141 results found
An S, Wenck N, Manoorkar S, et al., 2023, Inverse Modeling of Core Flood Experiments for Predictive Models of Sandstone and Carbonate Rocks, Water Resources Research, Vol: 59, ISSN: 0043-1397
Field-scale observations suggest that rock heterogeneities control subsurface fluid flow, and these must be characterized for accurate predictions of fluid migration, such as during CO2 sequestration. Recent efforts characterizing multiphase flow in heterogeneous rocks have focused on simulation-based inversion of laboratory observations with X-ray imaging. However, models produced in this way have been limited in their predictive ability for heterogeneous rocks. We address the main challenges in this approach through an algorithm that combines new developments: a 3-parameter capillary pressure model, spatial heterogeneity in absolute permeability, improved image processing to capture more experimental data in the calibration, and the constraint of history match iterations based on marginal error improvement. We demonstrate the improvements on two sandstones and three carbonate rocks, with varying heterogeneity, some of which could not be previously modeled. The algorithm results in physically representative models of the rock cores, reducing non-systematic error to a level comparable to the experimental uncertainty.
Lindsay C, Braun E, Berg S, et al., 2023, Core analysis in a changing world – how technology is radically benefiting the methodology to acquire, the ability to visualize and the ultimate value of core data, Geological Society, London, Special Publications, Vol: 527, Pages: 43-58, ISSN: 0305-8719
<jats:title>Abstract</jats:title> <jats:p>Core analysts principally study the storage, flow and saturation properties of porous rocks and sediments. Some of the derived parameters are specific to hydrocarbon production but many have commonality with other subsurface disciplines such as hydrology and soil science. Traditional core analysis involves direct physical experimentation on core plugs to derive a range of parameters used as calibration for conventional well logs, and to predict hydrocarbon reserves and recovery. The mechanisms and processes for obtaining such data have evolved significantly during the last century, from the manual instruments of the mid-twentieth century to the accredited digital data collection and recording of the 1990s onwards.</jats:p> <jats:p>X-ray micro- and nano-scale computed tomography (CT) imaging led to the development of the digital rock physics subdiscipline in the early 2000s. This has subsequently allowed direct visualization of fluid flow at the pore scale, imaging the wetting phase and multiphase fluid mobility. Multiscale imaging workflows are being developed to overcome issues around heterogeneous rock and the limited field of view associated with the highest resolution X-ray CT images. Hybrid workflows, which combine digital rock physics with traditional core analysis, are becoming increasingly common to meet the challenges associated with some of the most difficult to constrain properties, such as relative permeability.</jats:p> <jats:p>At a larger scale, the recent development of multisensor core logging (MSCL) tools has allowed the cost-effective acquisition of essentially continuous high-resolution 1D, 2D and 3D datasets from both slabbed and unslabbed whole core. Often aided by artificial intelligence to manage and interpret these large physical and chemical datasets, both new and legacy core can be rapidly screened to allow representative subsampli
Wu Y, An S, Tahmasebi P, et al., 2023, An end-to-end approach to predict physical properties of heterogeneous porous media: Coupling deep learning and physics-based features, FUEL, Vol: 352, ISSN: 0016-2361
Spurin C, Roberts GG, O'Malley CPB, et al., 2023, Pore-Scale Fluid Dynamics Resolved in Pressure Fluctuations at the Darcy Scale, GEOPHYSICAL RESEARCH LETTERS, Vol: 50, ISSN: 0094-8276
Zhang Y, Jackson C, Darraj N, et al., 2023, Feasibility of Carbon Dioxide Storage Resource Use within Climate Change Mitigation Scenarios for the United States, ENVIRONMENTAL SCIENCE & TECHNOLOGY, Vol: 57, Pages: 14938-14949, ISSN: 0013-936X
Krevor S, de Coninck H, Gasda SE, et al., 2023, Subsurface carbon dioxide and hydrogen storage for a sustainable energy future, NATURE REVIEWS EARTH & ENVIRONMENT, Vol: 4, Pages: 102-118
Thaysen EM, Butler IB, Hassanpouryouzband A, et al., 2023, Pore-scale imaging of hydrogen displacement and trapping in porous media, INTERNATIONAL JOURNAL OF HYDROGEN ENERGY, Vol: 48, Pages: 3091-3106, ISSN: 0360-3199
Andrews E, Muggeridge A, Jones A, et al., 2023, Pore structure and wetting alteration combine to produce the low salinity effect on oil production, Fuel: the science and technology of fuel and energy, Vol: 332, Pages: 1-15, ISSN: 0016-2361
