Offshore Brazil Research Articles

Elastic properties of rock salt in the Santos Basin: Relations and spatial predictions

Most subsurface rock models consider salt bodies as homogenous masses and set to evaporite minerals constant values of elastic properties such as density, compressional and shear velocities, Young's modulus and Poisson's ratio. Lithological analyzes of outcrops and wells indicate that evaporites present large vertical and lateral heterogeneities. Recent studies have demonstrated that the knowledge of the elastic properties of rock salt can substantially benefit velocity modeling, seismic imaging, reservoir geomechanical analysis, prediction of wellbore stability and calculation of optimum fluid weight. However, few papers document the spatial estimation of elastic properties for salt formations. We propose an approach to characterize the internal structures of the salt bodies in the Santos Basin, offshore Brazil, using well and 3D seismic data. It starts with a rock-physics analysis at well-log scale, which reveals that the elastic properties of rock salt are highly correlated. Once the relationships of the elastic properties are established, we explore the functionality of the empirical equations as property predictors. We demonstrate that the elastic properties can be empirically estimated from compressional velocity. The comparison between the estimated and the measured well logs validates the estimation. Then, we perform the seismic inversion to generate the spatial distribution of the acoustic impedance. We derive compressional and shear velocities, density, Young's modulus and Poisson's ratio volumes by applying the empirical equations to the acoustic impedance volume. The blind well points out that, through this workflow, the seismic data can successfully predict the elastic properties of the salt formation in undrilled portions.

Relationship between geoacoustic properties and chemical content of submarine polymetallic crusts from offshore Brazil

Marine mining is the ocean’s new exploration frontier, and polymetallic crusts (PMCs) and ferromanganese nodules are considered a strategic resource for the future. Acoustic geophysical methods are a valuable tool for oceanic research and have been employed for several decades in the exploration of marine resources and environmental evaluations. The main objective of this work was to investigate the correlation between the chemical composition of PMCs from three different areas along the Brazilian continental margin and their physico-acoustic attributes (P-wave velocity, density and acoustic impedance). The results show that the geoacoustic properties of PMCs are correlated to their chemical composition. Measurements showed positive and negative trends between acoustic impedance and studied elements (Fe, Mn, Co, Cu, Zn, W and Ni) according to the direction of measurement, indicting high anisotropy levels. Our study sheds initial light on the correlation between acoustic properties and metal content of PMCs. The study facilitates assessments of the acoustic responses of PMCs allowing more efficient prospection and exploitation compared to ship-board geophysical techniques that are too qualitative to identify PMCs. The results can contribute to determining the best procedures and techniques for more efficient future exploration of this resource.

Unsupervised seismic facies classification applied to a presalt carbonate reservoir, Santos Basin, offshore Brazil

Mapping of seismic and lithological facies is a very complex process, especially in regions with low seismic resolution caused by extensive salt layers, even when only an exploratory view of the distribution of the reservoir facies is required. The aim of this study was to apply multi-attribute analysis using an unsupervised classification algorithm to map the carbonate facies of an exploratory presalt area located in the Outer high region of the Santos Basin. The interval of interest is the Barra Velha Formation, deposited during the Aptian, which represents an intercalation of travertines, stromatolites, grainstones and spherulitic packstones, mudstones, and authigenic shales, which were deposited under hypersaline lacustrine conditions during the sag phase. A set of seismic attributes, calculated from a poststack seismic amplitude volume, was used to characterize geological and structural features of the study area. We applied k-means clustering in an approach for unsupervised seismic facies classification. Our results show that at least three seismic facies can be differentiated, representing associations of buildup lithologies, aggradational or progradational carbonate platforms, and debris facies. We quantitatively evaluated the seismic facies against petrophysical properties (porosity and permeability) from available well logs. Seismic patterns associated with the lithologies helped identify new exploration targets.

