Design of Hybrid Steam-In Situ Combustion Bitumen Recovery Processes

Given enormous capital costs, operating expenses, flue gas emissions, water treatment and handling costs of thermal in situ bitumen recovery processes, improving the overall efficiency by lowering energy requirements, environmental impact, and costs of these production techniques is a priority. Steam-assisted gravity drainage (SAGD) is the most widely used in situ recovery technique in Athabasca reservoirs. Steam generation is done on surface and consequently, because of heat losses, the energy efficiency of SAGD can never be ideal with respect to the energy delivered to the sandface. An alternative to surface steam generation is in situ combustion (ISC) where heat is generated within the formation through injection of oxygen at a sufficiently high pressure to initiate combustion of bitumen. In this manner, the heat from the combustion reactions can be used directly to mobilize the bitumen. As an alternative, the heat can be used to generate steam within the formation which then is the agent to move heat in the reservoir. In this research, alternative hybrid techniques with simultaneous and sequential steam-oxygen injection processes are examined to maximize the thermal efficiency of the recovery process. These hybrid processes have the advantage that during ISC, steam is generated within the reservoir from injected and formation water and as a product of oxidation. This implies that ex situ steam generation requirements are reduced and if there is in situ storage of combustion gases, that overall gas emissions are reduced. In this research, detailed reservoir simulations are done to examine the dynamics of hybrid processes to enable design of these processes. The results reveal that hybrid processes can lower emitted carbon dioxide-to-oil ratio by about 46%, decrease the consumed natural gas-to-oil ratio by about 73%, reduce the cumulative energy-to-oil ratio by between 40% and 70% compared to conventional SAGD, and drop water consumption per unit oil produced. However, oil recovery is between 25% and 40% below that of SAGD. Design of successful hybrid steam–oxygen processes must take into account the balance between injected steam and amount of injected oxygen and combustion gas products that dilute injected and in situ-generated steam in the depletion chamber by lowering its partial pressure, and thus its saturation temperature which in turn impacts production rates and recovery.     

Optimization of SAGD Well Elevation

The application of steam-assisted gravity drainage (SAGD) to recover heavy oil sands is becoming increasingly important in the northern Alberta McMurray Formation because of the vast resources/reserves accessible with this mechanism. Selecting the stratigraphic elevations of SAGD well pairs is a vital decision for reservoir evaluation and planning. The inherent uncertainty in the distribution of geological variables significantly influences this decision. Geostatistical simulation is used to capture geological uncertainty, which is used can be transformed into a distribution of the best possible well pair elevations. A simple exhaustive calculation scheme is used to determine the optimum stratigraphic location of a SAGD well pair where the recovery R is maximized. There are three basic steps to the methodology: (1) model the uncertainty in the top continuous bitumen (TCB) and bottom continuous bitumen (BCB) surfaces, (2) calculate the recovery at all possible elevation increments within the TCB and BCB interval, and (3) identify the elevation that maximizes R. This is repeated for multiple TCB/BCB pairs of surfaces to assess uncertainty. The methodology is described and implemented on a subset of data from the Athabasca Oilsands in Fort McMurray, Alberta.     

Implementation of Rock Typing on Waterflooding Process During Secondary Recovery in Oil Reservoirs: A Case Study,El Morgan Oil Field,Gulf of Suez,Egypt

Waterflooding is one of the most common secondary recovery methods in the oil and gas industry. Globally, this process sometimes suffers a technical failure and inefficiency. Therefore, a better understanding of geology, reservoir characteristics, rock typing and discrimination, hydraulic flow units, and production data is essential to analyze reasons and mechanisms of water injection failure in the injection wells. Water injection failure was reported in the Middle Miocene Hammam Faraun reservoir at El Morgan oil field in the Gulf of Suez, where two wells have been selected as injector’s wells. In the first well (A1), the efficiency of injection was not good, whereas in the other analog A2 well good efficiency was assigned. Therefore, it is required to assess the injection loss in the low efficiency well, where all aspects of the geological, reservoir and production data of the studied wells were integrated to get a complete vision for the reasons of injection failure. The available data include core analysis data (vertical and horizontal permeabilities, helium porosity, bulk density, and water and oil saturations), petrographical studies injection and reservoir water chemistry, reservoir geology, production, and injection history. The quality of the data was examined and a set of reliable X–Y plots between the available data were introduced and the reservoir quality in both wells was estimated using reservoir quality index, normalized porosity index, and flow zone indicator. Integration and processing of the core and reservoir engineering data indicate that heterogeneity of the studied sequence was the main reason for the waterflooding inefficiency at the El Morgan A1 well. The best reservoir quality was assigned to the topmost part of the reservoir, which caused disturbance of the flow regime of reservoir fluids. Therefore, it is clearly indicated that rock typing and inadequate injection perforation strategy that has not been aligned with accurate hydraulic flow units are the key control parameters in the waterflooding efficiency.

