Catálogo de publicaciones - revistas

<jats:p>Although pore geometry plays an important role in carbonates rock physics modeling, few studies have been done on its analytic relationship with other pore space properties like pore space stiffness. We propose an analytical workflow based on the differential effective medium (DEM) to estimate the elastic properties of carbonate rocks. Then, the validity of our results is cross-checked with the Xu and Payne model on a real carbonate dataset. This workflow establishes a direct and quantitative link between the pore geometry of carbonate rock with its other pore space properties such as Biot's coefficient and pore space stiffness. This relationship can be, furthermore, utilized in defining rock physics templates (RPTs) to investigate the role of pore geometry on the rock elastic properties. Furthermore, we extended the Biot-Gassmann-Krief (BGK) model through our proposed workflow by establishing a theoretical framework to relate the main components of the BGK model to the pore geometry usually estimated in the laboratory or empirically. This can help to investigate the impact of fluid substitution on each of these main components. Our investigation suggests that the higher the Biot and Gassmann coefficients, the rock is more sensitive to fluid substitution. Moreover, this analytical workflow has been employed to examine the role of selecting different rotational spheroids (i.e., oblate and prolate) on the modeled velocities. Our results show that the modeled velocities depend on this selection in a way that prolate pores are less sensitive to the variations in their pore aspect ratio compared with the oblate pores.</jats:p>

<jats:p>A 3D subsurface structural model was built in a zone of the greater Bay du Nord Area, Flemish Pass Basin, offshore Newfoundland and Labrador, to carry out a post-drilled, fault-seal analysis in a multi-rift, geological complex setting; aiming to test fault-seal predictions, calibrate computed static fault zone attributes and estimate hydrocarbon contact depths.</jats:p> <jats:p>Hydrocarbon exploration campaigns in the greater Bay du Nord Area have primarily targeted rotated fault blocks, which often exhibit structural segmentation and compartmentalisation. A comprehensive approach that combines empirical and deterministic methods for static fault-seal analysis has been implemented. This approach provides insights into open, base, and tight fault-seal scenarios, aiding prospect evaluation in this region. Notably, Shale Gouge Ratios (SGRs) within the range of 16% to 25% serve as a crucial indicator of the transition between fault-rock sealing and non-sealing fault segments. Furthermore, it is emphasised the critical role of hydrodynamics when calibrating or evaluating fault sealing properties.</jats:p> <jats:p>In areas like the Greater Bay du Nord region, characterised by complex geology, it is imperative to regularly update fault-seal models. These updates should align with the availability of new subsurface data, comprehensive analyses, and an improved understanding of the petroleum system.</jats:p> <jats:p content-type="thematic-collection"> <jats:bold>Thematic collection:</jats:bold> This article is part of the Fault and top seals 2022 collection available at: <jats:ext-link xmlns:xlink="http://www.w3.org/1999/xlink" ext-link-type="uri" xlink:href="https://www.lyellcollection.org/topic/collections/fault-and-top-seals-2022">https://www.lyellcollection.org/topic/collections/fault-and-top-seals-2022</jats:ext-link> </jats:p>

<jats:p>The evaluation of seal in conventional stratigraphic and structural traps requires the characterisation of the capillary top seal to assess the capacity to hold a hydrocarbon column. Typically, this seal analysis addresses the static seal and does not consider the role that hydrodynamics (the flow of water into or out of the shale seal) may play in influencing the seal capacity. Although possessing extremely low permeability, shale seals are not perfect seals and water can move through them under an imposed hydraulic gradient. Likewise, water can flow through trapped hydrocarbon columns even though relative permeabilities can be very low (Teige et al., 2005). The impact of this flow on the capillary seal capacity can, in theory, be quite profound and should be considered in seal analysis workflows. This paper revisits the Manzocchi &amp; Childs (2013) model for hydrodynamic effects on capillary seals and employs it directly in real-world trap analysis. The implementation of this model is described, and a workflow developed to incorporate the impact of hydrodynamics into column height prediction. The technique is applied to several known over-pressured fields from the Norwegian continental shelf to evaluate its applicability. Preliminary results from Monte Carlo modelling are promising and appear to offer some agreement between the observed column heights and the predicted hydrodynamic seal-controlled columns, dependant on the parameterisation used. Further testing is ongoing, but the methodology should be considered for routine application, particularly in exploration prospect evaluation. The impact of hydrodynamics on seal capacities should not be discounted.</jats:p> <jats:p content-type="thematic-collection"> <jats:bold>Thematic collection:</jats:bold> This article is part of the Fault and top seals 2022 collection available at: <jats:ext-link xmlns:xlink="http://www.w3.org/1999/xlink" ext-link-type="uri" xlink:href="https://www.lyellcollection.org/topic/collections/fault-and-top-seals-2022">https://www.lyellcollection.org/topic/collections/fault-and-top-seals-2022</jats:ext-link> </jats:p>