Low salinity water flooding is a promising enhanced oil recovery technique that has been observed, in experiments over a range of scales, to increase oil production by up to 14% in some systems. However, there is still no way of reliably predicting which systems will respond favourably to the technique. This shortcoming is partly because of a relative lack of pore scale observations of low salinity water flooding. This has led to a poor understanding of how mechanisms on the scale of micrometres lead to changes in fluid distribution on the scale of centimetres to reservoir scales. In this work, we use X-ray micro-CT scanning to image unsteady state experiments of tertiary low salinity water flooding in Berea, Castlegate, and Bunter sandstone micro-cores. We observe fluid saturations and characterise the wetting state of samples using imagery of fluid–solid fractional wetting and pore occupancy analysis. In the Berea sample, we observed an additional oil recovery of 3 percentage points during low salinity water flooding, with large volumes of oil displaced from small pores but also re-trapping of mobilised oil in large pores. In the Bunter sandstone, we observed 4 percentage point additional recovery with significant displacement of oil from small pores and no significant retrapping of oil in large pores. However, in the Castlegate sample, we observed just 1 percentage point of additional recovery and relatively small volumes of oil mobilisation. We observe a significant wettability alteration towards more water-wet conditions in the Berea and Bunter sandstones, but no significant alteration in the Castlegate sample. We hypothesise that pore structure, specifically the topology of large pores impacted recovery. We find that poor connectivity of the largest pores in each sample is strongly correlated to additional recovery. This work is the first systematic comparison of the pore scale response to low salinity flooding across multiple sandstone samples. Moreover
Zhang Y, Jackson C, Krevor S, 2022, An estimate of the amount of geological CO2 storage over the period of 1996-2020, Environmental Science and Technology Letters, Vol: 9, Pages: 693-698, ISSN: 2328-8930
The climate impact of carbon capture and storage depends on how much CO2 is stored underground, yet databases of industrial-scale projects report capture capacity as a measure of project size. We review publicly available sources to estimate the amount of CO2 that has been stored by facilities since 1996. We organize these sources into three categories corresponding to the associated degree of assurance: (1) legal assurance, (2) quality assurance through auditing, and (3) no assurance. Data were found for 20 facilities, with an aggregate capture capacity of 36 Mt of CO2 year–1. Combining data from all categories, we estimate that 29 Mt of CO2 was geologically stored in 2019 and there was cumulative storage of 197 Mt over the period of 1996–2020. These are climate relevant scales commensurate with recent cumulative and ongoing emissions impacts of renewables in some markets, e.g., solar photovoltaics in the United States. The widely used capture capacity is in aggregate 19–30% higher than storage rates and is not a good proxy for estimating storage volumes. However, the discrepancy is project-specific and not always a reflection of project performance. This work provides a snapshot of storage amounts and highlights the need for uniform reporting on capture and storage rates with quality assurance.
Spurin C, Rucker M, Moura M, et al., 2022, Red Noise in Steady-State Multiphase Flow in Porous Media, WATER RESOURCES RESEARCH, Vol: 58, ISSN: 0043-1397
Keable D, Jones A, Krevor S, et al., 2022, The effect of viscosity ratio and peclet number on miscible viscous fingering in a dele-shaw cell: a combined numerical and experimental study, Transport in Porous Media, Vol: 143, Pages: 23-45, ISSN: 0169-3913
The results from a series of well characterised, unstable, miscible displacement experiments in a Hele-Shaw cell with a quarter five-spot source-sink geometry are presented, with comparisons to detailed numerical simulation. We perform repeated experiments at adverse viscosity ratios from 1 to 20 and Peclet numbers from 104 to 106 capturing the transition from 2D to 3D radial fingering and experimental uncertainty. The open-access dataset provides time-lapse images of the fingering patterns, transient effluent profiles, and meta-information for use in model validation. We find the complexity of the fingering pattern increases with viscosity ratio and Peclet number, and the onset of fingering is delayed compared to linear displacements, likely due to Taylor dispersion stabilisation. The transition from 2D to 3D fingering occurs at a critical Peclet number that is consistent with recent experiments in the literature. 2D numerical simulations with hydrodynamic dispersion and different mesh orientations provide good predictions of breakthrough times and sweep efficiency obtained at intermediate Peclet numbers across the range of viscosity ratios tested, generally within the experimental uncertainty. Specific finger wavelengths, tip shapes, and growth are hard to replicate; model predictions using velocity-dependent longitudinal dispersion or simple molecular diffusion bound the fingering evolution seen in the experiments, but neither fully capture both fine-scale and macroscopic measures. In both cases, simulations predict sharper fingers than the experiment. A weaker dispersion stabilisation seems necessary to capture the experimental fingering at high viscosity ratio, which may also require anisotropic components. 3D models with varying dispersion formulations should be explored in future developments to capture the full range of effects at high viscosity ratio and Peclet number.