     

Scattering characteristics in heterogeneously fractured reservoirs from waveform estimation

Offset-dependent characteristics of seismic scattering are useful for characterizing fractured reservoirs. We use two models that have different background medium properties and different azimuthal AVO responses to study elastic wave propagation and scattering in gas-saturated, heterogeneously fractured reservoirs. Heterogeneous fracture density distributions are built through stochastic modelling. Synthetic seismograms are generated by 3-D finite difference modelling, and waveforms along crack-normal and strike directions are considered in this paper. The multiple signal classification (MUSIC) frequency estimator is used in waveform estimation to provide frequency-domain attributes related to seismic wave scattering by fracture heterogeneity. Our results indicate that the strength of the scattering field is a function of the background medium. The strength also increases with increasing fracture scatterer density and with decreasing correlation length of spatial variations of fracture density. The scattering field is weak at the top of the fractured reservoir. The first-order results are dominated by velocity anisotropy of the mean fracture density field. However, the base of the fractured reservoir corresponds to a strong scattering field on which fracture heterogeneity has a larger effect and is characterized by the loss of coherence.     

Lacustrine basin hydrocarbon exploration – current thoughts

Although much of the world's petroleum resource-base is associated with marine systems, regionally lacustrine petroleum systems are important. Individual accumulations may exceed several billion barrels. In each of these cases the oil is derived from a lacustrine source rock and may be produced from either nonmarine or marine reservoir rocks. The purpose of this paper is to describe the factors that control lacustrine source rock development and the nature of lacustrine reservoirs. Lacustrine oils display different physical and chemical characteristics than their marine counterparts. These differences can be related to the nature of their precursor material. Although the nature of the products are different, the geochemical threshold criteria for defining source rocks in both settings are the same because of common expulsion requirements. Commercially significant lacustrine systems require the presence of large, long-lived lakes. Such lake settings are tectonic in origin and restricted to climatic settings where precipitation exceeds evaporation. Within these large lake systems three primary factors determine source rock potential and quality. These factors are primary productivity level, organic preservation potential, and matrix sedimentation rate, which controls the dilution of preserved organic matter. Source rock potential is maximized where both productivity and preservation potential are maximized and sedimentation rate is minimized. To some degree these factors can compensate for each other. Hydrocarbon reservoir potential within lacustrine basins is partially impacted by overall tectonic setting. Within extensional settings, transport distances tend to be limited, with much of the sediment being transported away from the basin. The sediments delivered to the lake are poorly sorted and sedimentologically immature, commonly resulting in poor reservoirs due to both primary properties and their susceptibility to diagenesis. Within rifts better reservoirs tend to develop along platform or flexural margins. Stacking of reservoirs is important in lacustrine systems but baffles and barriers are often present between individual sand units. These barriers form as a result of lake level fluctuations. In compressional settings transport distances tend to be longer, resulting in more mature, better sorted sediments leading to higher quality reservoirs. These reservoirs typically develop in fluvial-deltaic and wave-dominated shoreline settings. Lacustrine carbonate reservoirs are locally important. These carbonates tend to develop during lake level lowstands and are dependent on diagenesis (dissolution and karstification) for porosity and permeability development. Lacustrine reservoirs are often stratigraphically and areally limited and display low individual well production rates. Within pure lacustrine systems exploration opportunities appear to be often restricted by either reservoir presence or quality (i.e., production rates). The best exploration opportunities in lacustrine basins appear to be associated with hybrid systems where a lacustrine source and marine reservoir exist.     