E&P Notes (April 2019)

E&P Notes (April 2019)

Long-wavelength FWI updates in the presence of cycle skipping

Full-waveform inversion (FWI) has become the tool of choice for building high-resolution velocity models. Its success depends on producing seamless updates of the short- and long-wavelength model features while avoiding cycle skipping. Classic FWI implementations use the L2 norm to measure the data misfit in combination with a gradient computed by a crosscorrelation imaging condition of the source and residual wavefields. The algorithm risks converging to an inaccurate result if the data lack low frequencies and/or the initial model is far from the true one. Additionally, the model updates may display a reflectivity imprint before the long-wavelength features of the model are fully recovered. We propose a new solution to this fundamental challenge by combining the quadratic form of the Wasserstein distance (W2 norm) for measuring the data misfit with a robust implementation of a velocity gradient. The W2 norm reduces the risk of cycle skipping, whereas the velocity gradient effectively eliminates the reflectivity imprint and emphasizes the long-wavelength model updates. We illustrate the performance of the new solution on a field survey acquired offshore Brazil. We demonstrate how FWI successfully updates the earth model and resolves a high-velocity carbonate section missing from the initial velocity model.

Deposition, diagenetic and hydrothermal processes in the Aptian Pre-Salt lacustrine carbonate reservoirs of the northern Campos Basin, offshore Brazil

The discovery of large oil accumulations in the rift and sag Pre-Salt sections of the Campos and Santos Basins has revived interest in the exploration of the lacustrine carbonate reservoirs in the Brazilian and African marginal basins. More than half of Brazilian oil production originates from the Pre-Salt reservoirs of these offshore basins. A study integrating systematic petrography, cathodoluminescence, scanning electron microscopy, microprobe and X-ray diffraction was performed on seven wells in the northern Campos Basin. This study highlights the major primary, diagenetic and hydrothermal features of the Pre-Salt succession, with the aim to improve our understanding of the factors that influence the porosity and permeability distribution in these important lacustrine carbonate reservoirs. The Pre-Salt deposits correspond to bioclastic grainstones and rudstones, syngenetic crusts of fascicular calcite, and intraclastic grainstones and rudstones of reworked crust fragments and calcite spherulites. Magnesian silicates are frequently associated with carbonate deposits. In the sag phase, stevensitic laminations constitute the substrate for the precipitation of calcite crusts and spherulites, which displace and replace the syngenetic magnesian clay deposits. In the rift section, stevensitic ooids are mixed with bioclasts or form ooidal arenites. Pre-Salt carbonate reservoirs have undergone a complex and heterogeneous diagenetic evolution. Eodiagenetic processes include the dissolution, neomorphism and cementation of bivalve bioclasts in the rift, as well as the dissolution of magnesian silicates and their replacement by calcite spherulites, silica and dolomite in the sag section. Burial alterations are commonly associated with hydrothermal fluids carried through faults and fracture systems. These fluids promote dolomitization, silicification, and dissolution at varying degrees and intensities. Eodiagenetic precipitation and dissolution owing to variations in the lake water chemistry and the episodic flow of hydrothermal fluids under burial conditions control the creation, redistribution, and obliteration of porosity in the Pre-Salt reservoirs.

Optimal design and scheduling for offshore oil-field development

Oil-and-gas field development projects are capital-intensive, and optimizing profitability has always been a critical subject for the industry. This paper presents a mixed-integer linear programming (MILP) model to facilitate scenario comparison and selection at the design stage for green offshore oil-field development. The model solves an allocation-scheduling problem with the objective of maximizing the project’s net present value (NPV). Decision variables include the drilling schedule for both production and injection wells, well assignment to FPSO (floating, production, storage and offloading unit), FPSO oil and water production capacity, and water injection capacity. The model represents the waterflood scheme through an injection-production relationship matrix, leading to consistent scheduling of producer-injector pairs. Also, the model allows the assignment of development priorities to blocks or well groups, which corresponds to the “phased-development” concept in real-world application. Methods to estimate production rates are proposed, and a production prediction model is established. Production rates considering scheduling effect are generated by a linear superposition of base production curves from reservoir simulations. Two synthetic reservoirs with properties resembling deepwater offshore Brazil illustrated the performance of the modeling approach. It is observed that in early development years, drilling capacity and oil production capacity are active constraints to the system, while in late development years, active constraints change to water capacity, which propels the “capacity expansion” concept in the late production years, such as subsea water separation. Higher recovery is obtained with expedited production, but NPV does not necessarily increase with increased oil recovery when there is considerable investment on extra FPSOs.