<jats:p>Natural fractures are pervasive in southern Sichuan Basin marine shales, China, and provide a desired opportunity to understand subsurface fracture network in shale reservoirs. Based on cores and electrical imaging logs from vertical and horizontal petroleum wells in southern Sichuan Basin, four types of natural fractures are identified in terms of orientation, size, filling properties, and spatial distribution. The uncemented bed-parallel shear fracture is developed at or in the vicinity of the mechanical interfaces and inclined to present in shale layers with dip angles greater than 12°. The cemented bed-parallel fracture is characterized with crack-seal texture marked by multiple bands of fibrous cement, and its intensity decreases upwards and shows a positive relation with the TOC values. The uncemented bed-oblique fracture is barely developed, and bears limited open space. The cemented bed-oblique/perpendicular fracture is the most developed fracture type and distributed on a regional scale with a pattern of two systematic sets. The results imply that these shale fractures could be formed sequentially by local and regional tectonic deformation, and by abnormally high-pressure. Most natural fractures cannot contribute to reservoir storage or efficiently enhance its permeability yet can act as planes of weakness and be potentially reactivated during hydraulic fracture treatments.</jats:p>

<jats:p> Reservoir quality in carbonates is influenced by various factors, such as depositional environment, burial history, and diagenesis processes. Understanding these geological heterogeneities is essential for successful petroleum exploration. This study characterizes Brazilian pre-salt reservoirs and aims to understand how their heterogeneity impacts reservoir quality. We analyzed carbonate samples from the Barra Velha Formation (Santos Basin) through an integration of petrographic and core plug descriptions, petrographic facies characterization, porosity and permeability measurements, and image analysis to identify the principal controls on porosity and permeability, pore size distribution, and groups with similar petrophysical properties using the Hydraulic Flow Unit (HFU) concept. Five facies groups were recognized: Spherulitestone (F1); Shrubstone (F2); Intraclastic Grainstone (F3); Intraclastic Packstone, Spherulitestone with mud and Shrubstone with mud (F4); Shrub-Spherulite Intercalations and Bioclastic Grainstone (F5). The analysis of porosity and permeability showed that their variations are associated with pore type and cementation rate. Greater contribution of inter-aggregate, interparticle, and vugular porosity, combined with a reduced amount of cement, results in higher porosity and permeability, but the increase of cement tends to reduce the porosity and permeability. Among the facies groups, F2 and F3 exhibited the best porosities and permeabilities, followed by F1, F4, and F5. From image analysis, small pores (1.5 x 10 <jats:sup>-5</jats:sup> to 0.01 mm²) are the most frequent in all rocks. However, these small pores contributed significantly to total porosity only in F4 and some samples of F3. For F2 and F3, the large pores (from 0.01 mm² to a maximum of 19.62 mm²) are the main contributors, while F5 has a homogeneous contribution. Lastly, the data were grouped into 5 HFUs. HFU1 and HFU2 represent the zones with the best reservoir quality, primarily composed of F2 and F3. </jats:p>

