Turbidite Reservoirs Research Articles

The mathematical model of stress sensitivities on tight reservoirs of different sedimentary rocks and its application

In this paper, five types of sedimentary rocks (the Turbidite, the Beach bar sand, the Glutenite and the two outcrop cores) with permeability (k，10−3μm2) grades (k < 0.1, 0.1＜k ≤ 0.3, 0.3＜k ≤ 0.5, 0.5＜k ≤ 1.0, 1.0＜k ≤ 3.0) are studied for the building of the model. The uniaxial compression tests, the stress sensitivity tests, and the CT structure scanning have been done, then the data and the curves obtained from the lab are carefully analyzed and examined. Studies on the grain sizes, the components ratios of the different grains, and the original pore structures are conducted in order to get the stress sensitivities of the rocks. Those of the Glutenite, the Turbidite and the Beach bar sand with the same permeability level (k ≤ 0.1 × 10−3μm2) are found having the order of stress sensitivity from high to low, and the maximum drops of permeability is range from 20.8% to 30.7%. Based on the experiment results, combined with the unequal diameter tortuous capillary bundle model and the contact deformation theory of Hertz, a mathematical model on stress sensitivities of tight reservoirs is established, which takes the characteristic parameters (Young's moduli, Poisson's ratios) of the reservoir rock materials, the pore structure parameters (the pore radii, the throat radii), and the macro physical parameters (the original permeability values) into account. The calculation error of the model is 2.6%. Finally, taking the actual data of the tight reservoirs in Jiyang Depression of Bohai Bay Basin as an example, this model is introduced into productivity equation to predict the production under the different formation pressures. It is suggested that the formation energy retention rate of the Glutenite reservoir to be above 0.9, the Turbidite reservoir above 0.85, and the Beach bar sand reservoir above 0.78.

A new approach to improve reservoir modeling via machine learning

In highly heterogeneous basins with complex subsurface geology, such as the Nile Delta Basin, accurate prediction of reservoir modeling has been a challenge. Reservoir modeling is a continuous process that begins with field discovery and ends with the last phases of production and abandonment. Currently, the stochastic reservoir modeling method is widely used instead of the traditional deterministic modeling method to consider spatial statistics and uncertainties. However, the modeling workflow is demanding and slow, typically requiring months from the initial model concept to flow simulation. In addition, errors from early model stages become cumulative and are difficult to change retroactively. To overcome these limitations, a new workflow is proposed that implements probabilistic neural network inversion to predict reservoir properties. First, well-log data were conditioned properly to match the seismic data scale. Then, the networks were trained and validated, using the conditioned well-log data and seismic internal/external attributes, to predict water saturation and effective porosity 3D volumes. The resulting volumes were sampled in simulation 3D grids and tested using a blind well test. Subsequently, the permeability was calculated from a porosity-permeability relationship inside the reservoir. Finally, a dynamic simulation project of the field was performed in which the historical field production and pressures were compared to the predicted values. One of the Pliocene deepwater turbidite reservoirs in the offshore Nile Delta was used to demonstrate the proposed approach. The results proved the accuracy of the model in predicting the reservoir properties and honoring the heterogeneity of the reservoir. The new approach represents a shortcut for the seismic-to-simulation process, providing a reliable and fast way of constructing a reservoir model and making the seismic-to-simulation process easier.

Seismic stratigraphic patterns and characterization of deepwater reservoirs of the Mundaú sub-basin, Brazilian Equatorial Margin