Garfi G, John CM, Rucker M, et al., 2022, Determination of the spatial distribution of wetting in the pore networks of rocks, JOURNAL OF COLLOID AND INTERFACE SCIENCE, Vol: 613, Pages: 786-795, ISSN: 0021-9797
Zhang Y, Jackson C, Zahasky C, et al., 2022, European carbon storage resource requirements of climate change mitigation targets, INTERNATIONAL JOURNAL OF GREENHOUSE GAS CONTROL, Vol: 114, ISSN: 1750-5836
Zhang Y, Jackson C, Krevor S, et al., 2022, European carbon storage resource requirements of climate change mitigation targets
<jats:p>As a part of climate change mitigation plans in Europe, CO2 storage scenarios have been reported for the United Kingdom and the European Union with injection rates reaching 75 – 330 MtCO2 yr-1 by 2050. However, these plans are not constrained by geological properties or growth rates with precedent in the hydrocarbon industry. We use logistic models to identify growth trajectories and the associated storage resource base consistent with European targets. All of the targets represent ambitious growth, requiring average annual growth in injection rates 9% – 15% from 2030-2050. Modelled plans are not constrained by CO2 storage availability and can be accommodated by the resources of offshore UK or Norway alone. Only if the resource base is significantly less, around 10% of current estimates, does storage availability limit mitigation plans. We further demonstrate the use of the models to define 2050 rate targets within conservative bounds of both growth rate and storage resource needs.</jats:p>
Garfi G, John C, Rücker M, et al., 2022, Determination of the spatial distribution of wetting in the pore networks of rocks
<jats:p>The macroscopic movement of subsurface fluids involved in CO2 storage, groundwater, and petroleum engineering applications is controlled by interfacial forces in the pores of rocks, micrometre to millimetre in length scale. Recent advances in physics based models of these systems has arisen from approaches simulating flow through a digital representation of the complex pore structure. However, further progress is limited by a lack of approaches to characterising the spatial distribution of the wetting state within the pore structure. In this work, we show how observations of the fluid coverage of mineral surfaces within the pores of rocks can be used as the basis for a quantitative 3D characterisation of heterogeneous wetting states throughout rock pore structures. We demonstrate the approach with water-oil fluid pairs on rocks with distinct lithologies (sandstone and carbonate) and wetting states (hydrophilic, intermediate wetting, or heterogeneously wetting). The resulting 3D maps can be used as a deterministic input to pore scale modelling workflows and applied to all multiphase flow problems in porous media ranging from soil science to fuel cells.</jats:p>
Harris C, Jackson SJ, Benham GP, et al., 2021, The impact of heterogeneity on the capillary trapping of CO2 in the Captain Sandstone, International Journal of Greenhouse Gas Control, Vol: 112, Pages: 1-12, ISSN: 1750-5836
A significant uncertainty which remains for CO2 sequestration, is the effect of natural geological heterogeneitiesand hysteresis on capillary trapping over different length scales. This paper uses laboratory data measured incores from the Goldeneye formation of the Captain D Sandstone, North Sea in 1D numerical simulations toevaluate the potential capillary trapping from natural rock heterogeneities across a range of scales, from cm to65m. The impact of different geological realisations, as well as uncertainty in petrophysical properties, on theamount of capillary heterogeneity trapping is estimated. In addition, the validity of upscaling trapping characteristics in terms of the Land trapping parameter is assessed. The numerical models show that the capillaryheterogeneity trapped CO2 saturation may vary between 0 and 14% of the total trapped saturation, dependingupon the geological realisation and petrophysical uncertainty. When upscaling the Land model from core-scaleexperimental data, using the maximum experimental Land trapping parameter could increase the expectedheterogeneity trapping by a factor of 3. Conversely, depending on the form of the imbibition capillary pressurecurve used in the numerical model, including capillary pressure hysteresis may reduce the heterogeneity trapping by up to 70%.
