Detailed Geological Description Research Articles

METHODS FOR HIGHLY EFFICIENT DEVELOPMENT OF OFFSHORE RIVERINE OILFIELDS

The geological reservoir conditions of offshore fluvial oilfields in the Bohai region are characterized by their complexity, including thin reservoir layers, significant lateral variations, and poor connectivity. These conditions pose challenges in deploying production wells, finely describing reservoirs, and optimizing resource allocation. This study has developed several techniques to address these challenges effectively. These include fine description and quantitative characterization of reservoirs in areas with few wells, regional sedimentation analysis and identification of individual river reservoirs, optimization of well networks for single sand bodies, and a rolling technique for tapping potential in fluvial oilfields. The effectiveness of these techniques has been confirmed through their application in the development of 11 oilfields in Bohai, resulting in the addition of newly discovered reserves amounting to 5 billion tons during rolling development evaluations. The fine description technology has achieved a drilling accuracy rate of 98%, while the recognition technique for individual river reservoirs in fluvial environments has increased the recovery rate by an average of 3%. Moreover, the rolling development technique has enabled rapid resource transformation around the oilfields, facilitating the efficient development of oil and gas resources. The Bohai oilfield, situated in the Bohai Sea, is part of the offshore Bohai Bay Basin. After four decades of exploration and development, this field has produced significant oil reserves from the Neogene Minghuazhen and Guantao formations. In 2012, these reserves constituted 56.3% of the Bohai oilfield's total proven oil reserves, underscoring the critical role of efficient development strategies for these reservoirs in maintaining and enhancing oil production. These formations have undergone extensive fracturing due to recent tectonic activities, resulting in a highly broken structure and complex fault blocks. Post-Neogene, the Bohai Sea became a major drainage center for the Bohai Bay Basin, fostering not only traditional fluvial sedimentary systems but also shallow water delta systems, primarily around distributary channels or underwater channels. The fluvial oilfields discussed in this paper include reservoirs from both meandering and braided river systems, as well as parts of shallow water delta distributary channels. The reservoirs typically exhibit curved strip, ribbon, and dendritic shapes, and feature thin reservoir layers with substantial lateral variation. This complexity is further compounded by interactions between water and oil beds, leading to a distinct "one sand body, one oil reservoir" scenario. To effectively develop these fluvial oilfields, the research employs advanced techniques. These include detailed reservoir description and quantitative characterization in areas with sparse well distribution, study of regional sedimentary evolution and identification of individual river reservoirs, optimization of well networks for single sand bodies, and a rolling technique to tap potential in fluvial oilfields. These methods are essential for overcoming the geological challenges and optimizing oil extraction in such complex environments. The development of offshore fluvial oilfields encounters specific challenges, largely due to differences in the approach and conditions compared to onshore oil field development. For onshore fields in China, the development strategy typically evolves progressively, beginning with the establishment of a basic well pattern. This initial phase is followed by integrated geological and reservoir studies to determine optimal development and infill drilling patterns. In contrast, offshore oilfields are constrained by several factors that complicate their development. High operational costs limit the number of exploratory wells that can be drilled, resulting in sparse well patterns and consequently less data for making informed decisions. Additionally, the physical limitations of offshore platforms — such as available space, the lifespan of the platform, and finite well slot resources — prevent frequent adjustments to the drilling plan. To navigate these challenges and achieve efficient development, offshore oilfields require robust preliminary research. This involves a comprehensive and detailed geological description of the reservoirs, which forms the basis for strategic deployment of development wells. By adapting the well deployment strategy to the specific geological characteristics and constraints of offshore environments, developers can enhance the effectiveness and efficiency of oil extraction from these complex reservoirs. Keywords: geological reservoir condition, fluvial oilfields, geological challenges, seismic data, conventional method

Classificação textural de rochas carbonáticas do pré-sal da Bacia de Santos e análise do sistema permoporoso: uma abordagem baseada na interpretação de imagens de tomografia computadorizada de raios X

Pre-salt lacustrine carbonates remain in evidence for being rocks of high complexity and responsible for the great economic potential of the Santos Basin. Aiming to contribute to studies in this field, the objective of this research was to define the key textures of the carbonate rocks in X-ray computed tomography (CT) images. For the execution of this study, core samples from two wells were used, and the adopted methodology comprises detailed geological description, characterization of the permoporous system, definition of the main textures in CT images, and analysis of the relationship between textures and their permoporous systems. The description of the main properties enabled the definition of six lithofacies and, through the analysis of CT images, a recurring pattern of certain textural attributes in specific lithofacies was identified. Thus, a representative proposal with four textural classes was established: laminated, shrubby, clastiform fragmented, and recrystallized. A direct relationship was observed between certain textures and the progression of diagenetic processes, as well as their corresponding permoporous systems. Finally, the proposed textural classification of CT images applied to Brazilian pre-salt lacustrine carbonate rocks demonstrates effectiveness in standard segmentation performed by expert technicians, enabling rapid identification of reservoir intervals of interest. For future work, it is recommended to employ this classification as an input base for training algorithms using machine learning techniques.