Introduction to this special section: Case studies: Conventionals

Case studies, with a focus on conventional systems, provide insight of seismic and well data sets in terms of characterizing reservoirs with innovative techniques and approaches. This special section contains three such papers from three different regions: offshore Brazil, the North Sea, and the Middle East. Each contribution presents a different geologic problem ranging from siliciclastics to volcanics to carbonates. The challenges faced in each paper were tackled using innovative approaches to reservoir characterization in complex geologic regions.

3D controlled-source electromagnetic imaging of gas hydrates: Insights from the Pelotas Basin offshore Brazil

Mapping of natural gas hydrate systems has been performed successfully in the past using the controlled-source electromagnetic (CSEM) method. This method relies on differentiating resistive highly saturated free gas or hydrate-bearing host sediment from a less resistive low-saturated gas or brine-bearing host sediments. Knowledge of the lateral extent and resistivity variations (and hence the saturation variations) within sediments that host hydrates is crucial to be able to accurately quantify the presence of saturated gas hydrates. A 3D CSEM survey (PUCRS14) was acquired in 2014 in the Pelotas Basin offshore Brazil, with hydrate resistivity mapping as the main objective. The survey was acquired within the context of the CONEGAS research project, which investigated the origin and distribution of gas hydrate deposits in the Pelotas Basin. We have inverted the acquired data using a proprietary 3D CSEM anisotropic inversion algorithm. Inversion was purely CSEM data driven, and we did not include any a priori information in the process. Prior to CSEM, interpretation of near-surface geophysical data including 2D seismic, sub-bottom profiler, and multibeam bathymetry data indicated possible presence of gas hydrates within features identified such as faults, chimneys, and seeps leading to pockmarks, along the bottom simulating reflector and within the gas hydrate stability zone. Upon integration of the same with CSEM-derived resistivity volume, the interpretation revealed excellent spatial correlation with many of these features. The interpretation further revealed new features with possible hydrate presence, which were previously overlooked due to a lack of a clear seismic and/or multibeam backscatter signature. In addition, features that were previously mapped as gas hydrate bearing had to be reinterpreted as residual or low-saturated gas/hydrate features, due to the lack of significant resistivity response associated with them. Furthermore, we used the inverted resistivity volume to derive the saturation volume of the subsurface using Archie’s equation.

Diagenesis and its impact on a microbially derived carbonate reservoir from the Middle Triassic Leikoupo Formation, Sichuan Basin, China

The uppermost Middle Triassic Leikoupo Formation in the western Sichuan Basin of China has recently been shown to host as much as 5.3 tcf (1.5 × 1012 m3) of natural gas resources. The reservoir rocks, composed mainly of microbially derived dolomudstone (e.g., thrombolites and stromatolites), are characterized by low porosity (<8%) and permeability (<0.001 to 10 md). The limestone is commonly tight and not of reservoir quality because of abundant meteoric calcite cementation, whereas the dolostone has various types of pores dominated by solution-enlarged pores and vugs, microbial framework pores, and micropores. Breccias are well developed in places, probably because of dissolution of underlying evaporites (e.g., anhydrite) by an influx of low-salinity fluids (e.g., freshwater and seawater) during an early burial stage. Early dolomitization created micropores in the dolomudstone, and subsequent diagenetic events were dominated by calcite, dolomite, quartz cementation, pyrite replacement, compaction, fracturing, and development of stylolites. Localized hydrothermal activity has been evidenced by high homogenization temperatures (∼160°C–200°C) obtained from fluid inclusions in fracture-filling cements. Bacterial sulfate reduction probably resulted in H2S generation, pyrite precipitation, and solution-enlarged pore and vug formation, whereas part of the current H2S in these reservoirs may have been sourced from thermochemical sulfate reduction or an underlying formation (e.g., the Feixiangguan Formation). Development of microfractures and associated micropores was probably the final diagenetic event, which improved pore interconnectivity. This study confirms the effect of diagenesis on the development of a microbial dolomudstone reservoir, which may be applicable to other similar microbial carbonate reservoirs elsewhere, for example, Middle Triassic sections of the Tethys region and offshore Brazil.