柴达木盆地马海盐湖储卤层渗透特征及卤水富集机制

通过野外抽水试验方法,确定了柴达木盆地马海盐湖储卤层渗透系数,并结合地下卤水赋存特征与沉积环境对其渗透性能进行分析。结果表明：本地区石盐层大多不纯,石盐晶体内包裹有泥、砂,且晶体间也有泥、砂充填。在石盐沉积期间,由于受到洪水与间歇性河流影响,导致地质环境演化过程中沉积形成的储卤层渗透性能在各处相差较大,区域地下卤水的连通性相对较弱。根据试验开采区27口开采井钻孔资料和地下卤水监测数据,进行了储卤层差异性分类,将钻孔所揭露储卤层划分为3种类型,不同类型储卤层卤水富集性能具有较大差异,表现为渗透系数和单井涌水量在平面分布上的较大数值差距。通过对钻孔岩心岩性、孔隙特征及补给条件等方面进行分析,得出卤水富集性能强的基本条件：储卤层具备天然良好的颗粒骨架和稳定的卤水补给来源与通道。依据储卤层渗透性能和卤水富集规律,将马海盐湖试验开采区划分出不同地下卤水富集区段。     

Prediction of Shale Plugs between Wells in Heavy Oil Sands using Seismic Attributes

A fundamental geologic problem in the Steam-Assisted Gravity Drainage (SAGD) heavy oil developments in the McMurray Formation of Northern Alberta is to determine the location of shales in the reservoirs that may interfere with the steaming or recovery process. Petrophysical analysis shows that a key acoustic indicator of the presence of shale is bulk density. In theory, density can be derived from seismic data using Amplitude Versus Offset (AVO) analysis of conventional or multicomponent seismic data, but this is not widely accepted in practice. However, with billions of dollars slated for SAGD developments in the upcoming years, this technology warrants further investigation. In addition, many attributes can be investigated using modern tools like neural networks; so, the density extracted from seismic using AVO can be compared and combined with more conventional attributes in solving this problem. Density AVO attributes are extracted and correlated with “density synthetics” created from the logs just as the seismic stack correlates to conventional synthetics. However, multiattribute tests show that more than density is required to best predict the volume proportion of shale (Vsh). Vsh estimates are generated by passing seismic attributes derived from conventional PP, and multicomponent PS seismic, AVO and inversion from an arbitrary line following the pilot SAGD wells through a neural network. This estimate shows good correlation to shale proportions estimated from core. The results have encouraged the application of the method to the entire 3D.     

Paleolimnological records reveal biotic homogenization driven by eutrophication in tropical reservoirs

Biodiversity changes in response to eutrophication, climate variability and species invasions. These pressures have been shown to reduce community heterogeneity at various scales; however, how productivity drives homogenization patterns in a community of primary producers, such as diatoms, has not been studied. Using a dataset with good temporal resolution, obtained from cores collected from seven tropical reservoirs, we evaluated patterns of spatial and temporal homogenization, i.e. the trends in temporal α-diversity and spatial β-diversity (change in community composition), of diatom assemblages over the past 60–100 years. The paleolimnological records allowed us to study biodiversity trends since the initial community (reservoir construction) in those systems with low anthropogenic impact and also those undergoing eutrophication. No clear trend of spatial β-diversity change over time was found when all reservoirs were analyzed together. However, when only eutrophic reservoirs were considered, a marked decrease in the spatial β-diversity occurred, suggesting that eutrophication leads to homogenization of the diatom assemblage. These findings were reinforced by the lack of change in β-diversity when the age of the reservoirs was standardized, indicating that the reservoirs’ ontogeny did not influence the spatial β-diversity trend and β-diversity did not increase even in the reservoirs with low anthropogenic impact. In addition, the results showed a decrease of α-diversity over time for almost all the eutrophic reservoirs, as well as a decrease in the total species pool for the reservoirs, although periphytic diatoms may be favored by the appearance and sometimes mass development of floating macrophytes in warm, shallow eutrophic reservoirs. This study supports the role of eutrophication as one of the main drivers of diatom assemblage homogenization in tropical reservoirs, with a significant loss of species over time.     

