The key to understanding the clear and present threat of climate change is to realize that on the earth everything is linked to everything else in a myriad of subtle, detailed, and dynamic equilibria. Once disturbed, these equilibria change in nonlinear and surprising ways. First, I will visit Anthropocene and 140 years of global mean temperature records. I will then introduce the Earth as a complex system of interlinked systems and the miracle of stable albedo of the planet. The bulk of my lecture will be about the causes and symptoms of global heating. In particular, how exactly do GHGs cause global heating? I will focus on the radiation balance of the Sun-Earth system and the fine structure of CO2 IR absorption spectra. I will derive the most likely increment of mean global temperature per each 1 W/m2 of unequilibrated radiative forcing (RF) and per 100 ppm of CO2 in the atmosphere. I will use my own global fossil future scenario to show how burning fossil fuels will heat up the Earth. Finally, I will give a few translations from technocracy to ecology and debunk two most popular arguments by climate warming denialists. I hope to convince you that climate change is evident, but there is no point in doing more science when mainstream techno-industrial society refuses to apply its results.
Since its inception in 2009, research into Circular Carbon Economy (CCE) technology solutions has been an integral part of KAUST’s portfolio, including CO2 capture, Nature-Based Solutions, Renewable Energy and CO2 utilization. With the launch of the KAUST Circular Carbon Initiative (CCI) in 2020, we connect more deeply the different strands of our CCE research, to create a strong and well-informed network of researchers at different career stages, to identify and seek to engage missing expertise and, last but not least, to proactively contribute to the ongoing efforts of the Kingdom of Saudi Arabia and their CCE National Program.
I will discuss the current state of a pilot plant being built to demonstrate the cryogenic carbon capture technology applied to the demanding flue gas of a high efficiency natural gas fired combined cycle powerplant just coming on-line in Saudi Arabia. This pilot plant will capture 30 tonnes/day of high purity CO2 and deliver as a supercritical fluid to the user. I will discuss why we believe this is a scaleable, deployable, and affordable technology for point source carbon capture. Extending the technology to other constituents (e.g., SOx) and platforms (e.g., cement) will be discussed.
Geological carbon storage (GCS) is an important strategy to mitigate greenhouse gas emissions so that the State of California and the USA can meet their clean energy goals. This study provides a standardized procedure to evaluate CO2 storage, its risks, and incorporate uncertainties in hydrological and geomechanical parameters. We screen potential storage sites taking into account favorable storage formation characteristics, known seismic risks, and surface restrictions including sensitive habitats. Models incorporating CO2 injection and geomechanical response are then used to investigate CO2 plume migration, pressure, CO2 saturation profiles, and deformation of the earth. We take a probabilistic view of fault slip using a fault slip potential model with a distribution of geomechanical parameters. We also study the area’s historical seismicity and establish criteria to distinguish among natural and induced events. The risk of leakage is assessed using a reduced-order model, and sensitivity analysis, to estimate rates of CO2 and brine escape to drinking water aquifers through the overlying formations, existing wells, and faults. This workflow and accompanying risk assessment is illustrated using a demonstration project with 0.68 MtCO2/yr injection for 18 years and 100 years of monitoring in a saline formation in the Southern San Joaquin Basin.
The global scientific community has focused efforts on carbon capture and storage (CCS) for at least 29 years following the United Nations Framework Convention on Climate Change, which came into force on 21 March 1994. Nevertheless, despite 29 years of efforts negligible carbon storage is occurring at present. Of the ~40 gigatons of anthropogenic carbon emitted to the atmosphere in 2020, ~40 megatons of carbon, or less than 0.1% were captured and stored. Of the ~40 megatons of carbon captured and stored ~90% was through enhanced oil recovery. Life cycle analysis shows that current CO2 promoted enhanced oil recovery methods emit more CO2 that they store. The net mass of CO2 captured and stored ignoring enhanced oil recovery was on the order of 4 megatons in 2020, less than 0.01% of the corresponding anthroprogenic flux.