<jats:p>Optimizing unconventional field development requires simultaneous optimization of well spacing and completion design. However, the conventional practice of using cross plots and sensitivity analysis via Monte Carlo simulations (MCS) for independent optimization of well spacing and completion design has proved inadequate for unconventional reservoirs. This is due to the inability of cross plots to capture non-linear cross-correlations between parameters affecting hydrocarbon production, and the computational expense and difficulty of Monte Carlo simulations. Recently, automated machine learning (AutoML) workflows have been used to tackle complex problems. However, applying AutoML workflows to engineering problems presents unique challenges, as achieving high accuracy in forecasting the physics of the problem is crucial. To address this issue, a new physics-informed AutoML workflow based on the TPOT open-source tool developed that guarantees the physical plausibility of the optimum model while minimizing human bias and uncertainty. The workflow has been implemented in a Marcellus Shale reservoir with over 1,500 wells to determine the optimal well spacing and completion design parameters for both the field and each well. The results show that using a shorter stage length (SSL) and a higher sand-to-water ratio (SWR) is preferable for this field, as it can increase cumulative gas production by up to 8%. Additionally, it is observed that fifty-percentile cumulative gas predictions are in close agreement with actual field productions.</jats:p> <jats:p content-type="thematic-collection"> <jats:bold>Thematic collection:</jats:bold> This article is part of the Digitally enabled geoscience workflows: unlocking the power of our data collection available at: <jats:ext-link xmlns:xlink="http://www.w3.org/1999/xlink" ext-link-type="uri" xlink:href="https://www.lyellcollection.org/topic/collections/digitally-enabled-geoscience-workflows">https://www.lyellcollection.org/topic/collections/digitally-enabled-geoscience-workflows</jats:ext-link> </jats:p>

<jats:p>Former coal mines hosted in Upper Carboniferous silt- and sandstones in the Ruhr Basin, NW Germany, are currently examined for post-mining applications (e.g., geothermal energy) and are also important tight-gas reservoir analogs. Core material from well Pelkum-1, comprising Westphalian A (Bashkirian) delta deposits, was studied. The sandstones and siltstones are generally tight (mean porosity 5.5 %; mean permeability 0.26 mD). Poor reservoir properties primarily result from pronounced mechanical compaction (mean COPL 38.8 %) due to deep burial and high contents of ductile rock fragments. Better reservoir properties in sandstones (&gt; 8 %; &gt; 0.01 mD) are due to (1) lower volumes of ductile grains (&lt; 38 %) that deform during mechanical compaction and (2) higher volumes in feldspar and unstable rock fragments. During burial these form secondary porosity (&gt; 1.5 %) resulting from acidic pore water from organic matter maturation. Still, sandstones with enhanced porosities only show a small increase in permeability since authigenic clays (i.e., kaolinite and illite) or late diagenetic carbonates (i.e., siderite and ferroan dolomite/ankerite) clog secondary porosity. Quartz cementation has a minor impact on reservoir properties. Evaluating the Si/Al ratio can be a suitable proxy to assess grain sizes and may be a convenient tool for further exploration.</jats:p> <jats:p content-type="supplementary-material"> <jats:bold>Supplementary material:</jats:bold> <jats:ext-link xmlns:xlink="http://www.w3.org/1999/xlink" ext-link-type="uri" specific-use="dataset is-supplemented-by" xlink:href="https://doi.org/10.6084/m9.figshare.c.7003156">https://doi.org/10.6084/m9.figshare.c.7003156</jats:ext-link> </jats:p>

<jats:p>In this study, we use the concept of inverse rock physics modelling to analyse reservoir properties of the Kanywataba Exploration area and with focus on their lateral distribution away from the Kanywataba well. The procedure employs rock physics models calibrated for the basin constrained by seismic inversion data where also non-uniqueness and data error propagation issues are taken into account. Both seismic and well log datasets are used in the data calibration. The procedures enable us to obtain the most likely estimate mean, weighted mean and posterior mean of the reservoir properties. We obtain a good match between measured and modelled porosity values. Misfit between observed and predicted lithology is mainly attributed to the uncertainties in defining the correct mineral properties. The integrated approach reveals that high porosities correlates with low clay volumes, furthermore, indicating two distinct reservoir units in the basin interpreted as Oluka and Kakara Formations. Fluid saturation data were less successfully predicted, but was most probably a result of lack of real saturation logs for use in the calibration of rock physics model, instead, predicted saturation logs based on Archie's law were used in the calibration process. This analysis is first of its kind in this basin and therefore exhibits high level of novelty in reservoir property determination of this area.</jats:p>