Integrated Petrophysical Modeling for a Strongly Heterogeneous and Fractured Reservoir,Sarvak Formation,SW Iran

Introducing and applying an appropriate strategy for reservoir modeling in strongly heterogeneous and fractured reservoirs is a controversial issue in reservoir engineering. Various integration approaches have been introduced to combine different sources of information and model building techniques to handle heterogeneity in geological complex reservoir. However, most of these integration approaches in several studies fail on modeling strongly fractured limestone reservoir rocks of the Zagros belt in southwest Iran. In this study, we introduced a new strategy for appropriate modeling of a production formation fractured rock. Firstly, different rock types in the study area were identified based on well log data. Then, the Sarvak Formation was divided into nine zones, and the thinner subzones were used for further fine modeling procedure. These subzones were separated based on different fracture types and fracture distribution in each zone. This strategy provided sophisticated distribution of petrophysical parameters throughout the grids of the model, and therefore, it can handle strong heterogeneity of the complex reservoir. Afterward, petrophysical parameters were used to produce an up-scaled 3D gridded petrophysical model. Subsequently, maps of petrophysical properties were derived for each zone of the Sarvak Formation. Evidences achieved in this study indicates Sarvak Formation zone 2 as the target production zone with better performance of reservoir rock and the southwestern part of the field as area of maximum porosity.     

盐相关盆地油气地质特征及其勘探认识——以红海盆地为例

全球已发现的工业油气田中与盐系地层有关的约为58%,总结盐相关盆地油气地质特征及其勘探经验,为含盐盆地的油气发现具有非常重要的意义。通过对红海盆地的岩盐发育和分布规律研究、盆地生储盖特征分析及红海盆地实际勘探经验总结,认为含盐盆地具有以下特征:含盐盆地盐系地层发育,岩盐因构造变形可形成多种类型的盐构造,油气勘探应以寻找各种盐构造油气藏为主;含盐盆地盐下易形成高温高压,盐下储层主要为碳酸盐岩和砂岩,这种异常高压对储集层的储集性能是有利的,盐下应以储层类型和圈闭识别为主要勘探目标;含盐盆地地质情况复杂,勘探工程难度大,需加强钻井工程研究;含盐盆地盐下地震成像普遍较差,加强盐下地震处理技术研究,辨别盐下"假构造",是盐盆勘探取得突破的关键。     

Instabilities of fluid conduits in a flowing earth — are plates lubricated by the asthenosphere?

Summary A laboratory and theoretical study of the stability of conduits of buoyant fluid in a viscous shear flow has been conducted. The object of the study is to explain the formation of discrete islands in island chains such as the Hawaiian Emperor seamount chain, and to investigate a new method by which the variation of shear with depth in the mantle may be determined. The conduits were made by injecting oil into a more viscous oil of greater density. Initially a growing chamber of lower viscosity oil formed near the injector, but when the chamber got sufficiently large it rose as a buoyant spheroid. Behind this trailed a vertical cylindrical conduit through which fluid could continue to rise to the surface as long as the source continued. If the more viscous fluid was sheared laterally the conduit was gradually rotated to a more horizontal position. The diameter of the conduit increased with time due to a decreasing component of gravitational force along the axis of the conduit. When the conduit was tilted to more than 60° with the vertical, it began to go unstable by developing bumps which ultimately initiated a new chamber which rose to a new spot. In addition, if the Reynolds number of the conduit was greater than approximately ten, an axisymmetric wavy instability appeared in the walls of the conduit and the conduit had to be tilted less before a new chamber was initiated. If shear under the Pacific plate has to tilt buoyant mantle plumes to as much as 60° to form the relatively regular island chains associated with hot spots, most of the shear would be found in a zone with a vertical extent of less than 200 km.     