Abstract In recent years, the Brazilian Equatorial Margin has drawn attention due to its similarity to areas with new hydrocarbon discoveries in the African conjugated margin, and in French Guiana. However, studies on the tectonic regimes associated with transform margins and their evolution, structures, and petroleum potential are still lacking due to the geological complexity of this region. To address this knowledge gap, research has been done to better understand the geological structures, as well as to identify potential hydrocarbon accumulations in the deepwater Ceara Basin. To achieve this, we performed an integrated interpretation of a large 2D seismic data, new exploratory borehole data, as well as older well data with revised biostratigraphy. This data analysis refines the basin architecture and the Cretaceous-Paleocene tectonic evolution, including implications for hydrocarbon prospectivity in the Ceara Basin deepwater. 2D seismic interpretation was performed using modern concepts of continental break-up. To accomplish this, the transition of continental-oceanic crust was taken into account for restoration of the sediments of the rift stage in the basin. The analysis also identifies potential hydrocarbon accumulations in turbiditic reservoirs and presents new insights about the dimensions of the underlying rift features situated in the continental slope. The results reveal a high potential for drift sequences in deepwater where the Late Albian-Early Cenomanian-Turonian sediments reach thicknesses of approximately 3048–4894 m. Moreover, this research shows evidence of Cretaceous to Paleocene magmatism, indicated by the well-imaged volcanoes and associated sills in the seismic data. This analysis indicates that the Mundau sub-basin can be classified as a volcanic passive margin that was developed during the oblique dextral separation between South America and Africa. The variety of stratigraphic and structural features developed through the Cretaceous history of the Mundau sub-basin offers a variety of potential hydrocarbon traps and plays in a number of rift and post-rift sequences.

Effects of far-field boundary conditions on the simulation of hydrate production

The world’s first offshore methane hydrate extraction was conducted in 2013 at the Daini-Atsumi Knoll located in the eastern Nankai Trough. The results indicated that the gas production rate of a single vertical well cannot meet the requirement for commercialisation of methane hydrate production. Therefore, a trial multi-well system has been considered for future hydrate production. Understanding the ‘influence distance’ of extraction wells within methane hydrate turbidite reservoir formations, such as that of the Nankai Trough, is significant to the design of the proposed multi-well system. In this study, the boundary effects are examined for cases involving different values of permeability and initial hydrate saturation for the modelled turbidite formations. A relationship is proposed to predict the longest simulation time for a given set of lengths and parameters. The two concepts of critical production time (CPT) and turbidity/homogeneity coefficient ratio (THCR) are introduced to analyse the interaction between the effects of model size and heterogeneities. It is found that the CPT can be normalised by the radius of the model; the THCR is affected by the relative thickness of the sand and clay layers.

The Starling, Scoter and Merganser fields, Blocks 22/30a and 29/3a, UK North Sea

Abstract The Shearwater Field is located 242 km east of Aberdeen in the Central North Sea (CNS) and has three satellite fields, Starling, Scoter and Merganser. Acting as the hub for the gas-condensate-producing normal-pressure–normal-temperature (NPNT) satellites, Shearwater, which produces high-pressure–high-temperature (HPHT) Jurassic reservoirs, comprises a bridge-linked wellhead jacket to a production platform. The satellites, developed as subsea tiebacks, target Paleocene turbidite reservoirs, with the Starling Field most distant at 33 km from the host while Merganser is tied in via Scoter through a 15 km pipeline. Each satellite consists of a subsea manifold connected to two production wells at Merganser, and three production wells each at Scoter and Starling. All reservoir traps at the satellites are due to Permian-age Zechstein salt diapirs. Starling and Scoter produce Forties Sandstone Member reservoirs via three deviated wells targeting anticline structures. At Merganser, two long horizontal production wells cross over 4000 ft of faulted Paleocene reservoir intervals to produce under salt diapir overhangs. The satellites have been instrumental in maintaining the Shearwater facilities given early main field well failures, whilst recent challenges have developed as the satellites mature, requiring infill wells and well interventions to maximize economic recovery.