Assessing mesoscale permeability in unsaturated, fractured, and karstified carbonate reservoirs: a joint geological, petrophysical, and hydraulic approach for the interpretation of injection tests

In the study of subsurface reservoirs, permeability is a key parameter whose evaluation and extrapolation at the desired scale, such as that of the numerical model mesh, are both a necessity and a difficult task. Relating permeability measurements to the geological characteristics of the rock, at intermediate scales seldom characterized, can help understanding the heterogeneity of the medium and correctly determining the permeability at the desired scale. This concern is particularly important in karst reservoirs, which exhibit highly variable permeability at different scales of observation and from one location to another. Here, we study the petrophysical and geological properties of carbonate facies from the centimeter to the meter scale. Several boreholes a few meters apart were cored and exhaustively described. Petrophysical measurements were made on rock samples, while inter-packer injection tests were undertaken to investigate some meter intervals of the medium surrounding the wells. The results show that the investigated medium is a complex multi-medium with a multi-scale heterogeneity. The detailed geological description allowed explaining the differences between the permeability values at different scales and from one interval to another. Relationships were quantified between the texture of the limestone matrix, the density and aperture of the discontinuities, the permeability of the matrix, and the permeability contrast related to the dual medium at the meter scale. A strong correlation between this permeability contrast and the aperture of the discontinuities, itself more correlated to the texture of the rock than to the facies, is highlighted.

Geology and Structural Evolution of the La Huifa Ore Deposit, Central Chile: A Newly Discovered Porphyry Cu-Mo System in the El Teniente District

Abstract La Huifa is a breccia-related Cu-Mo porphyry deposit located in the Andes of central Chile, 3 km northeast of the giant El Teniente porphyry Cu-Mo orebody. It was discovered as part of CODELCO’s (Corporación Nacional del Cobre de Chile) brownfield exploration activities in the El Teniente district. It is the first major discovery in the area, and this work presents its first detailed geologic description. The La Huifa orebody is related to a complex of late Miocene diorite and granodiorite intrusions and hydrothermal breccias, the latter characterized by abundant tourmaline-anhydrite cement, emplaced in middle to late Miocene volcanic and subvolcanic rocks. The structural architecture of La Huifa is dominated by WNW-and NE-striking high angle faults. Usually, slip on the WNW-striking faults involves a sinistral component, whereas slip on the NE-striking faults is predominantly dextral. The main hydrothermal breccia body at La Huifa is located at the intersection of WNW- and NE-striking faults. Four stages are proposed for the tectono-magmatic-hydrothermal evolution of La Huifa:Premineralization, involving tourmaline-albite veins and sodic calcic alteration emplaced under a transpressive tectonic regime with a subhorizontal, ~E-W–trending σ1 (~N-S–trending σ3);Early mineralization, involving a polydirectional vein system associated with poorly developed potassic and transitional alteration zones with a scarce presence of Cu and Mo sulfides;Main mineralization, involving Cu- and Mo-rich anhydrite-tourmaline hydrothermal breccias and polydirectional veins associated with strong chlorite-sericite alteration with a 270° to 290°C emplacement temperature, obtained from chlorite geothermometry. The regional stress field during this period was exceeded by the local fluid pressure. These breccias and veins are followed by the emplacement of NE-striking C and D type veins associated with gray and white sericite alteration, respectively, which show a similar temperature range.Late mineralization, involving a NE-striking, carbonate-rich vein system containing polymetallic sulfides. It is associated with argillic alteration, whose temperature was 200° to 260°C. This stage occurred under a compressive tectonic regime with NE-trending σ1. The relatively low temperature at which mineralization was introduced in this deposit (~270°–290°C) and the predominantly vertical fluid flow pattern typical of hydrothermal breccia systems allow us to infer the presence of more mineralized rock at depth, below the recognized portion of the system. The association of Cu and Mo enrichment with chlorite-sericite alteration, instead of higher-temperature potassic or gray sericite alteration events, makes La Huifa a unique case among the porphyry deposits of central Chile and broadens the scope of mineralization styles that could be targeted in this belt. Finally, the intersection of arc-oblique, high-angle faults and, in particular, the presence of fault systems orthogonal to the main compression direction, favorable for magma storage and differentiation and metal concentration, constitute a valuable tool for exploring porphyry Cu deposits in similar geologic contexts.