Applicability of Kinetic Models for In Situ Combustion Processes with Different Oil Types

The in situ combustion (ISC) process is of interest as an enhanced oil recovery method because it is an alternative to traditional steam-based processes for heavy oil and bitumen recovery. ISC is a technique applicable outside the window of reservoir conditions deemed appropriate for steam injection (such as deeper and thinner reservoirs). The process involves complex chemical reactions and physical recovery mechanisms, and predicting the likelihood of successful ISC in field applications remains challenging. This paper describes a numerical investigation of the capability of different ISC kinetic models to predict the combustion behaviors of different types of oils (light oil, heavy oil, and bitumen). Three kinetic models (of Coats, Crookston, and Belgrave) were selected from literature and compared using data from four published combustion-tube experiments. The comparison procedure is as follows: (1) validate the numerical modeling of each kinetic model by matching the selected experimental results or duplicating the numerical results found in published literature; (2) adjust fluid viscosities and densities to match the fluid properties of each experiment;and (3) use each validated kinetic model to predict the performance of the other experiments without further tuning the kinetic parameters. The knowledge derived from the experiments provides guidance for choosing the appropriate kinetic model when no other data are available and for the preliminary design and screening study of a potential ISC project.     

Fold evolution and drainage development in the Zagros mountains of Fars province, SE Iran

A central question in structural geology is whether, and by what mechanism, active faults (and the folds often associated with them) grow in length as they accumulate displacement. An obstacle in our understanding of these processes is the lack of examples in which the lateral growth of active structures can be demonstrated definitively, as geomorphic indicators of lateral propagation are often difficult, or even impossible to distinguish from the effects of varying lithology or non‐uniform displacement and slip histories. In this paper we examine, using the Zagros mountains of southern Iran as our example, the extent to which qualitative analysis of satellite imagery and digital topography can yield insight into the growth, lateral propagation, and interaction of individual fold segments in regions of active continental shortening. The Zagros fold‐and‐thrust belt contains spectacular whaleback anticlines that are well exposed in resistant Tertiary and Mesozoic limestone, are often >100 km in length, and which contain a large proportion of the global hydrocarbon reserves. In one example, Kuh‐e Handun, where an anticline is mantled by soft Miocene sediments, direct evidence of lateral fold propagation is recorded in remnants of consequent drainage patterns on the fold flanks that do not correspond to the present‐day topography. We suggest that in most other cases, the soft Miocene and Pliocene sediments that originally mantled the folds, and which would have recorded early stages in the growth histories, have been completely stripped away, thus removing any direct geomorphic evidence of lateral propagation. However, many of the long fold chains of the Zagros do appear to be formed from numerous segments that have coalesced. If our interpretations are correct, the merger of individual fold segments that have grown in length is a major control on the development of through‐going drainage and sedimentation patterns in the Zagros, and may be an important process in other regions of crustal shortening as well. Abundant earthquakes in the Zagros show that large seismogenic thrust faults must be present at depth, but these faults rarely reach the Earth's surface, and their relationship to the surface folding is not well constrained. The individual fold segments that we identify are typically 20–40 km in length, which correlates well with the maximum length of the seismogenic basement faults suggested from the largest observed thrusting earthquakes. This correlation between the lengths of individual fold segments and the lengths of seismogenic faults at depth suggest that it is possible, at least in some cases, that there may be a direct relationship between folding and faulting in the Zagros, with individual fold segments underlain by discrete thrusts.     

The physical scale modelling of braided alluvial architecture and estimation of subsurface permeability