Much of the early scientific early effort took account of the natural carbon cycle, which has been efficient at moderating atmospheric carbon concentrations and global temperature over geologic times. Carbon dioxide is short-lived in the atmosphere. The average half-life of CO2 in the atmosphere is ~4 years. Roughly one eight of the carbon in the atmosphere circulates in and out of the oceans and in and out of the biosphere annually. The atmosphere is also a relatively small CO2 reservoir. The 800 gigatons of carbon in the atmosphere is dwarfed by the ~2,000 gigatons of carbon in the biosphere, the ~40,000 gigatons of carbon in the oceans and the >90,000,000 tons of carbon in the Earth’s crust, largely as carbonate minerals. These facts suggested the transfer of carbon from the atmosphere to one of these larger reservoirs could readily solve global warming. This led initial research into assessing forestry, increasing ocean alkalinity, and injecting carbon into the subsurface.
Relatively little was done to find industrial solutions until recently when public and government action threatened to 1) impose restrictions on and 2) provide financial motivation to limit carbon emission to the atmosphere. The potential financial rewards due have motivated the creation of hundreds of start-up companies to be created, many raising hundreds of millions of dollars. The companies commonly consist of 50% professional fundraisers, 50 percent experts in publicity, and the rest scientists and engineers. So many of these companies promise to be able to upscale to gigaton per year scales, that if such claims are to be believed global warming will soon be solved.
But can any of these claims be believed? Unlikely. Most of these start-ups have ignored basic facts of the global carbon cycle. Whereas it is cheap and easy to grow trees or seaweed, these also decompose rapidly after death liberating the captured CO2. Whereas it is easy to capture CO2 in seawater, it just as easily exsolved back into the atmosphere. What is largely ignored is the volume required for CO2 storage, which is on the order of a cubic kilometer per gigaton of carbon. This huge volume of space is likely only available in the subsurface. It is likely that it is only the major energy companies which have the expertise and political power to inject such quantities of CO2 into the subsurface. It seems, likely, therefore, that although some of the large number of CCS startup companies will make its creators rich, it the energy industry and their vast ability to uoscale, which likely holds the key to solving global warming.
This presentation analyzes ongoing hydrogen developments of the 27 member states of the European Union and the states outside this treaty-based organization. The focus of the presentation is on current policy and regulatory developments, which have been turbocharged by the war in Ukraine and Europe’s rapidly developing export relations with fossil fuel exporters. Gulf players such as Saudi Arabia are long-standing energy partners for Europe. They not only have the capacity and know-how to produce low-carbon hydrogen and ammonia, but also have the additional geopolitical and climate incentive to position themselves as reliable providers of clean energy imports for Europe. However, European policymakers and industries have yet to signal a coherent hydrogen import strategy. This presentation argues that this discord should be replaced by a coordinated European import strategy that balances renewable-based and low-carbon hydrogen. This should be based on a grounded assessment of production and demand capacities across Europe and of export partners such as Saudi Arabia.
As a collaboration between industry and academia, The Archie Initiative uses open-source, engineering-based models, informed by public and proprietary data sources, to estimate energy supply chain carbon intensities worldwide. For crude oil, the country-level carbon intensities, from well to pump, range from ~50 to 200 kg of carbon dioxide equivalent (CO2e) per barrel. This wide range is a function of the many sources and uses of crude oil from one country to another. While fossil fuel combustion accounts for most of its life cycle emissions, producing, transporting, and refining crude oil into fuels such as gasoline and diesel accounts for ~15 to 40% of the "well-to-wheels" life-cycle greenhouse gas (GHG) emissions of transportation fuels. Reducing emissions from petroleum production is particularly important, as current transport fleets mainly depend on liquid petroleum products. The Archie Initiative models the well-to-pump CI of most major active oil fields worldwide, identifying significant drivers of these emissions. The CI estimates in 2021 cover over 4,100 oil fields in 96 countries, representing 92% of global crude oil production. The Archie Initiative also accounts for oil transport, refining, and production activities as part of the supply chain analysis. The transport CI varies from 1 to 37 kg CO2e per barrel of oil delivered to the refinery entrance depending on pipeline and ocean vessel design requirements, transport distances, and supporting processes. The Archie Initiative accounts for the complexity and product slate of more than 460 refineries and shows that the global refining CI ranges from 8 to 78 kg CO2e per barrel. Data-driven CI estimates can potentially encourage prioritizing lower-CI crude oil sourcing, point to methods to manage crude oil CI and enable governments and investors to avoid "locking in" the development of higher-CI resources. However, future progress in this direction will rely on improved reporting and increased transparency about oil-sector emissions.