<jats:p>In this study Jurassic-Paleogene strata were investigated to understand the litho-biostratigraphic framework and hydrocarbon source rock potential of various stratal packages. Biostratigraphic controls were used to establish the chronostratigraphic framework of Jurassic-Paleogene strata in the area. The Lower Jurassic (Hettangian) clastics saw an uconformity during Sinmurian-Pliensbachian, while the Lower Jurassic (Toracian) – Middle Jurassic (Bajocian) clastic-carbonate mixed strata is also separated by a Bathonian Unconformity from the Middle Jurassic (Callovian)-Upper Jurassic (Tithonian) carbonate sequence. The Upper Jurassic Oxfordian strata are missing while the Upper Jurassic (Kimmeridgian)- Lower Cretaceous (Velanginian) glaucoconatic sandstone-clays are the conformable sequences. The Lower- Cretaceous (Hauterivian)-Upper Cretaceous (Turonian) clastics is a conformable sequence which is separated by a Coniacian-Santonian unconformity from the Upper Cretaceous (Campanion) pelegic carbonates. The Cretaceous-Tertairy Boundary is marked by laterites while the Paleocene (Thanetian) sequence is represented by a shale and sandstone dominated sequence. The Paleocene (Thanetian)-Early Eocene (Ilerdian) siliciclastic-carbonates mixed sequence marks the last episode of Tethyan sedimentattion. Total Organic Content (TOC), organic petrography and Rock Eval Pyrolysis (REP) techniques were used to evaluate the hydrocarbon source rock potential, kerogen type, level of maturity of the hydrocarbons. The majority of studied samples show the occurrence of type IV kerogen. However, the Middle Jurassic (Callovian)-Upper Jurassic (Tithonian) carbonate sequence of the Samana Suk Formation, the Kimmeridgian-Velanginian Chichali Formation, the Paleocene (Thanetian) sequence of the Hangu Formation, and Paleocene (Thanetian)-Early Eocene (Ilerdian) Patala Formation confirms the Type III kerogen, poor-fair source rock quality, immature-mature, gas-oil prone indigenous hydrocarbon occurrence in the region.</jats:p>

<jats:p>Understanding the genesis and relationships among oil and gas accumulations is of prime importance in exploration and development programs. This will not only help better identify and delineate petroleum systems, but also aid in evaluating seals – one of the most critical elements in petroleum systems. Integrating geochemistry and pressure-volume-temperature (PVT) data of reservoir fluids offer tools for the assessment of fault and top seal integrity. Examples from fields at different levels of delineation, development and management from different Paleozoic and Mesozoic basins in the Middle East are discussed to demonstrate the role of fluid geochemistry in aiding the evaluation of top, lateral and fault seal integrity, and in providing insights into the sealing and buffering effects of reservoir heterogeneity on hydrocarbon fluid flow. Examples discussed include (1) detection of petrophysical sealing using PVT fluid composition data, (2) geochemical detection of partial sealing, (3) the development of top seal by solid reservoir bitumen immediately below a regional unconformity, (4) geochemical recognition of possible strike-slip fault seal, and (5) geochemical detection of fault-controlled reservoir compartmentalisation in a field at an appraisal stage where PVT data are limited or inconclusive.</jats:p> <jats:p content-type="thematic-collection"> <jats:bold>Thematic collection:</jats:bold> This article is part of the Fault and top seals 2022 collection available at: <jats:ext-link xmlns:xlink="http://www.w3.org/1999/xlink" ext-link-type="uri" xlink:href="https://www.lyellcollection.org/topic/collections/fault-and-top-seals-2022">https://www.lyellcollection.org/topic/collections/fault-and-top-seals-2022</jats:ext-link> </jats:p>