Effect of paleoclimate and paleoenvironment on organic matter accumulation in lacustrine shale: Constraints from lithofacies and element geochemistry in the northern Qaidam Basin, NW China

Organic matter enrichment in lacustrine shale is significantly influenced by paleoclimate and paleoenvironment. In this study, a total of 24 shale samples were vertically collected from the YQ-1 drilling well in the northern Qaidam Basin, north-western China. The high-resolution geochemistry analyses were performed to provide a detailed geological description of these samples through lithofacies interpretation, total organic carbon (TOC) content testing, element geochemistry analysis, and mineralogical composition characterization. The results show that four lithofacies types can be identified in the Middle Jurassic Shimengou Formation, which consist of the brown oil shale with horizontal bedding, the black shale with well-developed lamination, the grey-black mudstone with horizontal and wavy bedding, and the carbonaceous mudstone with plant debris. The former two types were preserved in the Upper Member and were mainly deposited in a deep and semi-deep lake environment, whereas the latter two types were preserved in the Lower Member and were deposited in a littoral-shallow lake. The TOC content, paleo-salinity, redox action, and paleo-productivity of the shales in the Upper Member are higher than those in the Lower Member, and other parameters, such as the chemical weathering degree and terrestrial clastic input, are higher in the shales of the Lower Member. Based on lithofacies and geochemical data, the shales in the Lower Member were deposited in a small, shallow freshwater lake within an oxygen-rich and relatively wet and hot paleoclimate, whereas the shales in the Upper Member were deposited in a large, deep, and saline water lake with dysoxic-anoxic conditions and a relatively arid and cold paleoclimate. The organic matter content in the Lower Member was primarily determined by the amount of detritus input with a low paleo-productivity owing to a strong weathering, whereas that in the Upper Member was dominated by anoxic processes under a good preservation and a low deposition rate. The model reflecting the relationship between accommodation and sediment-fill is employed to analyse the mechanism of organic matter accumulation. Three depositional stages are distinguished within the Shimengou Formation corresponding to overfilled, underfilled, and balanced-filled sediments with average TOC contents of 0.84 %, 4.95 %, and 6.09 %, respectively. This study reveals the dominated factors controlling organic matter enrichment in a continental basin and proposes a TOC distribution mechanism, which could provide a guide for the shale gas and shale oil exploration. • High-resolution geochemistry and detailed geological description were performed. • Paleoclimate evolution of Middle Jurassic Shimengou Formation was analysed. • Detritus inputs and anoxic degree were predominant factors for influencing TOC. • Three depositional stages of the Shimengou Formation were subdivided. • The model of lacustrine organic matter accumulation was proposed.

Магнитостратиграфия турона–сантона Самарского Правобережья

The paper presents the results of petro- and paleomagnetic studies of two sections of Turonian – Santonian on the Samara Right Bank – near Novodevichye, Podval’e villages and detailed geological description of the Novodevichye section. The magnetostratigraphic subdivision and detailed correlation of the sections were carried out. Unknown unconformity in the Podval’e section was recognized. Reverse polarity corresponds to a significant part of the Coniacian – Santonian deposits, the presence of which contradicts the existing ideas about the regime of the Turonian – Santonian geomagnetic field, but partly agrees with the data on deposits of the same age found in other sections in the Volga region.

Application of the steаm аssisted grаvity drаinаge (SAGD) method in the heavy oil fields