The Schiehallion and Loyal fields, Blocks 204/20, 204/25a, 204/25b, 205/16 and 205/21b, UK Atlantic Margin

Abstract The Schiehallion subsea development comprises two fields, Schiehallion and Loyal, which are located approximately 200 km to the west of the Shetland Islands in the UK Continental Shelf. The Schiehallion and Loyal fields were discovered in late 1993 and 1994, respectively, with a combined oil-in-place of more than 2.3 Bbbl. The fields are developed under waterflood and were on production from 1998 to 2013. After an extended shut-in, the fields were brought back on line in 2017, through new floating production facilities. Most of the production to date has been from the Paleocene Vaila Formation deep-water turbidite, in the T31 and T34 reservoir intervals. The ongoing Quad 204 redevelopment drilling programme commenced in April 2015, has drilled and completed 21 wells to date, and is expected to continue for several more years. The campaign includes new producer–injector pairs and stand-alone wells to support existing well stock, targeting stacked turbidite reservoir intervals, including the youngest T35–T34 interval, the main T31 interval and the previously under-developed T28–T25 fairway. In addition to an active drilling programme, a 4D seismic survey was acquired and processed in 2018, and its interpretation is key to unlocking further potential sources of value in this mature field.

The Buzzard Field, Blocks 19/5a, 19/10a, 20/1 and 20/6a, UK North Sea

Abstract The Buzzard Field remains the largest UK Continental Shelf oil discovery in the last 25 years. The field is located in the Outer Moray Firth of the North Sea and comprises stacked Upper Jurassic turbidite reservoirs of Late Kimmeridgian–Mid Volgian age, encased within Kimmeridge Clay Formation mudstones. The stratigraphic trap is produced by pinchout of the reservoir layers to the north, west and south. Production commenced in January 2007 and the field has subsequently produced 52% over the estimated reserves at commencement of development, surpassing initial performance expectations. Phase I drilling was completed in 2014 with 38 wells drilled from 36 platform slots. Platform drilling recommenced in 2018, followed in 2019 by Phase II drilling from a new northern manifold location. The evolution of the depositional model has been a key aspect of field development. Integration of production surveillance and dynamic data identified shortcomings in the appraisal depositional model. A sedimentological study based on core reinterpretation created an updated depositional model, which was then integrated with seismic and production data. The new depositional model is better able to explain non-uniform water sweep in the field resulting from a more complex sandbody architecture of stacked channels prograding over underlying lobes.

A complete workflow applied on an oil reservoir analogue to evaluate the ability of 4D seismics to anticipate the success of a chemical enhanced oil recovery process

In an Enhanced Oil Recovery (EOR) process, one of the main difficulties is to quickly evaluate if the injected chemical products actually improve oil recovery in the reservoir. The efficiency of the process can be monitored in the vicinity of wells, but it may take time to estimate it globally in the reservoir. The objective of this paper is to investigate the ability of 4D seismics to bridge this gap and to help predict the success or breakdown of a production strategy at reservoir scale. To that purpose, we consider a complete workflow for simulating realistic reservoir exploitation using chemical EOR and 4D seismic modeling. This workflow spans from geological description to seismic monitoring simulation and seismic attributes analysis, through geological and reservoir modeling. It is applied here on a realistic case study derived from an outcrop analog of turbiditic reservoirs, for which the efficiency of chemical EOR by polymer and surfactant injection is demonstrated. For this specific field monitoring application, the impact of both waterflooding and proposed EOR injection is visible on the computed seismics. However, EOR injection induces a more continuous water front that can be clearly visible on seismics. In this case, the EOR efficiency can thus be related to the continuity of the water front as seen on seismics. Nevertheless, in other cases, chemical EOR injections may have more moderate impacts, or the field properties may be less adapted to seismic monitoring. This points out the importance of the proposed workflow to check the relevance of seismic monitoring and to design the most adapted monitoring strategy. Numerous perspectives are proposed at the end of the paper. In particular, experts of the different disciplines involved in the proposed workflow can benefit from the availability of a complete set of well-controlled data of various types to test and improve their own tools. In contrast, the non-experts can easily and quickly benefit from “hands-on” experiments for understanding the involved phenomena. Furthermore, the proposed workflow can be directly applied to geological reservoirs all over the world.