The quantitative modelling of fluvial reservoirs, especially in the stages of enhanced oil recovery, requires detailed three‐dimensional data at both the scale of the channel belt and within‐channel. Although studies from core, analogue outcrop and modern environments may partially meet these needs, they often cannot provide detail on the smaller‐scale (i.e. channel‐scale) heterogeneity, frequently suffer from limited three‐dimensional exposure and cannot be used to examine the influence of different variables on the process–deposit relationship. Physical modelling offers a complementary technique that can address many of these quantitative requirements and holds great future potential for integration with reservoir modelling. Physical modelling provides the potential to upscale results and derive reservoir information on three‐dimensional facies geometry, connectivity and permeability. This paper describes the development and use of physical modelling, which employs generic Froude‐scaling principles, in an experimental basin that permits aggradation in order to model the morphology and subsurface depositional stratigraphy of coarse‐grained braided rivers. An example is presented of a 1:50 scale model based on the braided Ashburton River, Canterbury Plains, New Zealand and the adjacent late Quaternary braided alluvium exposed in the coastal cliffs. Critically, a full, bimodal grain size distribution (20% sand and 80% gravel) was used to replicate the prototype, which allows the realistic reproduction of the surface morphology and importantly permits grain size sorting during deposition. Uncertainties associated with the compression of time, sediment mass balance and the hydrodynamics of the finest particle sizes do not appear to affect the reproducibility of stratigraphy between experimental and natural environments. Sectioning of the preserved sedimentary sequence in the physical model allows quantification of the geometry, shape, spatial distribution and internal sedimentary structure of the coarse‐ and fine‐grained facies. A six‐fold facies scheme is proposed for the model braided alluvium and a direct link is established between the grain size distribution and facies type: this allows permeability to be estimated for each facies, which can be mapped onto two‐dimensional vertical cross‐sections of the preserved stratigraphy. Results demonstrate the dominance of four facies based on permeability that range over three orders of magnitude in hydraulic conductivity. Quantification of such variability, and linkage to both vertical proportion curves for facies distribution and connectivity presents significant advantages over other methodologies and offers great potential for the modelling of heterogeneous braided river sediments at the within channel‐belt scale. This paper outlines how physical models may be used to develop high‐resolution, geologically‐accurate, object‐based reservoir simulation models.     

South Caspian Oil Fields: Onshore and Offshore Reservoir Properties

Original field data reports from the Azerbaijan sector of the South Caspian Basin have been used to compile statistical histograms of reservoir characteristics for both onshore and offshore oil fields. Two groups of statistics are presented here: the first group discusses reservoir thickness, areas, volumes, and horizon depths for the onshore and offshore fields; the second group discusses permeability, porosity, oil viscosity, oil recovery factor, reserves, and production for the onshore and offshore fields. These statistical distributions have been constructed so that one has available an historical database for use in assessing the range of likely reservoir characteristics in exploration ventures in this basin.     

Combustion Kinetics of Athabasca Bitumen from 1D Combustion Tube Experiments

There are two basic requirements for heavy-oil recovery processes: first, mobilize the bitumen, and second, have a drive mechanism deliver the mobilized bitumen to a production wellbore. In situ combustion has the potential to be an important heavy-oil recovery method. Before design of in situ combustion recovery processes can start, it is necessary as a first step to understand the kinetics of various complex chemical reactions and determine kinetic constants associated with the reactions. Even with modern reservoir simulation capabilities, this is a significant challenge. In this research, an Athabasca bitumen combustion tube experiment, conducted by the ISC Research Group at the University of Calgary, was history matched by using a reservoir thermal simulator to determine a set of kinetic parameters as well as the transport parameters for the system. The main results of the history match was a match of air injection rate, bitumen and gas production volumes, average product gas compositions, temperature profiles along the tube through time, and pressure. Gridding sensitivities were examined to determine if the derived kinetic and transport parameters were dependent on gridblock size. The results revealed that the grid was refined enough to sufficiently capture thermal, mass transfer, and reaction length scales. After this single match was achieved, the same constants were used to successfully predict several other combustion tube experiments. The results suggest that the fuel (coke) for high-temperature oxidation (HTO) originates mainly from low-temperature oxidation (LTO) and not from thermal cracking. This implies that the major control on HTO is upstream oxygen transfer into the LTO region. If LTO does not occur, then a relatively small amount of coke is deposited in the matrix due to thermal cracking and this may be insufficient to start or sustain HTO.     