Recently, the prospects for the development of the oil industry have been associated with the development of deposits of heavy oils and natural bitumen. It is economically feasible and possible to extract high-viscosity oil (HVO) and natural bitumen (NB) only thanks to the development and application of effective technologies for their development. Unconventional oil production requires an unconventional exclusive approach, one of them is the steam — gravity method of oil production. The creation of SAGD models involves solving problems of heat and mass transfer in wells and a productive reservoir to optimize the production mode. To calculate the parameters of heat transfer, reliable information is required about the complex of thermal properties (thermal conductivity, thermal conductivity, volumetric heat capacity) of rocks of the productive formation, the underlying and overlapping layers of the mountain massif. Currently, when conducting research and constructing geological and technological models for predicting development indicators, the degree of influence of variations in the thermophysical properties of reservoir rocks on the efficiency of the SAGD process is not taken into account. Due to the absence until recent years of the possibility of obtaining reliable representative data on the thermal properties of rocks of a particular deposit, averaged values based on single measurements or on reference data that do not take into account the features of the object being developed and do not contain a detailed geological description of the studied rocks are usually used. In this regard, it was necessary to conduct a study of the influence of real spatial variations of the thermophysical properties of rocks, studied in detail for one of the deposits with the help of a new highly efficient hardware and methodological measuring base, on the development indicators by the SAGD method. In this article, the authors considered the effectiveness of using horizontal wells with cyclic steam exposure at the Yareg field.

Revisiting an old profile: an updated geoarchaeological study at Nasera Rockshelter (Tanzania)

ABSTRACTNasera Rockshelter hosts a highly continuous sedimentary record, containing a wide array of archaeological remains from Middle Stone Age, Later Stone Age and Pastoralist occupations. Excavated by L. Leakey and M. Mehlman, geological studies carried out by R. Hay included granulometric and general mineralogical analyses but lacked individualized, detailed description and interpretation of each of the 25 levels exposed. This study presents updated detailed geological descriptions and interpretations of 17 levels exposed during excavations in 2018.

Phased Pilot Approach Reduces Uncertainty in Carbonate Steamflood Development

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 191695, “Results From a Phased Piloting Approach in the First Eocene Reservoir of Wafra: Reducing Uncertainties in Carbonate Steamflood Development,” by David Barge, SPE, Joel Brown, Raushan Kumar, Chris Lolley, SPE, Ruurd Bartlema, and Saleh Al-Ghamdi, Chevron, prepared for the 2018 SPE Annual Technical Conference and Exhibition, Dallas, 24–26 September. The paper has not been peer reviewed. The First Eocene is a multibillion-barrel heavy-oil carbonate reservoir in the Wafra field, located in the Partitioned Zone (PZ) between Saudi Arabia and Kuwait. After more than 60 years of primary production, expected recovery is low and provides a good target for enhanced-oil-recovery (EOR) processes. A phased piloting approach has been used to reduce the uncertainties (subsurface and surface) related to application of thermal EOR processes in this field. Introduction Wafra is one of four major fields located in the PZ (Fig. 1). Because of the low primary oil recovery and large original oil in place of the Wafra Eocene reservoirs, a significant EOR opportunity exists. A detailed geological description of the reservoir is provided in the complete paper. Because of key surface and sub-surface uncertainties, along with the high cost of implementing a full-field steamflood-development (FFSFD) project, a phased, sequential approach, from piloting to FFSFD, was implemented. This approach was required so that critical uncertainties could be evaluated efficiently and sequentially in a time-frame consistent with overall reservoir- development objectives while managing capital exposure. Pilot Planning and Design Steamflood Pilots. A specific set of objectives, primary and secondary, was developed for each of the continuous-steam-injection (CSI) pilots. Primary objectives were identified as being critical for progression to the next phase (piloting/FFSFD); secondary objectives were regarded as important in understanding identified uncertainties, but not necessarily project roadblocks. Success measures for the pilots were derived from the key metrics that were prerequisites for the next phase. These success measures were formulated to ensure that learnings gained will be used to support the design and operational planning of the next phase. A five-spot pattern on a 1.25-acre steamflood-pilot, small-scale test (SST) was a continuation of the phased approach in managing and mitigating technical uncertainties related to implementing steamflooding. The primary objectives of the SST were to test whether Eocene-produced water could be treated to produce suitable feedwater for steam generation and to test steam injectivity in the First Eocene reservoir. The SST was conducted in First Eocene C Zone/Steam Zone 3 and successfully proved sustained injectivity using steam generated from the produced water. The SST was a pre-lude to a multipattern steamflood pilot known as the large-scale pilot (LSP).

Serpentinite in the Śnieżnik Massif: petrology and ecological impact

Abstract The paper presents a locality related to the occurrence of serpentinite body from the western slope of Żmijowiec in the Śnieżnik Massif. On the basis of field observations and numerous literature references, I provide a detailed geological description of this site and discuss the origin and tectonic settings of the serpentinite body. Apart from compelling geology, these rocks are site for ladder spleenwort, a rare species protected in Poland as well as in the European Union.