The amount of digital subsurface and geoscience data has grown exponentially over the past few decades with many companies and government organizations dealing with rapidly growing Petabyte-scales of data. On the other hand, hardware, storage solutions, technical applications and data management utilities have not kept up with these rapid developments. This has resulted in a big gap and hampers the use of AI and data-driven workflows in complex subsurface projects, be it in hydrocarbon exploration and development, geothermal energy projects, CCS, H2-exploration & storage and the search for nuclear waste sites, but also integrated scientific research programs.
The Middle and Upper Jurassic strata of the eastern Arabian Plate host some of the world’s most prolific hydrocarbon reservoirs and are part of one of the best studied sedimentary basins on earth. Their economic relevance led to the acquisition of extensive subsurface data sets (seismic, wells, core), whereas the presence of world-class outcrops in the surrounding mountain chains of Saudi Arabia, Oman, Iran and Iraq provide valuable outcrop analogs. Despite this wealth of information, the tectono-stratigraphic history of the Middle and Upper Jurassic deposits at the scale of the Arabian Plate is only documented in a fragmentary way in the literature. This is due to the fact that the subsurface information has mostly remained confidential property of oil companies and state institutions, and that many of the published studies have only a limited geographical coverage, constrained to individual countries and oil company concessions. In this presentation we will bring together the information of a number of local studies published over the last 30 years, which, together, provide a robust database for a regional tectono-stratigraphic synthesis.
This synthesis documents the evolution from mixed siliciclastic-carbonate ramps to the creation and partial asymmetrical infill of large intrashelf basins along a master-transect of 2000 km from Northern Iraq to the ocean margin in Oman. It will be demonstrated how this type of regional synthesis allows to address fundamental sedimentological and stratigraphic questions such as: what were the tectonic controls? what are the drivers behind the creation of intrashelf basins? what was the composition and timing of their infill? and how did the carbonate factories evolve? In addition, since the Arabian Plate was tectonically stable for most of this time interval, these rock successions provide a good proxy for eustatic sea level fluctuations.
Carbon capture and storage (CCS) technologies are needed as a crucial technology for Saudi Arabia to reach its net-zero goal by 2060. This study represents the first comprehensive evaluation of both industrial CO2 emissions and geological CO2 storage capacities in the sedimentary basins of Saudi Arabia. Our study relied on collecting and analyzing hundreds of data sets from public domain. We evaluated the suitability and storage capacity of 17 basins and sub-basins throughout the country for CO2 storage in deep saline aquifers as well as depleted oil and gas reservoirs using the CO2-SCREEN tool. Our evaluation shows that the most suitable basins are located in the eastern part of the country, including the Eastern Arabian Basin and the Interior Homocline-Central Arch. On the other hand, western Saudi Arabia is characterized by limited favorable basins, including the Umm Luj, Yanbu, and Jeddah coastal basins. At the 50th percentile uncertainty, the estimated total effective storage capacities in deep saline aquifers, depleted oil reservoirs, and non-associated gas reservoirs are ~432, ~5, and ~9 gigatons (Gt), respectively. Large storage capacity is located in the eastern suitable basins that is high enough to store the major CO2 emissions located near Riyadh and along the east coast for a thousand of years. In contrast, relatively small storage capacity in the western coastal basins is available for storing the major CO2 emissions near Yanbu and Jeddah. The estimated industrial CO2 emissions and geological CO2 storage capacities in this study provide critical information for policymakers and industry leaders seeking to address carbon emissions in Saudi Arabia.
