Catálogo de publicaciones - revistas

<jats:p>Deformation bands are usually responsible for up to 3 orders of magnitude reduction in permeability perpendicularly to the structure planes, while the fault core represent a reduction of up to 7 orders of magnitude in cross-fault permeability, imposing large anisotropies to fluid flow. As deformation bands occur distributed along the damage zone, they impact not only the across-fault flow, but also the along-fault flow. The fault core is usually represented by fault transmissibility multipliers (TMs), along the fault planes, using well established workflows. However, there is a lack of methods to represent fault damage zones in any direction and grid cell sizes. In this context, we proposed new methods to: (1) estimate the deformation intensity in damage zones; (2) calculate their most representative value within the cell domain; (3) calculate the equivalent permeability of a cell containing oblique deformation bands. The workflow is applied to the 3D numerical model of the Santa Helena High, in Rio do Peixe Basin, NE Brazil. We performed streamline simulations in 4 models to evaluate the impact of fault damage zones and the fault core in fluid flow. Our models show that the fault core and damage zone negatively affected the performance of the reservoir.</jats:p> <jats:p content-type="supplementary-material"> <jats:bold>Supplementary material:</jats:bold> Appendix A, describing the method developed to estimate the deformation intensity in damage zones, and Appendix B, describing the method develop to calculate the equivalent permeability, are available at <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.6251469">https://doi.org/10.6084/m9.figshare.c.6251469</jats:ext-link> </jats:p>

<jats:p>Seismic velocity models have significant importance in subsurface studies, notably when applied in structurally challenging areas. In some parts of the Campos Basin, offshore Brazil, the pre-salt reservoir's overburden shows complex structures, mainly due to raft tectonism that positions laterally resulting in interspersed salt domes, carbonate rafts, and siliciclastic sediments. This work used an extensive well database in the Marlim Complex to analyze the raft seismic velocities and their related impacts on pre-salt reservoir models. Based on well data, in combination with detailed seismic interpretation, it was proposed seven alternative velocity scenarios for the rafts. The geological motivations for each scenario are discussed aiming to develop constrained depth models for pre-salt reservoirs. The depth forecast results could be tested by the drilled wells and resulting models are quantitatively compared in terms of depth predictions and gross-rock volumes. The results show that the topography of the target pre-salt reservoirs can vary considerably, even in scenarios where well and geological constraints are considered. This can impact pre-salt geological characterization and field development.</jats:p>

<jats:p> Faults play an essential role at many potential CO <jats:sub>2</jats:sub> storage sites because they can act as conduits or barriers to fluid flow. To contribute to the evaluation of the Aurora storage site in the northern North Sea, we perform a structural characterization and assessment of across-fault seals that displace the Lower Jurassic storage complex. We find that first-order faults are predominately north–south striking and west dipping, with throws greater than the thickness of the primary seal (&gt;85 m). In contrast, second-order faults have lower throws (15–50 m), and variable strike and dip directions. Due to the dip of the storage complex, injected CO <jats:sub>2</jats:sub> is likely to migrate northwards before encountering the first-order Svartalv Fault Zone on its footwall side, which juxtaposes the storage units against younger sand-rich units. However, shale gouge ratio values exceed 0.30 at the depth of the storage complex, suggesting that a fault membrane seal may be present. Furthermore, second-order NE-dipping faults create juxtaposition seals and, in places, small-scale structural traps (24–48 m) along the Svartalv Fault Zone. Overall, we suggest that faults within the Aurora storage site could provide barriers to plume migration, allowing more CO <jats:sub>2</jats:sub> to become trapped and thereby increasing the storage capacity. </jats:p> <jats:p content-type="thematic-collection"> <jats:bold>Thematic collection:</jats:bold> This article is part of the Energy Geoscience Series available at <jats:ext-link xmlns:xlink="http://www.w3.org/1999/xlink" ext-link-type="uri" xlink:href="https://www.lyellcollection.org/cc/energy-geoscience-series">https://www.lyellcollection.org/cc/energy-geoscience-series</jats:ext-link> </jats:p>