Proppant Fracture for Unconventional Carbonate Source Rock in Saudi Arabia

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IPTC 17765, “First Successful Proppant Fracture for Unconventional Carbonate Source Rock in Saudi Arabia,” by Nayef Ibrahim Al-Mulhim, SPE, Ali Hussein Al-Saihati, SPE, Ahmed M. Hakami, SPE, Moataz Al-Harbi, SPE, and Khalid Saeed Asiri, SPE, Saudi Aramco, prepared for the 2014 International Petroleum Technology Conference, Kuala Lumpur, 10–12 December. The paper has not been peer reviewed. A type of unconventional play currently being evaluated is a carbonate source rock with nanodarcy permeability and very low porosity. This paper will discuss the hydraulic-fracturing- stimulation design, execution, and evaluation for the first successful proppant-fracturing treatment in an unconventional carbonate source rock in Saudi Arabia. The successful two-stage treatment proved that proppant-fracturing techniques could be used to stimulate carbonate formations after modifying the stimulation design (specifically, the perforation strategy, fracturing fluids, and proppant type). Introduction The operator has embarked on an exploration-and-appraisal project to assess unconventional-resource potential in three geographic areas: northwest, South Ghawar, and East Ghawar. Hydraulic-fracturing techniques will be used to enhance production by connecting natural fissures and creating high-connectivity pathways through which gas can flow into the well. The initial focus is in the northwest and in the area of Ghawar. Initial knowledge building from similar plays in North America is being supplemented with internal technical studies and research programs to help solve geological and engineering challenges unique to Saudi Arabia and to locate specific wells planned for 2014. Acid vs. Proppant Fracturing The operator has used mainly acid fracturing and matrix acidizing to increase production rates from carbonate formations in conventional gas fields, while proppant fracturing was used predominantly in sandstone formations. This methodology, coupled with the fact that all previous attempts to stimulate carbonate formations in Saudi Arabia resulted in premature screenouts after only 10% of the proppant had been placed in the formation, clearly demonstrates the significance of the first successful proppant-fracturing treatment in an unconventional carbonate source rock in Saudi Arabia. Jafurah Basin Source Rocks The Jurassic sediments being targeted in the Jafurah basin as unconventional reservoirs are carbonate source rocks within the Tuwaiq Mountain, Hanifa, and locally basal Jubaila formations (please see the complete paper for a detailed geological description). The H-1 well is the first well drilled on a seismic anomaly, and it encountered a thick organicrich Jurassic source rock. The thick sequence of source rock in the H-1 well, as well as other areas within the basin, may suggest the possibility of a commercially viable unconventional play. As a followup to the drilling of the H-1 well, a geophysical forward-modeling project was initiated to investigate the cause of the seismic-amplitude anomaly in the Jafurah basin. The study revealed that the formation encountered in the H-1 well has an overall lower acoustic impedance, which appears to be the result of its high total organic content. Drilling and Coring The H-2 well, east of the giant Ghawar field, was drilled to evaluate several Jurassic source-rock targets. The well was completed with 4½-in. tubing, a 7-in. liner with a 7-in. permanent packer, and a 25-ft sealbore receptacle. The tubing and annulus were displaced with 65-lbm/ft3 brine. The well was designed to be re-entered for horizontal sidetracking. Five cores were cut for laboratory testing and analysis. Acid-solubility tests were performed on the core-plug samples to determine their solubility in hydrochloric acid (HCl). X-ray-diffraction analysis was performed on four core samples before and after the acid-solubility tests, showing that the four samples analyzed consisted mainly of calcite with smaller fractions of dolomite, quartz, anhydrite, pyrite, and clays. Perforation-Design Strategy Deep-penetrating charges were used in Well H-2, in conjunction with underbalanced perforating to minimize perforation damage and ensure clean perforations. In addition, 3,000 gal of 15% HCl was pumped as a preflush before pumping the pad in each stimulation treatment to further aid in removal of debris from the perforation tunnels.

New data on the stratigraphy and environment of the Eocene formation at the Aktolagay Plateau (West Kazakhstan)

Detailed geological description along with sedimentological and petromagnetic studies provided new data on the structure and formation environments of the Eocene key section at the Aktolagay Plateau (North Peri-Caspian, West Kazakhstan). The volumes of the Alashen and the Tolagaysor Formations were revised.