The main purpose of basin modelling is to simulate the burial and thermal history of a sedimentary basin and apply the derived Pressure/Temperature/Rock Properties data to simulate HC generation, HC expulsion and HC migration.
Initially developed as a 1D tool to simply assess maturity levels at some sparse points in a basin, with the availability of 3D models since the mid 90’ it became an integrated tool to assess conventional Petroleum Systems.
With the advent of the Unconventional revolution, the basin modelling toolbox didn’t need fundamental adjustments, the workflow simply needed to be switched from a focus on expulsion/migration towards retention/expulsion.
With the Energy Transition, basin modelling will still be needed to support the conventional and unconventional oil&gas exploration for years to come but also did already started to support initial geothermal investigations of sedimentary basin as well as CCS.
For both the Geothermal and the CCS applications, the derivation of present day rock properties, thermal and pressure field are the main requirements.
The presentation will cover Arabian plate controls on heat flow and the challenges to derive sealing data.
Governments and companies around the world have set ambitious targets to reduce CO2 emissions by 2030. Carbon Capture and Storage plays a crucial role in achieving these goals, and thus workflows for identifying underground storage locations and assessing the risk and uncertainty associated with subsurface CO2 storage are becoming necessary. Fortunately, this newly emerging sector of the industry can greatly benefit from well established workflows and technologies of the oil and gas sector which need only minor adjustments to become fully suitable to tackling CO2 storage challenges.
Fine-grained sediments, mudrocks and shales have unique fabric and pore topology that reflect their mineral composition and formation history. Atomic-scale clay-clay electrical interactions coexist with the micron-scale mechanical interactions between silicate and carbonate grains, clay tactoids and organic matter; layering adds cm-scale vertical heterogeneity. The resulting strata define the performance of km-scale natural and engineering systems including oil and gas reservoirs and the long-term geological storage of CO2 and nuclear waste.
We conduct multi-scale studies to gain new insights into the behavior of fine-grained sediments, mudrocks and shales. Atomic-scale studies show the effect of isomorphic substitution and adsorbed water molecules on clay tactoid stiffness. Pore-scale analyses based on SEM images reveal spherical pores in organic matter and elongated/aligned pores bound by clay tactoids. Particle-scale simulations capture fabric evolution including tactoid alignment facilitated by organic matter deformation to accommodate the evolving mineral fabric, effectively giving rise to shale fissility. Layer-scale simulations help understand the brittle-to-ductile transition, and multi-strata studies elucidate the evolution of fracture networks during tectonism.
Energy Geotechnics includes several applications related to the recovery and storage of energy from and into the ground, energy transportation, and the management of waste and carbon dioxide generated from energy use. These applications often involve the need to consider the behaviour of the involved clayey geomaterials under complex - and often extreme – conditions, involving a series of coupled mechanical, hydraulic, chemical and thermal phenomena. The presentation discusses advances on the development of experimental, numerical and constitutive modelling tools for analysing the complex series of couplings involved in those applications.
Understanding flow and reactive transport in porous material is of crucial importance for a wide range of engineering applications, including Carbon Capture and Storage, geothermal energy, construction materials and fuel cells. Numerical simulation can be a fantastic tool to investigate and optimise these processes and, at the application scale, modelling rely on the definition of effective porous media properties (e.g., porosity, permeability, diffusivity). However, the mechanisms (e.g., convection, diffusion, reaction) that control the processes occur at the pore-scale, i.e. in the void between the solid bodies. Pore-scale modelling can be employed to bring insights into the mechanisms and estimate accurate effective porous media properties for large scale modelling by performing simulations on Representative Elementary Volume (REV). However, most porous materials relevant to the energy transition are multiscale, i.e., they have a range of porous structures of different sizes (e.g., nanopores, micropores, vugs and fractures) and it’s the way these structures interact between each other that ultimately controls processes. Because the REV of large pore structures such as vugs and fractures are way too large to perform simulation at a resolution high enough to represent accurately nanopores and micropores, estimating porous media properties for multiscale material require the development of a multiscale workflow. In this talk, I will present recent advances in developing such a workflow, show applications to flow, reactive transport and heat transfer, and discuss the challenges of extending this to multiphase flow.