Wenck N, Jackson SJ, Manoorkar S, et al., 2021, Simulating Core Floods in Heterogeneous Sandstone and Carbonate Rocks, WATER RESOURCES RESEARCH, Vol: 57, ISSN: 0043-1397
Manoorkar S, Jackson SJ, Krevor S, 2021, Observations of the Impacts of Millimeter- to Centimeter-Scale Heterogeneities on Relative Permeability and Trapping in Carbonate Rocks, WATER RESOURCES RESEARCH, Vol: 57, ISSN: 0043-1397
Spurin C, Bultreys T, Rücker M, et al., 2021, The development of intermittent multiphase fluid flow pathways through a porous rock, Advances in Water Resources, Vol: 150, Pages: 1-7, ISSN: 0309-1708
storage and natural gas production. However, due to experimental limitations, it has not been possible to identify why intermittency occurs at subsurface conditions and what the implications are for upscaled flow properties such as relative permeability. We address these questions with observations of nitrogen and brine flowing at steady-state through a carbonate rock. We overcome previous imaging limitations with high-speed (1s resolution), synchrotron-based X-ray micro-computed tomography combined with pressure measurements recorded while controlling fluid flux. We observe that intermittent fluid transport allows the non-wetting phase to flow through a more ramified network of pores, which would not be possible with connected pathway flow alone for the same flow rate. The volume of fluid intermittently fluctuating increases with capillary number, with the corresponding expansion of the flow network minimising the role of inertial forces in controlling flow even as the flow rate increases. Intermittent pathway flow sits energetically between laminar and turbulent through connected pathways. While a more ramified flow network favours lowered relative permeability, intermittency is more dissipative than laminar flow through connected pathways, and the relative permeability remains unchanged for low capillary numbers where the pore geometry controls the location of intermittency. However, as the capillary number increases further, the role of pore structure in controlling intermittency decreases which corresponds to an increase in relative permeability. These observations can serve as the basis of a model for the causal links between intermittent fluid flow, fluid distribution throughout the pore space, and the upscaled manifestation in relative permeability.
Wenck N, Jackson SJ, Muggeridge AH, et al., 2021, Characterisation and Modelling of Heterogeneous Sandstone and Carbonate Rocks
De Simone S, Krevor S, 2021, A tool for first order estimates and optimisation of dynamic storage resource capacity in saline aquifers, International Journal of Greenhouse Gas Control, Vol: 106, Pages: 1-11, ISSN: 1750-5836
The importance of carbon capture and storage in mitigating climate change has emerged from the results of techno-economic or integrated assessment modeling, in which scenarios of future energy systems are developed subject to constraints from economic growth and climate change targets. These models rarely include limits imposed by injectivity, ultimate amounts, or the geographic distribution of storage resources. However, they could if a sufficiently simple model were available. We develop a methodology for the fast assessment of the dynamic storage resource of a reservoir under different scenarios of well numbers and interwell distance. The approach combines the use of a single-well multiphase analytical solution and the superposition of pressure responses to evaluate the pressure buildup in a multiwell scenario. The injectivity is directly estimated by means of a nonlinear relationship between flow-rate and overpressure and by imposing a limiting overpressure, which is evaluated on the basis of the mechanical parameters for failure. The methodology is implemented within a tool, named CO2BLOCK, which can optimise site design for the numbers of wells and spacing between wells. Given its small computational expense, the methodology can be applied to a large number of sites within a region. We apply this to analyse the storage potential in the offshore of the UK. We estimate that 25–250 GtCO2 can be safely stored over an injection time interval of 30 years. We also demonstrate the use of the tool in evaluating tradeoffs between infrastructure costs and maximising injectivity at two specific sites in the offshore UK.