Scaling Up a 900-Million-Cell Static Model to a Dynamic Model

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 164187, ’Answering the Challenge of Scaling Up a 900-Million-Cell Static Model to a Dynamic Model - Greater Burgan Field, Kuwait,’ by Eddie Ma, SPE, Kuwait Oil Company; Sergey Ryzhov, SPE, Schlumberger; Yuandong Wang, SPE, Petrobras; Reham Al-Houti, SPE, Laila Dashti, SPE, and Farida Ali, Kuwait Oil Company; and Muhammad Ibrahim, SPE, Schlumberger, prepared for the 2013 SPE Middle East Oil and Gas Show and Exhibition, Manama, Bahrain, 10-13 March. The paper has not been peer reviewed. The Greater Burgan field began producing in 1946. It remains under primary depletion with natural waterdrive. Subsurface modeling is an integral part of reservoir management. In 2001, the first comprehensive full-field geological model was built with 65 million cells, encompassing all of the major reservoirs. A reservoir-simulation study (1.6-million-cell dynamic model) was conducted in 2003 by use of parallel-simulation technology. During the last decade, active field-development plans have resulted in major surface-facility upgrades and the drilling of +more than 300 new wells. This paper discusses scaling up the high-resolution geological model and specific problems encountered by the study team. Introduction The Greater Burgan field is in southeastern Kuwait, with an area of 320 sq miles. Fig. 1 shows the five main reservoir units of the Greater Burgan field complex: the Wara sand, Mauddud, Burgan Upper sand, Burgan Middle sand, and the Burgan Lower sand. Areally, the field is separated into three producing areas, Burgan, Magwa, and Ahmadi. Mauddud, the only carbonate reservoir in the sequence, is relatively tight and, together with the extensive Wara shale, acts as a barrier separating the Wara sand from the massive sands of the underlying Burgan formation. However, extensive faulting prevents communication between the Wara and Burgan sands. The Burgan oil field was discovered in 1938, with first oil production in 1946. Burgan has good energy support from strong natural aquifers, and after 66 years of production, most of the field is still under primary depletion. More than 1,200 wells have been drilled across the field. While drilling spacing is dense in the crestal area, well control in the flanks is relatively weak, giving rise to more geostatistical uncertainty. As the field has matured, the reservoir pressure has declined, reducing productivity. Scaling-Up Approach Because the field comprises significantly different reservoir units, a detailed geological description is required. A very-fine-scale geological model with 900 million cells was required. This geological model was constructed as a master model integrating all types of data available, and will be maintained and updated over time with new data from drilling, production, and other activities. For dynamic modeling, the very-fine-scale geological model is too big and must be scaled up. A multiscale approach is needed for the Greater Burgan field. Several studies, including reservoir management and optimization, facilities design and planning, recovery optimization, and enhanced oil recovery, are envisaged for the field. These studies are expected to require different resolutions and different levels of reservoir-description detail. Use of a single model with the highest possible resolution for all of the studies is impractical for a field this size. Thus, each study had to formulate model-resolution requirements in accordance with the phenomena to be studied, which resulted in different scaling of the models.

Local and Global Error Models to Improve Uncertainty Quantification

In groundwater applications, Monte Carlo methods are employed to model the uncertainty on geological parameters. However, their brute-force application becomes computationally prohibitive for highly detailed geological descriptions, complex physical processes, and a large number of realizations. The Distance Kernel Method (DKM) overcomes this issue by clustering the realizations in a multidimensional space based on the flow responses obtained by means of an approximate (computationally cheaper) model; then, the uncertainty is estimated from the exact responses that are computed only for one representative realization per cluster (the medoid). Usually, DKM is employed to decrease the size of the sample of realizations that are considered to estimate the uncertainty. We propose to use the information from the approximate responses for uncertainty quantification. The subset of exact solutions provided by DKM is then employed to construct an error model and correct the potential bias of the approximate model. Two error models are devised that both employ the difference between approximate and exact medoid solutions, but differ in the way medoid errors are interpolated to correct the whole set of realizations. The Local Error Model rests upon the clustering defined by DKM and can be seen as a natural way to account for intra-cluster variability; the Global Error Model employs a linear interpolation of all medoid errors regardless of the cluster to which the single realization belongs. These error models are evaluated for an idealized pollution problem in which the uncertainty of the breakthrough curve needs to be estimated. For this numerical test case, we demonstrate that the error models improve the uncertainty quantification provided by the DKM algorithm and are effective in correcting the bias of the estimate computed solely from the MsFV results. The framework presented here is not specific to the methods considered and can be applied to other combinations of approximate models and techniques to select a subset of realizations.