It is a well-established fact that fluids affect the mechanical behavior of rocks and a many experimental evidences have been reported so far describing their impact over relevant properties such us UCS, brittleness, etc. In the case of cracking and crack propagation the role of fluids has been commonly reduced to a hydro-mechanical coupling by which its pressurization in poorly-connected, constrained volumes (e.g. saturated micro cracks) promotes crack propagation due to the increase of pore pressure in cracks and its squeeze towards pores (squirt flow). On the other hand, chemical stimulation (i.e. injection of chemically reactive agents) has been thoroughly applied to oil & gas as well as geothermal reservoirs to enhance their performance. However, the results obtained under field conditions have not yet gained a sufficient level of understanding what indicates that it is still needed a greater effort to better understand some fundamental aspects of fluid/rock interactions, especially from the standpoint of their chemo-hydro-mechanical couplings. In the present contribution we will illustrate some ongoing results of an experimental exploratory survey performed at room P&T conditions, focused in the assessment of the effect of reactive and non-reactive fluids on crack initiation and propagation in two types of rock: A sandstone and two granites. The main measured reference property to evaluate fluid impacts is mode I fracture toughness. The results suggest that not all fluids equally enhance rock cracking (or crack propagation) while the relevance of the chemical mechanisms involved is not akin in the two studied rock types. Furthermore, some ideas on further steps including fracture toughness testing above-ambient P&T conditions will be presented.
As part of its mid and long term decarbonization strategy, Petroleum Development Oman (PDO) is committed to achieve net zero by 2050,and aspires to support the Sultanate’s industry decarbonization ambitions. Carbon Capture Utilisation and Sequestration (CCUS) is a key enabler to realise these plans. The base-case sink for the PDO CO2 is likely to be sequestration into mature oil fields through the application of CO2 flood enhanced oil recovery (EOR). The potential economic upside of EOR will be critical in supporting the economics of CCUS investment. A portfolio of CO2 EOR/EGR opportunities was established in PDO in 2019. To mature the CCUS portfolio while building inhouse technical capabilities around CO2 EOR, PDO embarked in de-risk activity for EOR project and kick-off studies to screen the sink to be used as storage. The CCUS technical framework will realise these opportunities through: • Definition of CCUS projects (EOR / EGR) and opportunities within PDO concession area • Definition of additional carbon sinks within PDO concession area, for sequestration • Identification of demonstration projects for CCUS to accelerate and enable skill building.
The Intermountain West region of the United States is at a pivotal moment in its transition towards a cleaner and more sustainable energy future. Hydrogen has emerged as a promising candidate for meeting the region's energy needs, given its potential to enable low-carbon pathways for transportation, industry, and power generation. In this talk, we will explore the opportunities and challenges of developing hydrogen production and geologic storage in the Intermountain West, and the role of hydrogen in building a low-carbon economy
Geological CO2 sequestration (GCS) remains the main promising solution to mitigate global warming. Understating the fate of CO2 behavior is crucial for securing its containment in the reservoir and predicting the impact of dissolved CO2 on the host formation. Most modeling based studies in the literature investigated the convective-reactive transport of CO2 by assuming isothermal conditions. The effect of temperature on the convective-reactive transport of CO2 is poorly investigated. The objective of this study is to provide an in-depth understanding of CO2-related reactive thermohaline convection (RTHC) processes at field scale. Thus, a new numerical model based on advanced finite element formulations is developed based on advanced finite elements method and time integration techniques. Numerical experiments confirm high accuracy and efficiency of the newly developed model. The newly developed model is used for understanding the effect of temperature on CO2 transport for a field case in the Viking reservoir in the North Sea. Results show that including the temperature effect intensifies the fingering processes and, consequently, CO2 dissolution. Neglecting the thermal convection processes and the impact of temperature on the dissolution rate can significantly impact the model predictions. A sensitivity analysis is developed to understand the effect of parameters governing the 38 dissolution rate on the fingering phenomenon and the total CO2 flux.