Seismic sedimentology of lacustrine delta-fed turbidite systems: Implications for paleoenvironment reconstruction and reservoir prediction

Abstract The deltaic-turbidite systems are common features in continental lacustrine rift basins. In the Bohai Bay rift Basin, Eastern China, the turbidite sandstones are the critical targets for hydrocarbon production and development. However, their intricate sedimentary patterns and the small size of the reservoirs introduces more challenge for their understanding and prediction. Through seismic sedimentology workflow, 90°-phase adjustment, strata slicing, spectral decomposition, RGB color blending technique, and geobody extraction, 3D seismic data and wireline log information data are integrated to understand the historical evolution of delta-turbidite systems and predicting the spatial and temporal distribution of sandbodies of the Es3m sub-member in the Shahejie Formation, dongying depression. The study identifies two system tracts in the study area, transgressive and highstand system tracts, from seismic and wireline logs interpretation. We identified six fourth-order sequences within the highstand system tracts, each of which corresponds to a different period of deltas progradation. Stratal slicing mapping on multiple deposition surfaces reveals the high-resolution historical evolution of the delta-turbidite systems and the distribution of their associated sandbodies. Interpretation of slices shows six stages of deltas development, which led to widespread delta-fed turbidite reservoirs. Three multi-delta-turbidite systems: the northern fan-turbidite systems and the southeast-turbidite systems are documented, which evolved throughout all stages of delta development. Rapid progradation of multi-deltas systems played an essential role in the evolution and development of thin-bedded reservoirs in the HST. Faults and local topographic lows controlled the spatial distribution of sandbodies in the area. The individual sandbodies range from 4.48 km2 to 16.49 km2 in size, and they vertically superimposed from bottom to top. The classification scheme presented in this work shows a successful application in terms of paleoenvironmental reconstruction and reservoir prediction of the delta-fed turbidite systems, which can be applied to similar systems worldwide.

A review of producing fields inferred to have upslope stratigraphically trapped turbidite reservoirs: Trapping styles (pure and combined), pinch-out formation, and depositional setting

Siliciclastic turbidite systems that pinch out updip toward their proximal margin are prime targets for hydrocarbon exploration, especially in deep-water basins. Such “upslope stratigraphic traps” potentially offer large-volume discoveries but have significant geological risks, notably because of ineffective closure or containment. In the published literature, at least 20 fields from 11 basins globally with 6–7 billion BOE of cumulative discovered reserves have been inferred to be reliant on upslope pinchout traps. These fields are reviewed in terms of their interpreted trapping styles, pinch-out formation process, and depositional-tectonic setting. Reservoirs display a range of upslope trapping styles, including pure (depositional and erosional) stratigraphic pinch-outs and combined stratigraphic-structural traps. In one-third of cases, faulting appears intimately linked to updip trapping, either through offsetting slope feeder conduits or assisting pinch-out development, and in some cases, faulting may be the most important updip trapping element. Sediment bypass and erosion in proximal areas is the most common inferred pinch-out formation mechanism. Some reservoirs also demonstrate the ability of erosional truncation by mud-prone channels and mass transport deposits to form viable stratigraphic traps and seals. Encouragingly for exploration, robust pinchout traps occur in various tectonic settings on a variety of different slope types and positions along the slope profile. Most large-volume discoveries to date, however, are restricted to the toe-of-slope environment in graded passive margins or out-of-grade rift and transform margin settings. Insights into the nature and occurrence of upslope stratigraphic traps are important for future exploration, especially for evaluating new license areas and risking prospects.