The use of GIS-based 3D geological tools to improve hydrogeological models of sedimentary media in an urban environment

A software platform was developed to facilitate the development of 3D geological models of sedimentary media for hydrogeological modelling, especially for urban environments. It is composed by a geospatial database and a set of tools that enable the user to perform an accurate stratigraphic analysis. The geospatial database is used for the management of a large amount of different data types coming from different sources (geophysical logs, borehole logs, hydraulic tests, etc.). Its structure allows us to store accurate and very detailed geological borehole-log description that can be straightforwardly generalized and further upscaled. The set of stratigraphic analysis instruments, working within a Geographical Information System (GIS) environment, has been set up to facilitate the geological data interpretation. Detailed stratigraphic columns of the selected boreholes can be generated using customized queries. Creating automatically a geological profile is further possible by displaying the boreholes lithological columns and the geophysical and geotechnical field-tests’ results together with the defined stratigraphic units. Based on an interactive analysis environment is created, where the user is able to analyze and to define the possible existing correlation surfaces, units, and faults. The obtained information represented by the geological units/subunits can be then converted within a 3D environment. The resulted 3D features could be used within the same GIS environment or by external software packages for further stochastic analysis or to build up 3D geological and hydrogeological models. Starting from an accurate and very detailed geological description, the software allows us to represent in three dimensions (3D) the heterogeneity of the sedimentary media and their spatial distribution. Thus, it shows how connectivity implemented into hydrogeological models among the different sedimentary bodies plays an important role. Results are shown consisting in a case study located in the Besos River Delta, in the metropolitan area of Barcelona, on the Mediterranean coast in NE Spain.

Multidomain Data and Modeling Unlock Unconventional Reservoir Challenges

Technology Update Completion strategy and hydraulic fracture stimulation are important keys to economic success in low- permeability and unconventional reservoirs such as tight sand and shale. Therefore, engineering workflows in unconventional reservoirs need to focus on completion and stimulation optimization, just as they do well placement and spacing. The primary obstacles associated with optimizing completions in these reservoirs have been the absence of hydraulic fracture models that properly simulate the complex fracture propagation common in many reservoirs, the lack of efficient methods to create discrete reservoir simulation grids to rigorously model hydrocarbon production from complex hydraulic fractures, the lack of automated fracture treatment staging algorithms, and the lack of ability to efficiently integrate microseismic mapping measurements with geological and geophysical data. This article details a novel approach for enabling efficient multistage completions, new complex fracture models, unstructured gridding-based reservoir simulation, and a comprehensive integrated workflow developed within single reservoir-centric stimulation design software. Though primarily focused on unconventional reservoirs, this efficient full-cycle seismic-to- simulation workflow is applicable also for conventional reservoirs. Seismic-to-Simulation Through Stimulation In recent years, an increasing amount of hydrocarbons in North America have been produced from unconventional reservoirs, with a similar trend expected worldwide. The International Energy Agency projects the hydrocarbon reserves in unconventional reservoirs to be as high as 8 trillion BOE. Most of these low-permeability reservoirs must be hydraulically fractured to produce. In unconventional reservoirs, stimulation is the key step in the seismic-to-simulation workflow. For unconventional reservoirs, detailed reservoir characterization plays a fundamental role in completion design, affecting the staging strategy, location of perforations or fracture ports, and stimulation design. Properly modeling the interaction of induced fractures with the rock fabric and coupling the hydraulic fracture geometry and conductivity with subsequent well performance is an essential element in this comprehensive workflow. The unconventional reservoir simulations include a detailed geologic description. The modeling is focused on the well and the specifics of the completion (i.e., the hydraulic fracture treatments). In contrast, this information can be significantly scaled up for conventional reservoirs, shifting the focus to large-scale reservoir behavior (i.e., multiwell and full-field simulation models).

Characterisation of the Krechba CO2 storage site: Critical elements controlling injection performance

Abstract The In Salah CO 2 storage project in Algeria, initiated in 2004, provides a unique early-mover case study on CO 2 storage. After 5 years of operation, the project has developed a substantial storage-unit characterisation and monitoring dataset. The question we address in this paper is: which reservoir features have proven most critical in controlling the injection performance so far? This is also an important question for future CO 2 storage sites, as part of the planned global ramp-up in CCS as a greenhouse gas mitigation option. Our main findings are that structural geological and rock mechanical aspects are most critical in the early injection phase, while characterisation of the pore space, combined with the dynamically created fracture permeability, becomes more important when considering the medium to long-term effects (10–1000 years) including geochemical, fluid dynamical and geomechanical aspects. When considering the quantity and type of data that are needed to sufficiently characterise this CO 2 storage site, high quality 3D seismic proves to be highly valuable (despite its relatively high cost). For the pore space characterisation, core samples from both the reservoir and the caprock are vital in order to calibrate and properly interpret static and dynamic well data. Finally, monitoring datasets, including well-head gas and tracer data, time-lapse seismic data, and satellite (InSAR) monitoring data need to be interpreted and only bring true value when utilised with detailed geological descriptions and models of the subsurface.