The permeability of a pore structure is typically described by stochastic representations of its geometrical attributes (e.g. pore-size distribution, porosity, coordination number). Database-driven numerical solvers for large model domains can only accurately predict large-scale flow and reactive behaviour when they incorporate upscaled descriptions of that structure and its evolution. This is particularly challenging for rocks with multimodal porosity structures such as carbonates, where several different type of structures (e.g. micro-porosity, cavities, fractures) are interacting. It is the connectivity both within and between these fundamentally different structures that ultimately controls the porosity-permeability relationship at the larger length scales. Recent advances in machine learning techniques combined with both numerical modelling and informed structural analysis have allowed us to probe the relationship between structure, reaction, and permeability much more deeply. We have used this integrated approach to tackle the challenge of upscaling flow and reaction in rocks with complex pore structures with a combination of advanced pore-scale modelling and machine learning.
Carbon dioxide (CO2) capture, utilization and storage (CCUS) is one of the most promising technologies to mitigate the anthropogenic emissions of CO2 and resulting climate change. One of the biggest advantages of CCUS is it can be deployed at large-scale and at different locations. Geologic CO2 storage (GCS) is a critical component of CCUS technology. Globally, there are multiple geologic storage options including saline aquifers as well as depleted hydrocarbon reservoirs that have the appropriate features and characteristics necessary for injecting large quantities of CO2 (10s – 100s million tons) and storing it over long time periods (100s – 1000s years). Multiple commercial scale CCUS projects are currently in operations and multiple are in the planning stages globally. One of the critical components for wider acceptance of GCS is ensuring and demonstrating its safety over long time. The potential geologic CO2 storage sites currently under consideration primarily include deep saline aquifers, depleted oil/gas reservoirs and deep un-mineable coal seams, etc. These geologic systems are inherently heterogeneous and sites with saline aquifers have limited to no characterization data. Effective risk management decisions to ensure safe, long-term CO2 storage requires assessing and quantifying risks while taking into account the uncertainties in a storage site’s characteristics. The key decisions are typically related to definition of area of review, effective monitoring strategy and monitoring duration, potential of leakage and associated impacts, etc. A quantitative methodology for predicting a sequestration site’s long-term performance is critical for making key decisions necessary for successful deployment of commercial scale geologic storage projects where projects will require quantitative assessments of potential long-term liabilities. An integrated assessment modeling (IAM) paradigm which treats a geologic CO2 storage site as a system made up of various linked subsystems can be used to predict long-term performance. The subsystems include storage reservoir, seals, potential leakage pathways (such as wellbores, natural fractures/faults) and receptors (such as shallow groundwater aquifers). CO2 movement within each of the subsystems and resulting interactions are captured through reduced order models (ROMs). The ROMs capture the complex physical/chemical interactions resulting due to CO2 movement and interactions but are computationally extremely efficient. The computational efficiency allows for performing Monte Carlo simulations necessary for quantitative probabilistic risk assessment. We have used the IAM to predict long-term performance of geologic CO2 sequestration systems and to answer questions related to probability of leakage of CO2 through wellbores, impact of CO2/brine leakage into shallow aquifer, etc. Answers to such questions are critical in making key risk management decisions. This talk will give an overview of the IAM approach and example showing its application to field projects.
Distributed Acoustic Sensing (DAS) is a technology whereby a fibre optic cable is transformed into tens of thousands of seismic sensors, that recently has seen rapid uptake by the oil and gas sector as a monitoring technology. The advantages of DAS include the lost-cost of fibre optic cables and its ability provide high resolution datasets spanning 10’s of km on the ground or the full length a the well. Many applications of DAS datasets in O&G utilise a fibre deployed down-hole and are for the purpose of geophysical surveys such as VSP or passive seismic monitoring. However, it is also possible to use DAS responses to investigate of fluid flow in the well or the reservoirs slow-strain response to stimuli. As such DAS acquisition is also applicable in settings such as CO2 sequestration and geothermal projects. In fact, the ubiquity of fibre optic cables throughout our society extends the potential uses for DAS beyond those directly related to the subsurface into areas such as; seismic monitoring, leak detection, railway and road traffic monitoring, security and intruder detection, as well as infrastructure monitoring.