Andrews E, Muggeridge A, Garfi G, et al., 2021, Pore-Scale X-ray Imaging of Wetting Alteration and Oil Redistribution during Low-Salinity Flooding of Berea Sandstone, ENERGY & FUELS, Vol: 35, Pages: 1197-1207, ISSN: 0887-0624
Andrews E, Muggeridge A, Jones A, et al., 2021, Pore scale observations of wetting alteration during low salinity water flooding using x-ray micro-ct
This paper describes the first pore scale in-situ observations of wetting alteration on clays during tertiary low salinity flooding. Observations in the laboratory over a range of scales show that reducing the salinity of injected water can alter the wetting state of a rock, making it more water-wet. However, there remains a poor understanding of how this alteration impacts the distribution of fluids over the pore and pore network scale and how it leads to additional oil recovery. In this work, X-ray micro-CT scanning is used to image an unsteady state experiment of tertiary low salinity water flooding in a Berea sandstone core with an altered wettability due to exposure to crude oil. Oil was trapped heterogeneously, at a saturation of 0.62, after flooding with high salinity brine. Subsequent flooding with low salinity brine led to an oil production of three percentage points. To understand the mechanisms for this additional recovery, we characterise the wetting state of the sample using imagery of fluid-solid fractional wetting and fluid pore occupancy analysis. Pore occupancy analysis shows that there is a redistribution of oil from large pores to small pores during low salinity flooding. We observe a decrease in the solid surface area covered by the oil after low salinity flooding, consistent with a change to a less oil-wetting state. Pore by pore analysis of the mineral surface area covered by the oil shows that the wetting alteration during low salinity flooding is more significant on clays which likely control the behaviour. Whilst there was only three percentage points of additional recovery during low salinity flooding, the wetting alteration led to the redistribution of 22% of oil within the rock. The success of low salinity water flooding depends on a wetting alteration and oil mobilisation as well as a pore structure which can facilitate the production of the mobilised oil.
Razak WNA, Kechut NI, Andrews E, et al., 2021, 3D Visualization of Film Flow During Three-Phase Displacement in Water-Wet Rocks via Microtomography Method
Spatial image resolution has limited previous attempts to characterize the thin film flow of oil sandwiched in-between gas and water in a three-phase fluid system This paper describes how a systematically designed displacement experiment can produce imagery to define the film flow process in a 3D pore space of water-wet sandstone rocks. We image multiphase flow at the pore scale through three displacement experiments conducted on water-wet outcrop rock with variable spreading tendencies. The experiment has been formulated to observe the relationship between fluid spreading, phase saturations, and pore-scale displacement mechanisms. We provide exhaustive evidence of the three-phase fluid configurations that serve as a proxy mechanism assisting the fluid displacement process in a three-phase system, which includes the oil sandwiches in-between water and gas, the flow of oil via clay fabrics, and the double-displacement process that generates oil and water film in 3D pore spaces. Further, we show evidence that the stable thin-oil film has enhanced the gas trapping mechanism in the water-wet rocks. We observed that the oil layer had covered the isolated and trapped gas blobs, enhancing their stability. As a result, the trapped gas in the positive and zero spreading systems is slightly higher than in the negative spreading system due to a stable oil film. We analyze the Euler characteristic of the individual fluid phases and the interface pair of the fluids during waterflooding, gas injection, and chase water flooding. The comparison of the Euler characteristic for the connected and disconnected fluid phases between three different spreading systems (i.e., positive, zero, and negative) shows that the oil layer's connectivity is highest in the positive spreading system and lowest in the negative spreading system. The oil layer in the positive spreading system is also thicker than in the negative spreading system.
Ringrose PS, Furre A-K, Gilfillan SMV, et al., 2021, Storage of Carbon Dioxide in Saline Aquifers: Physicochemical Processes, Key Constraints, and Scale-Up Potential, ANNUAL REVIEW OF CHEMICAL AND BIOMOLECULAR ENGINEERING, VOL 12, 2021, Vol: 12, Pages: 471-494, ISSN: 1947-5438
Spurin C, Bultreys T, Rucker M, et al., 2020, Real-Time Imaging Reveals Distinct Pore-Scale Dynamics During Transient and Equilibrium Subsurface Multiphase Flow, WATER RESOURCES RESEARCH, Vol: 56, ISSN: 0043-1397
Spurin C, Rücker M, Bultreys T, et al., 2020, The development of intermittent multiphase fluid flow pathways through a porous rock
Jackson SJ, Krevor S, 2020, Small-Scale Capillary Heterogeneity Linked to Rapid Plume Migration During CO<sub>2</sub>Storage, GEOPHYSICAL RESEARCH LETTERS, Vol: 47, ISSN: 0094-8276
Spurin C, Bultreys T, Ruecker M, et al., 2020, Real-time imaging reveals distinct pore scale dynamics during transient and equilibrium subsurface multiphase flow
Jackson S, Krevor S, 2020, Small-scale capillary heterogeneity linked to rapid plume migration during CO2 storage
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