Determining Wettability of Fractured Carbonate Reservoirs

Wettability plays a pivotal role in oil recovery processes in reservoirs owing to the fact that it has a direct impact on the proportion of oil recovery. Reservoir rocks are a complex of a variety of mineral types, and each mineral may have a different wettability. Typically most aquifer materials such as quartz, carbonate, and dolomite are water-wet prior to oil migration. Some oil recovery processes are designed to alter the wetting preference of the oil formation to be more oil-wet. There are three techniques used in the laboratory for the characterization of the capillary pressure properties of core samples: mercury injection, centrifuge, and porous plate. This article provides an in-depth review of wettability. It also entails a case study from one of the Iranian carbonate reservoirs and measurements, which have been carried out for selected samples to clarify the nature of the wettability of reservoir rock. Samples were chosen from three wells of oil field which is composed of limestones and dolomites, rarely inter-bedded by shales, and their wettability was measured by Amott–Harvey method, which is one of the main methods for measuring wettability. After cleaning and drying the samples, measurements were carried out. According to the results, it can be said that the range of Amott–Harvey index for these samples is between ?0.48 and ?0.8. In Amott–Harvey method, if IAH varies from ?1 to ?0.3, the rock is oil-wet. Therefore, it can be concluded that the reservoir is oil-wet.     

Vegetation heterogeneity in Monte Desert ecosystems: A multi-scale approach linking patterns and processes

We review the current state of research on vegetation heterogeneity in the Monte Desert at scales varying from landscape to intra-patch. Different factors are related to vegetation heterogeneity at every scale. At a coarse scale (i.e. landscapes and communities) vegetation heterogeneity is commonly determined by abiotic factors, whereas biotic interactions usually influence fine scale (patch, intrapatch) heterogeneity. Communities are distributed at the landscape scale according to differences in precipitation, topography and soil attributes. On the other hand, there is evidence that the spatial pattern of plant patches within communities is determined by runon –runoff processes, although biotic influences such as grazing can induce changes in the spatial pattern of patches when plant cover is strongly reduced. In the same way, at patch and intrapatch scales, biotic interactions (i.e. plant –plant interactions, grazing) determine the size and the species composition of plant patches as well as the distribution of species inside plant patches. However, the mechanisms operating behind such biotic interactions at small scales are commonly related to plant-induced changes in the physical environment. We also found evidence of cross-scale interactions, feedbacks, and non-linear effects such as those induced by grazing disturbance. Our analysis showed some regional differences in patterns and processes related to vegetation heterogeneity along the Monte Desert which can be ascribed to climatic and taxonomic variation among areas. Although information about vegetation heterogeneity and its causes and consequences in the Monte Desert is abundant, some areas where knowledge is scarce are detailed.     

Low resistivity zones at contacts of igneous intrusions emplaced in organic-rich formations and their implications on fluid flow and petroleum systems: A case study in the northern Neuquén Basin,Argentina

Igneous sills and laccoliths emplaced in sedimentary basins may significantly impact petroleum systems, both positively and negatively. Igneous intrusions provide heat to maturate regionally immature organic-rich host rocks, act as fractured reservoirs hosting commercial accumulations of hydrocarbons, and form structures affecting fluid flow and trapping at different scales. Nevertheless, the petrophysical implications of igneous intrusions on their host rock are poorly known. In this study, we analyse 200 wells in the Río Grande Valley oil field, Neuquén basin, Argentina, where the main reservoirs are in fractured igneous sills. This dataset represents a globally unique possibility to characterize the igneous–host rock interaction using both wireline logs and core material. We identify a systematic Contact Low Resistivity Zone (CLRsZ) at both the upper and lower contacts of the sills emplaced in the organic-rich Vaca Muerta and Agrio Formations. We characterize the nature of these CLRsZ and their petrophysical properties by integrating resistivity and gamma ray well logs, petrographic analyses, petrophysical tests and geochemical analyses. The low resistivity signal of the CLRsZ is dominantly carried by massive-sulphide deposits, mainly pyrite, observed both in the host rock and the chilled margin of the sills. Well log images and porosity-permeability analysis on core plugs show that both the sills and their associated CLRsZ can act as carrier for fluid flow and reservoir for hydrocarbons storage. The thickness of the upper and lower CLRsZ correlates linearly with the thickness of the sill, and the volume of both the upper and lower CLRsZ represents ca. 40% with respect to the volume of their associated sill. The thickness of the CLRsZ represents ca. 13% of the thickness of contact aureole induced by the sills. In the CLRsZ, a great proportion of kerogen was transformed to hydrocarbon, so that CLRsZ were restricted to the innermost contact aureole of the sills. Our results show that the CLRsZ can have major implications on fluid flow and should be considered in reservoir models in volcanic basins hosting sills emplaced in organic-rich formations.