Identifying flow units by FA-assisted SSOM—An example from the Eocene basin-floor-fan turbidite reservoirs in the Daluhu Oilfield, Dongying Depression, Bohai Bay Basin, China

Accurate identification of flow units is essential in oil and gas development. In this study, integrated core, log, and production data from the Eocene basin-floor-fan turbidite reservoir demonstrates a new method to identify flow unit using factor analysis (FA) and supervised-mode self-organizing-map neural network (SSOM). The reservoirs were classified into four types of flow units (I, II, III and IV). Five principal factors were extracted through factor analysis on thirteen evaluation parameters for reflecting the characteristics of basin-floor-fan turbidite reservoirs. Then using the five principal factors as the input, the flow unit prediction model was established based on SSOM. The prediction results of flow unit based on FA-SSOM are consistent with the results of core analysis and test oil conclusion, which have a good classification effect. Therefore, the prediction model based on FA and SSOM provides an effective way for fine reservoir interpretation. The established FA-SSOM model is further compared with Linear Discriminant Analysis (LDA) and Back Propagation (BP) neural network and has the best prediction. This study also sheds light on the remaining oil development by linking the identified flow unit type with daily production data.

Ultra-deepwater seismic plays offshore Brazil — Future drilling off Santos and Campos Basins

Contemporaneous seismic data acquisition in the Santos and Campos Basins offshore Brazil have focused on image characterization of deepwater and ultra-deepwater reservoirs and their relationship with hydrocarbons originating from synrift source rocks. Our interpretation has mapped the stratigraphy of postsalt turbidite reservoirs, and, on the presalt lithology, it has uncovered the underlying synrift sequences that embrace oil-bearing source rocks and the prolific, recently discovered, microbialite carbonate reservoirs. The new phase in geophysical data acquisition and offshore drilling that started in 1999 bolstered the Brazilian offshore petroleum production to record levels. The new, massive, nonexclusive, speculative 2D and 3D data acquisition surveys conducted offshore the Brazilian coast far exceed the amount of all existing cumulative vintage data. Deepwater drilling programs probed the interpreted new prospects. As whole, the modern geophysics data libraries offshore Brazil brought in the technology era to seismic interpretation, reservoir characterization, and geosteering operations in deepwater development drilling. Still, regional interpretation mapping of the outer shelf, slope, deepwater and ultra-deepwater provinces of the Santos and Campos Basins indicates plenty of prospective future drilling in the salt locked minibasins of the ultra-deepwater provinces. Salt tectonics shapes the architecture of these basins; hence, postsalt deepwater turbidite plays were readily interpreted from seismic amplitudes of the modern data that also allow for resolution images of the synrift source rocks, salt architecture, migration paths through faulting and salt windows, reservoir characterization, and regional seal mapping. The new techniques of prestack depth migration have enabled uncovering the imaging structure of the synrift that led to characterization of the presalt carbonate reservoirs and discovery of giant accumulations. Future offshore exploration will continue aiming at postsalt deepwater and ultra-deepwater minibasins plus presalt plays under the massive salt walls, still an underexplored frontier.

Quantitative architectural characteristics of deep-lake turbidites: Taking block 146 of Shinan Oilfield in Dongying Depression in China as an example

Abstract Taking He146 Development Unit of Shinan Oilfield in Dongying Depression as an example, the quantitative architectural model of turbidite reservoir is studied by using local dense well pattern and production performance data. The turbidites in the study area are mainly turbidite fans and turbidite channels. The area of a single turbidite-fan belt is 0.08–0.8 km2, with long-axis length of 162–900 m, width of 120–620 m, and thickness of 2–25 m. The scale of turbidite-fan belt is positively correlated with its thickness. The morphological parameters of turbidite-channel belts could be counted in logging and seismic data. The width of turbidite-channel belt is positively correlated with its thickness. Its thickness is 2.4–9.6 m, with an average of 6.3 m. The width of turbidite-channel belts is about 612–1212 m (estimated from seismic and logging profiles), with an average of about 884 m. The thickness of a single channel story is 1.5–5.8 m, the inclination angle of the bottom of the channel story is 0.9–2.4°, width of a channel stories is 120–450 m. The variation of channel-story thickness between two wells is fitted to a better linear function with the distance between wells in the cross section of channel stories. High production wells and corresponding injection wells are basically parallel or intersected with low angle to the extension direction of channel. The ideal projection distance is within 150 m, and the projection distance can exceed 150 m in the superimposed area of main body of turbidite-channel.