An approach for three-dimensional quantitative carbonate reservoir characterization in the Pampo field, Campos Basin, offshore Brazil

In carbonate rock reservoirs, spatial distribution models and elastic properties are complex because of diagenetic processes and mineralogical composition, which together directly interfere with variations in pore shape and interconnectivity. The main objective of this paper is to propose a workflow to aid in three-dimensional quantitative carbonate reservoir characterization of the Quissama Formation (Macae Group) in the Pampo field of the Campos Basin, offshore Brazil. Model-based seismic inversion, sequential Gaussian simulation with cokriging for porosity modeling, and truncated Gaussian simulation with trend for facies modeling were used to characterize the carbonate reservoirs. Our results show that the carbonate platform is located between the upper Aptian and lower Albian seismic surfaces. Interpretation of a new surface, called the intra-Albian, was possible via acoustic-impedance (AI) analysis. Our workflow facilitated identification of low AI, high porosity, and best facies areas in structural highs where the most productive wells have been drilled. Facies modeling suggests that intercalation of facies with high and low porosities is connected to shallowing-upward cycles. Finally, several debris facies with low AI and high porosities were identified in an area that could be targeted for new exploration.

A detailed look at diapir piercement onto the ocean floor: New evidence from Santos Basin, offshore Brazil

Diapir piercement through the ocean floor marks the final stages of a dynamic migration path. Once exhumed, a diapir extrudes from the seafloor, placing an obstacle for the flow of ocean bottom currents. While the hydrodynamic response of the flow has been previously studied, the detailed depositional and weathering modifications involved in the piercement process are less understood. To bridge this gap, we gathered already available multibeam bathymetric data, multichannel 2D seismic reflection profiles and collected new single-channel CHIRP profiles, Acoustic Doppler Current Profiler data and sediment samples across Santos Basin, offshore Brazil. In this region, the processes connecting the uppermost subsurface with the lowermost section of the water column are unknown. Data show three main stages of diapir exhumation: pre-, syn- and post-piercement into the seafloor. Extensional faults crown the pre-exposed diapir, before its piercement through the seafloor. Ocean bottom currents rework the top of the faults to form elongated depressions. The bottom currents tightly detour the diapir during and after its exposure at the seafloor. This interaction forms a drift and moat contourite depositional pattern. Our high-resolution data allow relating these morphologies to seafloor processes and distinguishing them from other reflector geometries related to diapir flank deformation, such as outward dipping of reflections. We further use this geometrical distinction to suggest a key for interpreting the exposure versus burial history of other diapirs worldwide.

Strengths and Weaknesses Guide Choice of Brazilian Subsea-Development Options

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 28051, “Subsea Concept Alternatives for Brazilian Presalt Fields,” by Kevin Buckley and Ricardo Uehara, Shell, prepared for the 2017 Offshore Technology Conference Brasil, Rio de Janeiro, 24–26 October. The paper has not been peer reviewed. Copyright 2017 Offshore Technology Conference. Reproduced by permission. This paper identifies and compares four subsea-development concepts for typical Brazilian presalt deepwater applications on the basis of generic system functional requirements; the strength, weakness, opportunity, and threat analysis method (SWOT); and comparative cost/benefit analysis. The paper provides a fast-track approach to perform screening assessment of multiple subsea concepts. Introduction Subsea development concepts for presalt regions such as those offshore Brazil have followed a replication methodology primarily based on a satellite configuration with flexible risers and flowlines. While this concept has several strengths, the associated scope of the operation incurs considerable cost. This concept, in addition to three others, is outlined in this paper. The concepts discussed include the following: Satellite configuration with flexible risers and flowlines Daisy-chain configuration with rigid risers and flowlines Cluster configuration with manifolds, rigid risers, flowlines, and flexible jumpers Hybrid solutions with rigid risers and flexible flowlines (with and without manifolds) The objective of this paper is not to select the best option; rather, it is to discuss these options on the basis of application, objectives, premises, and field characteristics. Common characteristics of the Brazilian presalt fields are provided in the complete paper, and its Fig. 13 summarizes the SWOT analysis for all four concepts. Satellite Configuration In this configuration, each well is connected directly to the host by two dedicated flowlines/risers: The production well has one production and one service flowline/riser, while the injection well has one gas-injection and one water-injection flowline/riser. Each well has an umbilical connected directly to the host. Thus, each tree has three connection modules located on the tubinghead spool (THS), one for each flowline and one for the umbilical. A pigging loop inside the THS allows for fluid displacement, double-sided depressurization, and round-trip pigging of the flowlines. The subsea-controls system is multiplexed, with a subsea-control module on each tree. Strengths. Flexibility to position the wellhead on the seabed Independent well control from topsides Standardization of subsea systems Installation of flexible flowlines and risers can be faster and cheaper than the installation of rigid pipes Weaknesses. High number of flowlines and risers (two per well) Use of flexible lines is at the edge of technology for these materials for presalt conditions, so qualification is required Limited inner diameter (ID) Opportunities. Reduce the number of risers Use free-hang catenary risers instead of lazy-wave risers Incorporate subsurface data to define well location in the reservoir as late as possible Threats. Because the subsea system is not modular, interventions tend to increase operating costs A lack of multiple vendors capable of delivering the necessary scope of the operation