Ensemble-Level Upscaling for Efficient Estimation of Fine-Scale Production Statistics

Summary Upscaling is often needed in reservoir simulation to coarsen highly detailed geological descriptions. Most existing upscaling procedures aim to reproduce fine-scale results for a particular geological model (realization). In this work, we develop and test a new approach, ensemble-level upscaling, for efficiently generating up-scaled two-phase flow parameters (e.g., upscaled relative permeabilities) for multiple geological realizations. The ensemble-level upscaling approach aims to achieve agreement between the fine-and coarse-scale flow models at the ensemble level, rather than realization-by-realization agreement, as is the intent of existing upscaling techniques. For this purpose, flow-based upscaling calculations are combined with a statistical procedure based on a cluster analysis. This approach allows us to compute numerically the upscaled two-phase flow functions for only a small fraction of the coarse blocks. For the majority of blocks, these functions are estimated statistically on the basis of single-phase velocity information (attributes), determined when the upscaled single-phase parameters are calculated. The procedure is designed to maintain close correspondence between the cumulative distribution functions (CDFs) for the numerically computed and statistically estimated two-phase flow functions. We apply the method to 2D synthetic models of multiple realizations for uncertainty quantification. Models with different geological heterogeneity and fluid-mobility ratios are considered. It is shown that the method consistently corrects the biases evident in primitive coarse-scale predictions and can capture the ensemble statistics (e.g., P50, P10, P90) of the fine-scale results almost as accurately as the full flow-based upscaling procedures but with much less computational effort. The overall approach is flexible and can be used with any combination of upscaling procedures.

Masaya, the “Mouth of Hell”, Nicaragua: Volcanological interpretation of the myths, legends and anecdotes

Nicaragua's conquest started only 30years after Christopher Columbus arrived to America in 1492. At that moment the Masaya and Momotombo volcanoes were erupting simultaneously. The former was the first permanent lava lake observed by Europeans, and this produced a strong impression and interest in it. For more than a century there was great controversy over the nature of this phenomenon. Some people believed that it was the Mouth of Hell, whereas others could greedily see in the lava a source of gold or silver. This fact led to many attempts trying to prove it. In this paper, aboriginal myths about the volcano are described as well as different ideas and “supported evidence” given by the Spaniards regarding whether it was or not indeed the Mouth of Hell. Moreover, the first detailed geological descriptions are exposed as well as interesting interpretations found in the chronicles. It is also narrated the first descent into the volcano's mouth to extract samples of that “gold”, a real exploit for that time. From these descriptions, a volcanological interpretation is proposed, which is a contribution to the understanding of the eruptive history and evolution of the Masaya volcanic complex, one of the largest, shallow magma chamber systems in Central America.

Investigator Group Expedition 2006: Cainozoic Sediments on Flinders Island, South Australia: Description, Age and their Implication for Diamond Exploration

Diamond exploration techniques including geophysics, remote sensing, sampling, geochemistry, mapping, drilling, and exploration expertise were applied to Flinders Island, considered highly prospective for diamonds. Kimberlite indicator grains, predominantly chromites, were recovered from both drill core and sludge samples. Over 900 surface heavy mineral samples were collected to the end of 2007 and a wide range of kimberlite indicator minerals have been recovered, including chromite, pyrope, diopside, picroilmenite, diamond, phlogopite, forsterite and orthopyroxene, with the highest concentration around Gem Pan. The age of the sediments and depositional environments were assigned on palynological evidence. For the first time a detailed geological description of Cainozoic sediments is provided for Flinders Island, including a new stratigraphic unit which has been formally named Flinders Island Sand. Five anomalous indicator mineral zones have been identified and the analysis of mineral grains appears to favour a kimberlitic origin. Mineralogical examination of the indicator minerals show that the grains are relatively fresh and have not been transported far from the source. The kimberlitic source still remains undiscovered, but indicator minerals recovered from analysed samples indicate an age of Miocene or older.