Marlim R3D: A realistic model for controlled-source electromagnetic simulations — Phase 2: The controlled-source electromagnetic data set

Synthetic data provided by geoelectric earth models are a powerful tool to evaluate a priori a controlled-source electromagnetic (CSEM) workflow effectiveness. Marlim R3D (MR3D) is an open-source complex and realistic geoelectric model for CSEM simulations of the postsalt turbiditic reservoirs at the Brazilian offshore margin. We have developed a 3D CSEM finite-difference time-domain forward study to generate the full-azimuth CSEM data set for the MR3D earth model. To that end, we fabricated a full-azimuth survey with 45 towlines striking the north–south and east–west directions over a total of 500 receivers evenly spaced at 1 km intervals along the rugged seafloor of the MR3D model. To correctly represent the thin, disconnected, and complex geometries of the studied reservoirs, we have built a finely discretized mesh of [Formula: see text] cells leading to a large mesh with a total of approximately 90 million cells. We computed the six electromagnetic field components (Ex, Ey, Ez, Hx, Hy, and Hz) at six frequencies in the range of 0.125–1.25 Hz. In our efforts to mimic noise in real CSEM data, we summed to the data a multiplicative noise with a 1% standard deviation. Both CSEM data sets (noise free and noise added), with inline and broadside geometries, are distributed for research or commercial use, under the Creative Common License, at the Zenodo platform.

Eocene-Oligocene syn-rift deposition in the northern Gulf of Tonkin, Vietnam

Abstract Reconstruction of non-marine syn-rift deposition in ancient basins is challenged by intense deformation, rapid lateral facies variation and limited biostratigraphic resolution. This affects petroleum resource assessments that relies on prediction of basin fill. The northern Gulf of Tonkin contains such non-marine-dominated rift system. The area is in an early stage of exploration. Depositional facies analysis based on all existing 2D seismic and well data suggests that Eocene-Oligocene deposition in grabens and half-grabens occurred in three steps. This resulted in formation of three successive packages, namely the rift initiation-, the rift development- and the rift termination succession. Rift initiation deposits are mainly composed by alluvial-fluvial strata deposited in segmented and often isolated grabens and half-grabens. As rifting progressed, faults joined and rift depressions merged into larger, coherent areas of deposition. Faulting peaked, which resulted in rapid creation of accommodation space, relief, and the development of deep lakes, alluvial fans and fan deltas. Elsewhere, floodplain, deltaic and shallow lake deposits comprise most of the rift development succession. As rift-subsidence declined, floodplain, deltaic and shallow lake deposits filled accommodation space and therefore dominate the rift termination succession. Structuring by strike-slip faulting and inversion complicates sequence stratigraphic analysis. Moreover, diachronic rift culmination caused the rift initiation, -development and -termination successions to vary laterally in age, further obscuring sequence stratigraphic analysis. Even so, tectonostratigraphic grouping into these three units allows a meaningful mapping of gross-depositional facies. The locally developed deep lake successions, potentially containing petroleum source rocks and seals, together with areas including potential deltaic, fan-delta, fluvial and turbidite reservoir sand suggest play types similar to those working in the Chinese part of the Beibuwan Basin. The most prospective areas are least explored suggesting an overlooked petroleum potential in the northern Gulf of Tonkin.