The equivalent pore aspect ratio as a tool for pore type prediction in carbonate reservoirs

The equivalent pore aspect ratio provides a tool to detect pore types by combining compressional and shear wave velocities, porosity, bulk density, and mineralogical composition of carbonate rocks. The integration of laboratory measurements, well logs, and petrographic analysis of carbonate rocks from various depositional and diagenetic settings (Lower Cretaceous presalt nonmarine carbonates from offshore Brazil; Lower Cretaceous shallow-water platform carbonates from southeast France; and Upper Cretaceous deep-water carbonate from the Gargano Peninsula, Italy) allowed the acoustic signature of a wide range of pore types to be quantified. The equivalent pore aspect ratios are shown to be independent of pore volume and mineralogy. They can, therefore, be regarded as relevant parameters for discriminating selected pore network architectures in carbonate reservoirs. Interparticle and intercrystalline microporosity and macroporosity may include a variety of distinct pore network structures and a wide range of acoustic signatures depending on particle shape, nature of contacts, packing, and cementation (intergranular macroporosity in a densely packed granular sediment, secondary pseudofenestral, etc.). The acoustic response of moldic pores appears to be mainly controlled by the shape of the dissolved allochems. The present work reveals also that correct pore type detection from acoustic and porosity measurements is highly dependent on the pore type classification used. A selection of petrographic and diagenetic features to be considered for the construction of a suitable pore type classification is proposed to improve the detection of the pore type effect on the acoustic properties of carbonate reservoirs at plug and well log scale.

How, where, and when do radial faults grow near salt diapirs?

We examine 3-D seismic reflection data from the Santos Basin, offshore Brazil to determine how, where and when do radial faults grow near a sub-circular salt diapir (stock). We show roof stretching alone cannot account for the large heights and lengths of the kilometre-scale radial faults, suggesting stock widening (‘stem push’), a mechanism implied in numerical models but not yet documented in natural examples, played a pivotal role in radial fault formation. We suggest that, when a diapir is covered by a roof, radial faults form in its overburden due to roof stretching, extending no further than the limit of the drape folding. The roof may then be shouldered aside and the faults buried along the stock flanks, exposing these strata to stem push-related stresses that may then reactivate pre-existing or form new radial faults. Radial faults, irrespective of how they formed, may dip-link with or offset one-another as salt continues to rise. We suggest the causal mechanism for radial fault formation will likely change as roof thickness varies during diapirism, with this reflecting the ratio between sedimentation rate and salt volumetric flux. Our findings are likely applicable to other diapirs, helping us not only to interpret the paleo-stress state of salt-bearing sedimentary basins, but also advancing our understanding of fracture distributions, potential fluid flow pathways, and reservoir compartmentalization around salt diapirs in basins where seismic reflection imaging is poor.