<jats:p>The geological features revealed by well production data or 4D Seismic are often neglected in data assimilation or disconnected from the geomodelling tasks through simplifications on static and dynamic data. This work provides a workflow to accurately integrate 4D seismic insights through a forward geomodelling approach and provides prior simulation models calibrated with observed dynamic data. The methodology follows four steps: (1) develop the geological model, (2) generate equiprobable geostatistical realisations based on the multiple stochastic approach, (3) apply the DLHG method (Discretized Latin Hypercube combined with Geostatistics), and (4) validate the geological consistency and uncertainty quantification using the observed dynamic data. The methodology is applied to a real turbiditic reservoir, a heavy oil field in the offshore Campos Basin, Brazil. From the 4D seismic datasets, the following data was available: (1) base survey, (2) monitor-2016, and (3) monitor-2020. The interpreted 4D seismic trends were integrated in the geological model by combining the geometrical modelling technique, for observed structural features, with the objects’ modelling approach, for the observed sand channels. The geostatistical realisations were then combined with dynamic uncertainties through the DLHG method. The quantitative validation based on the NQDS indicator showed that the generated prior simulation models encompass the observed production data. In addition, the match with observed 4D seismic data based on dRMS amplitude maps highlighted the value of adding 4D seismic information. This paper presents a successful forward modelling approach to highlight the value of 4D seismic on the calibration of simulation models prior to data assimilation.</jats:p>

<jats:p>Predicting the performance of a subsurface oil field is a large, multivariant problem. Production is controlled and influenced by a wide array of geological and engineering parameters which overlap and interact in ways that are difficult to unravel in a manner that can be predictive. Supervised machine learning is a statistical approach which uses empirical learnings from a training dataset to create models and make predictions about future outcomes. The goal of this study is to test a number of supervised machine learning methods on a dataset of oil fields from the United Kingdom continental shelf (UKCS), in order to assess whether, a) it is possible to predict future oil field performance and b), which methods are the most effective. The study is based on a dataset of 60 fields with 5 controlling parameters, (gross depositional environment, average permeability, net-to-gross, gas-oil ratio and total number of wells) and 2 outcome parameters (recovery factor and maximum field rate) for each. The choice of controlling parameters was based on a PCA of a larger dataset from a wider project database. Five different machine learning algorithms were tested. These include linear regression, robust linear regression, linear kernel support vector regression, cubic kernel support vector regression and boosted trees regression. Overall, 83% of the data was used as a training dataset while 17% was used to test the predictability of the algorithms. Results were compared using R-Squared, Mean Square Error, Root Mean Square Error and Mean Absolute Error. Graphs of predicted responses vs true (actual) responses are also shown to give a visual illustration of model performance. Results of this analysis show that certain methods perform better than others, depending on the outcome variable in question (recovery factor or maximum field rate). The best method for both outcome variables was the support vector regression, where, depending on the kernel function applied, a reliable level of predictability with low error rates were achieved. This demonstrates a strong potential for statistics-based prediction models of reservoir performance.</jats:p>

<jats:p>Mechanical properties of layered rocks are critical in ensuring wellbore integrity and predicting natural fracture occurrence for successful reservoir development, particularly in unconventional reservoirs for which fractures provide the main pathway for hydrocarbon flow. We examine rock mechanical properties of exceptionally organic-rich, immature source rocks from Jordan and understand their relationships with rock mineral composition and lithofacies variations. Four depositional microfacies were identified: organic-rich mudstone, organic-rich wackestone, silica-rich packstone, and fine-grained organic-rich wackestone. The four types exhibit various mineralogical compositions, dominated by carbonates, biogenic quartz, and apatite. Leeb hardness ranges between 288 – 654, with the highest average values in silica-rich packstone and organic-rich mudstone. The highest uniaxial compressive strength (derived from the intrinsic specific energy measured by Epslog's Wombat scratch device), compressional, and shear waves velocities were measured in organic-rich mudstones (140 MPa, 3368 m/s, and 1702 m/s, respectively). Porosity shows higher average values in organic-rich wackestones and fine-grained organic-rich wackestones (33% – 35%). Silica-rich packstone and organic-rich mudstone have brittle properties, while organic-rich wackestone and fine-grained organic-rich wackestone are ductile. High silica contents are correlated positively with brittleness. A strong hardness-brittleness correlation suggests that Leeb hardness is a useful proxy for brittleness. Our study allows a better understanding of the relationships between lithofacies, organic content and rock mechanical properties, with implications for fracking design to well completion and hydrocarbon production. Further work involving systematic sampling and a more rigorous study is still required to better understand the spatial distribution of target lithologies and their mechanical properties.</jats:p>