Simplified Dynamic Modeling of Faulted Turbidite Reservoirs: A Deep-Learning Approach to Recovery-Factor Forecasting for Exploration

Summary Faults are geological features that are essential in considering the development of hydrocarbon reservoirs. Significant resources (appraisal costs and manpower) are often deployed to locate them and assess their connectivity more accurately so that adequate investment decisions can be made. Early in a project's life, data might be sparse or the time that can be dedicated to data processing might be limited. An estimate of the impact of faults can be derived by considering the impact of analogous fault patterns in similar reservoir environments. A significant number of discoveries consist of channelized turbidite reservoirs draped over deepwater toe–thrust anticlines. To understand the effects of various fault patterns on the recovery factors of structurally complex turbidite reservoirs, we first perform extensive flow–simulation–based multidimensional sensitivity studies using realistic channelized stratigraphic architectures. Many of these reservoirs contain high–porosity, high–permeability channels, light oil, limited aquifer drive, and a limited number of fault populations. To constrain the potential impacts of the faults, a generic reservoir model was constructed and simulated with varying reservoir and fault properties. Because the input parameters are known (e.g., fault–zone thickness and permeability, shale–drape coverage, and oil viscosity), the relative importance of each variable can be quantified. The simulation results show that the impacts of the faults on reservoir performance vary systematically with the fault length and orientation, the undeformed–reservoir permeability, and the fault permeability. The recovery factors are relatively insensitive to fault–zone thickness, net/gross ratio, and porosity. The time–delay effect of the faults is significant in reservoirs with a permeability of approximately 100 md but not in darcy–quality reservoirs. In most fault scenarios, the recovery factors from simulations with high–permeability faults range from approximately 30% in 100–md reservoirs to approximately 45% in 3,000–md reservoirs, equivalent to 75 to 96% of the recovery factors of the unfaulted reservoirs. In comparison, assuming the most likely fault permeabilities, the recovery factors decrease to circa 20% in 100–md reservoirs and circa 41% in 3,000–md reservoirs, equivalent to 40 to 85% of the values in unfaulted reservoirs. To learn and predict the effects of faults on the recovery factor in a very fast and reasonably generic fashion in deepwater toe–thrust anticlines, we have developed an accurate deep–learning (DL) based surrogate model that predicts the structure connectivity factors as a function of recovery time. These factors are then used for discounting the recovery factors computed by simpler and easier–to–construct unfaulted models. The surrogate model is a very fast and advanced proxy for the multidimensional structure connectivity factor function and operates without resorting to any new flow simulation with a faulted model. We describe the novel DL architecture used for constructing the surrogate model and quantitatively prove its effectiveness. We finally demonstrate an example real–life application of the surrogate model on an exploration–stage prospect–ranking exercise.

Evaluation of consolidation parameter data trendings and comparison between prediction models for well-log velocities: A case study from the Namorado Oilfield (southern Brazil)

The compressional and shear-wave velocities (VP and VS) have been used in studies for hydrocarbon exploration over the last decades. Nevertheless, the absence of S-wave velocity records in geophysical surveys is common. In this work, we applied the iterative method proposed by Lee (2006), which allows evaluations of P- and S-wave velocities by estimates of the consolidation parameter α. We use well-log datasets from a turbiditic reservoir at Namorado Oilfield (Campos Basin, southeastern Brazil) to test this methodology. Results were further compared to a well-established empirical model (Greenberg and Castagna, 1992). We verified a good agreement for VS results provided by both methods, and a consistent correspondence between the measured VP and those calculated by the Lee (2006) method. It was also possible to assume the reliability of the α values, although the presence of denser lithologies may produce local artifacts, which affect VP(α) and VS(α) estimates. Furthermore, the results for α, VP(α) and VS(α) pointed to: (i) an upward trending for VPVS ratio values, for profile NA-01, that indicate a possible hydrocarbon-filling zone; (ii) the presence of two distinctive α data groupings with respect to porosity, which are clearly influenced by the involved type of lithologies; and (iii) the absence of a straightforward relationship between α and porosity under pressure conditions.