Hole Cleaning, Torque Management Lead to Longest Extended-Reach Well in Brazil

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper OTC 28091, “The Longest Horizontal Section Ever Drilled in an Extended-Reach Well in Brazil,” by Rafael Kenupp, Affonso Lourenço, Stian Soltvedt, and Ian Thomson, Baker Hughes, a GE company, and Grazielli Simoes, Daniela L. Morosov, and Raquel Andrade, Statoil, prepared for the 2017 Offshore Technology Conference Brasil, Rio de Janeiro, 24–26 October. The paper has not been peer reviewed. Copyright 2017 Offshore Technology Conference. Reproduced by permission. The Peregrino project, located in the post-salt zone of the Campos Basin, presents immense challenges for drilling extended-reach wells. This paper shares challenges imposed by the well profile and downhole environment on the design and execution phases. Information is included about the solutions used that led to reaching the target depth as planned, including the well-planning methodology, bottomhole-assembly (BHA) design, drill-bit selection, data monitoring, and procedures for maximizing the transfer of power downhole and minimizing rock-cutting energy. Introduction The Peregrino oil field is in the BM-C-7 area of the Campos Basin. Of 47 wells drilled from two fixed platforms in the field (Peregrino A and B), 20 were from Peregrino A, where the longest horizontal sections have been drilled. The average horizontal length was 1419 m, and the operator is pushing the technical limits to extend the overall lateral stepout, increase reservoir lengths, and maximize hydrocarbon exposure. Drilling horizontal sections beyond the field average length has several additional challenges including mud quality along the sections, high friction factors, and surface-equipment operational limits. For extended-reach wells, hole-cleaning efficiency and proper torque management have been shown to be key factors for flawless execution. Proposed Approach Considering the typical well setup in off-shore Brazil, Well A-27 had a considerable total length. The planned length of the well was 8400-m measured depth (MD), with a possible extension to 8740-m MD. The landing of a 9⅝-in.-casing shoe was planned to be at 6520-m MD with approximately 82° of inclination, and the 8½-in.-section lateral displacement was to start at 5673 m from the wellhead (Fig. 1). With a possible horizontal section of 2220 m, a rotary-steerable system was to be used, with the addition of a drilling dynamics sub and a modular motor, to reduce the demanded weight on bit (WOB) and surface rate of revolution while maintaining sufficient energy at the bit. Management of torque and equivalent circulating density (ECD) would be helped by the use of 4-in. drill-pipe, which would also provide lower torque values with less cross-sectional area. The final measure required to reduce overall friction along the horizontal well path was to add lubricant to the drilling fluid to reduce metal-to-metal friction at the drillpipe/casing interaction. Lubricant was also to be added while drilling, with the idea that drops of lubricant deposited into the mudcake would help reduce friction when drill-pipe tool joints pass through.

Comments: Offshore Makes a Comeback

Editor's column All eyes in the upstream continue to be on the growth in unconventional production, particularly in the US. But the offshore arena may be making a quiet comeback, at least in the near term. The US Gulf of Mexico, North Sea, Latin America, and other spots have seen renewed interest of late, as operators enforce capital discipline to make these expensive projects feasible given the current price climate. Many offshore megaprojects were cut or scaled back when oil prices began to drop sharply in 2014 and, while global offshore output has been steady, it has not grabbed the head-lines that surging shale production has. World offshore output has remained about 27 million B/D over the past decade. US Gulf of Mexico production, which is rising, made up a quarter of US output in the early 2000s but captures only 16% of the total now with the rise in unconventionals. US Gulf of Mexico production in 2017 rose to 1.65 million B/D, the highest annual level on record, according to the US Energy Information Administration (EIA). It is expected to increase this year and in 2019, maintaining record highs. Output will creep to 1.7 million B/D in 2018 and then to 1.8 million B/D in 2018, according to the EIA. This is due mainly to projects that were sanctioned before the price downturn and went forward in 2016 and 2017. The EIA says that seven deepwater fields will start production this year and another three will start up the following year. Shell will begin production from three fields over the period—Gotcha, Rydberg, and Kaikias. Hess and LLOG both will start up two fields, and Stone Energy and Apache will bring one field each online. An offshore auction by the US government in March, the largest for drilling prospects off the US Gulf Coast in history, attracted only modest interest from operators, proving that they are still wary of market conditions. The bidding was for 77 million acres of deep- and shallow-water tracts. Interest offshore Mexico and Brazil remains high. Brazil’s offshore auction in late March brought winning bids from ExxonMobil, Wintershall, Chevron, Shell, BP, Statoil, and Qatar Petroleum. Several operators said their break-even price for offshore projects is now under $50/bbl, well below where prices were trading in mid-April. The success of Brazil’s auction was not only because of rising oil prices and better capital discipline among operators, but also changes in Brazil regulatory laws that made the projects more attractive. That followed a deepwater auction in Mexico earlier this year that saw aggressive winning bids from Shell, which snatched up nine blocks, as well as Petronas and Qatar Petroleum. But offshore production will not catch US onshore output, which continues to outpace expectations despite fears of infrastructure bottlenecks and people shortages. Total US production will reach 11 million B/D this year, a whole year earlier than projected in March, the EIA said in April. Output is averaging 10.2 million B/D so far this year. The EIA expects US production to reach 11.18 million B/D next year.