<jats:p> This study investigates the hydrocarbon generation and retention potential of Chang 7 organic-rich shale, with an emphasis on the producibility of retained hydrocarbons, using a sample set chosen to represent a maturity spectrum of 0.54 % to 0.9 % Ro and organic matter of type II and mixed type II-III. Based on the present-day hydrogen index (HI <jats:sub>pd</jats:sub> ), the sample sets are divided into three sections, Upper, Middle, and Lower. The three sections have a high hydrocarbons generation potential, with an average original TOC (TOC <jats:sub>o</jats:sub> ) of 12.27, 3.10, and 5.13 wt.% of which 49.39, 23.62, and 49.86 wt.% represent generative organic carbon (GOC), an original hydrogen index (HI <jats:sub>o</jats:sub> ) of 581.27, 278.05 and 586.82 HC/g rock, in the Upper, Middle, and Lower Sections, respectively. The bulk of analyzed samples exhibit moderate-high oil saturation, yet the oil crossover effect is observed only in two organic-rich samples indicating organic-rich shale-oil resource systems. The sorption capacity of organic matter controls oil retention in the Chang 7 shale system, where the oil saturation index increases with increasing maturity in the oil window until a maximum retention capacity of about 82-83 mg HC/g TOC is reached at a vitrinite reflectance of 0.8% and thereafter decreases with further maturity. </jats:p> <jats:p content-type="supplementary-material"> <jats:bold>Supplementary material:</jats:bold> [Detailed spreadsheet of the back-calculated original geochemical parameters using the mass-balance method of Jarvie (2012a)], are available at <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.6387577">https://doi.org/10.6084/m9.figshare.c.6387577</jats:ext-link> . </jats:p>

<jats:p>Drilling infill wells into a heavily depleted reservoir poses several challenges that can lead to increased time, cost and risk. Data acquisition, including gathering formation pressure data, can be severely compromised, complicating real-time decisions and pore pressure interpretation. Fracture gradients, usually constrained by data acquired outside the reservoir, need to be estimated using a different approach through a depleted reservoir. The Jasmine high-pressure high-temperature (HPHT) field in the UK Central North Sea can be used to illustrate some of these challenges and to describe some practical solutions. A qualitative approach to estimating the level of reservoir depletion from formation gas measurements has been developed for the Jasmine Field, comparing pre-depletion gas trends against those obtained during the infill drilling campaign. The methods described here to estimate depleted fracture gradients using modelled and observed stress paths coupled to the pore pressure reduction were found to fit with well observations, and have helped to inform operational decisions to manage severe lost circulation events. A strategy to acquire data in memory while drilling has proved successful and has allowed lost circulation events to be managed safely. Managed pressure drilling has opened up narrow drilling windows, and has reduced the number of hole sizes and liners required to drill these infill wells.</jats:p> <jats:p content-type="thematic-collection"> <jats:bold>Thematic collection:</jats:bold> This article is part of the Geopressure 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/geopressure">https://www.lyellcollection.org/topic/collections/geopressure</jats:ext-link> </jats:p>

<jats:p>In this study, a thermal–hydraulic–mechanical–chemical (THMC) multi-field coupling triaxial cell was used to study systematically the evolution of gas permeability and the deformation characteristics of sandstone. The effects of confining, axial and gas pressure on gas permeability characteristics were fully considered in the test. The gas permeability of sandstone decreases with increasing confining pressure. When the confining pressure is low, the variation of gas permeability is greater than that of gas permeability at high confining pressure. The gas injection pressure significantly affects the gas permeability evolution of sandstone. As the gas injection pressure increases, the gas permeability of sandstone tends to decrease. At the same confining pressure, the gas permeability of the sample during the unloading path is less than the gas permeability of the sample in the loading path. When axial pressure is applied, it has a significant influence on the permeability evolution of sandstone. When the axial pressure is less than 30 MPa, it significantly influences the permeability evolution of sandstone. At axial pressures greater than 30 MPa, the permeability decreases as the axial pressure increases. Finally, the micro-pore/fracture structure of the sample after the gas permeability test was observed using 3D X-ray CT imaging.</jats:p>