Determining permeability cut-off values for net pay study of a low-permeability clastic reservoir: A case study of the Dongying Sag, eastern China

Net pay cut-off values are key parameters in the evaluation of both conventional and unconventional reservoirs. However, there is no widely accepted method for determining net pay cut-off values. The low permeability turbidite reservoirs in the middle part of the third member of the Shahejie Formation (Es3z) in the Dongying Sag are taken as an example; the net pay permeability and porosity cut-off values are determined according to detailed core descriptions, thin section analyses, porosity and permeability test, mercury injection analyses, and well test data. Taking economic benefits into consideration, the concept of a net pay permeability cut-off value refers to the minimum permeability of a clastic reservoir that can produce hydrocarbons and meet the minimum economic benefits under the availability of existing technologies. The proposed methodology of this work is based on balancing the cost and income, and considers related parameters such as the cost of well drilling, investment in surface construction, operational cost, oil price, and oil production. The net pay permeability cut-off values of reservoirs with different thicknesses of development intervals are calculated based on the constraint of the oil price at $50/bbl. Then, the net pay porosity cut-off values are calculated following the pore-throat structure analyses. The proposed method and the net pay permeability and porosity cut-off values for the low permeability reservoirs in this article are acceptable since fit for purpose principle and data available principle have been considered. Meanwhile, this method enables the dynamic evaluation of reservoirs at any burial depth.

Oil production uncertainty assessment by predicting reservoir production curves and confidence intervals from arbitrary proxy responses

Underground fluid flow in hydrocarbon reservoirs (or aquifers) is difficult to predict accurately due to geological and petrophysical uncertainties. To quantify that uncertainty, several spatial statistical methods are often used to generate an ensemble of subsurface models representing and sampling these uncertainties. However, to predict the uncertainties in terms of flow responses, one needs to run a forward flow simulator (often multiphase flow in transient state) on every model of this ensemble and this generally entails intractable computational costs. Approximate solutions (flow proxies) can help addressing this challenge but introduce physical simplifications whose impact on the uncertainty quantification is difficult to characterize. This paper proposes a workflow to assess the dynamic reservoir behavior uncertainties from an input ensemble of realizations sampling geological and geophysical uncertainties. Analytical reservoir production curves are estimated from proxy distances computed between all ensemble members and from a few accurate flow responses computed on a subset of the ensemble. A randomization process accounting for proxy quality and for model selection is used to assess confidence intervals about reservoir production quantile curves. The process can use both static and dynamic proxies and also permits to compare their efficiency. A case study on a real turbiditic reservoir shows the applicability of the method, and highlights the value of even a simple proxy to increase the confidence about future reservoir production.

Meteoric Water and Salt-Dome-Related Diagenesis in Tertiary Turbidite Reservoirs from the EspÍrito Santo Basin, Brazil

Abstract Quantitative petrography and stable-isotope and fluid-inclusion analysis revealed that the diagenetic evolution of two Tertiary turbidite sandstone reservoirs from the offshore part of the Espirito Santo Basin, eastern Brazil, was influenced by the flow of meteoric water and salt-dome-related fluids, which had different impacts on their quality. Influx of meteoric water during early burial, in response to relative sea-level fall, resulted in extensive kaolinization and dissolution of framework silicate grains. Mesogenetic compactional fluids were progressively modified by the proximity of salt domes, which led to ubiquitous feldspar albitization and localized quartz, calcite, and saddle-dolomite precipitation. Fluid inclusions in quartz overgrowths indicate that the precipitating fluids had salinities predominantly in the range 8–13 wt% NaCl equivalent and temperatures largely in the 100–155°C range (higher than present-day formation temperatures—105° up to 115°C). The distribution of feldspar albitization suggests that the fracture systems along the margins of the salt domes acted as preferential pathways for such hot brines. However, the influence of the salt domes on the diagenetic processes of the reservoirs was relatively mild, despite their proximity, because pore-filling neoformed illite is absent, and occurrence of quartz cement is limited in the sandstones, which may be related to the late burial of the reservoirs and the intermittent behavior of the salt-dome-associated fracture systems as effective conduits for reactive fluids. We expect that this paper may contribute to the understanding and prediction of diagenesis and reservoir properties of turbidite sandstones influenced by meteoric and salt-dome-related fluids in offshore Espirito Santo Basin and in other similar areas.