Entrainment and abrasion of megaclasts during submarine landsliding and their impact on flow behaviour

Abstract Many mass transport complexes (MTCs) contain up to kilometre-scale (mega)clasts encased in a debritic matrix. Although many megaclasts are sourced from the headwall areas, the irregular basal shear surfaces of many MTCs indicate that megaclast entrainment during the passage of flows into the deeper basin is also common. However, the mechanisms responsible for the entrainment of large blocks of substrate, and their influence on the longitudinal behaviour of the associated flows, have not been widely considered. We present examples of megaclasts from exhumed MTCs (the Neuquén Basin, Argentina and the Karoo Basin, South Africa) and MTCs imaged in three-dimensional seismic reflection data (Magdalena Fan, offshore Colombia and Santos Basin, offshore Brazil) to investigate these process–product interactions. We show that highly sheared basal surfaces are well developed in distal locations, sometimes extending beyond their associated deposit. This points to deformation and weakening of the substrate ahead of the flow, suggesting that preconditioning of the substrate by distributed shear ahead of, and to the side of, a mass flow could result in the entrainment of large fragments. An improved understanding of the interactions between flow evolution, seabed topography, and the entrainment and abrasion of megaclasts will help to refine estimates of run-out distances, and therefore the geohazard potential of submarine landslides.

FACIES HETEROGENEITIES IN A RAMP CARBONATE RESERVOIR ANALOGUE: A NEW HIGH‐RESOLUTION APPROACH FOR 3D FACIES MODELLING

In contrast to the conventional view that facies distribution patterns on carbonate ramps are relatively simple, outcrop analogue studies point to a high degree of internal facies complexity. Depending on the diagenetic overprint, this complex pattern may result in reservoir compartmentalization due to the presence of interflow baffles. The often subseismic scale heterogeneities may not be included in conventional reservoir modelling. In order to evaluate how facies heterogeneities in shoal reservoirs can be modelled realistically, this paper presents a facies modelling workflow which includes a new approach to the design of training images for multiple‐point statistics (MPS). The workflow was developed in the course of a reservoir outcrop analogue study of a Ladinian (Middle Triassic) coquinadominated shoal complex in SW Germany which was deposited on an epicontinental, gently inclined carbonate ramp. The data set was based on an intensive field study and includes 3D facies and sequence stratigraphic analyses of the largest shoal complex in the Quaderkalk Formation (Upper Muschelkalk). This several metre thick shoal complex represents a subseismic scale, bioclast‐rich reservoir analogue and has a very heterogeneous facies pattern.Integrating 1D facies logs and sequence stratigraphic trends from tens of outcrop sections and cores, two nested 3D geocellular facies models were produced: (i) a large‐scale (30 × 30 km) model based on truncated Gaussian simulation (TGS); this formed the basis for (ii) a smaller‐scale (10 × 10 km), more detailed model based on multiple point statistics. In addition, a new approach for training image design was developed to honour small‐scale sequence stratigraphic trends and lateral facies patterns observed in modern analogues. Compared to facies patterns in modern analogues, the large‐scale model presents geologically‐feasible facies distribution patterns and geometries, and in addition shows a vertical facies distribution which is similar to the observed sequence stratigraphic architecture of the outcrop data‐set used. Due to the new training image design, the final small‐scale model has a distribution pattern of facies heterogeneities which looks similar to modern facies distributions in the offshore UAE and thus represents a valuable method of producing realistic reservoir facies models.The modelling workflow and the new approach for training image design presented will help to reduce uncertainties in the understanding and modelling of subsurface reservoirs by using a systematic combination of outcrop data and modern analogues, with the consistent application of sequence stratigraphic principles. In addition, this study emphasises the importance of careful training image design, derived from modern analogues, which can be used as realistic inputs in order to optimize multiple point simulations, and which may be applied to producing bioclastic reservoirs such as those located on the Arabian Plate or offshore Brazil.

Dual tectonic-climatic controls on salt giant deposition in the Santos Basin, offshore Brazil

Dual tectonic-climatic controls on salt giant deposition in the Santos Basin, offshore Brazil