Here I will outline some of the basic principles and applications of DAS surveys as well as describing some of the challenges int DAS acquisition. In particular, DAS surveys are limited by the very high data rates produced the acquisition hardware (up to 10's of TB/day). These large data volumes make DAS data difficult to analyse and cumbersome to extract from the field location. To address this issue Motion Signal Technologies has developed the Compression At The Edge (CATE) acquisition system. CATE is capable of compressing DAS data as it is acquired in real time, such that the data can be archived locally and or transmitted from field using a band limited connection. The system has been tested in a variety of settings and the results include recordings from fibre optic cables positioned beside train lines in the UK, which in addition to monitoring railway security and condition show clear signals from the Feb 6th Turkey Earthquake. I will also present results from a trial using (possibly the first) temporary downhole fibre deployed in a geothermal well to record a VSP/ Check shot survey. The results show clear detections of the first arrivals beyond 3.5km depth and provide an important constraint on the velocity model used to locate natural and induced seismic events in the area.
Numerous geoenergy projects (geologic carbon storage, geothermal systems, gas storage or hydraulic fracturing) involve injection of fluids at depth. The resulting changes in stress often induce (micro)seismicity. While damages are usually minimal, public perception may be damaged, thus compromising the project viability. The problem is worsened by the numerous processes involved (hydraulic, mechanical, thermal, and often chemical), by the fact that they are intimately coupled, and by the diversity of failure settings. As a result, understanding is hard, which hinders not only numerical simulation, but also the design and operation of remediation and mitigation actions. We first review coupled process, from the traditional impact of pore pressure increase on stability, to stress transfer driven by pressure gradients or thermal contraction. This leads to a broad view of the induced seismicity operational mechanisms, which we summarize in five operational failure mechanisms (i.e., directly linked to fluid operation): pressure buildup, pressure dissipation, displacement transfer, thermal contraction, and buoyancy. Understanding them is needed to move beyond the traditional traffic light system into active pressure management to control induced seismicity.
Microseismic monitoring of both overburden and reservoir/basement induced seismicity is an essential part of almost any C02 sequestration project. Most of the induced seismicity is triggered by increased pore pressure due to injected C02 (e.g., Zoback, 2012) and re-activation of pre-existing faults. Hence, the observed microseismicity in the overburden is an indicator of seal breakage due to C02 penetration into the seal. Microseismicity in the basement is usually interpreted as the C02 plume causing increased pore pressure on pre-existing faults in the reservoir or basement (e.g., Williams-Stroud, et al., 2020). However, our understanding of the usual size and frequency of the induced seismicity that results from C02 sequestration is constrained by limitations of currently deployed induced seismicity although these are monitored (e.g., Sleipner, Aquistore, Otway). Furthermore, different types of monitoring arrays are used, from regional networks (e.g., Sleipner, Snøhvit) through local arrays with surface or shallow borehole receivers (e.g. Aquistore, Cranfield), downhole arrays (e.g. Weyburn-Midale, In Salah) to hybrid arrays with combined downhole and surface receivers (e.g. Lacq-Rousse, Decatur). As the injections of C02 need to last for exceptionally long periods of time and involve large volumes, microseismicity may occur at great distances from the injection wells.
Land seismic is inherently more complex than marine, even more so in arid desert environments. Geophysical techniques proven in a desert environment would ace everywhere else. Monitoring in a desert environment is extremely challenging due to shifting sand dunes and seasonal changes. First, I will walk you through actual field feasibility results with various source-receiver configurations. Then, picking the winner of hybrid acquisition with buried receivers and surface source, we dive into a 3D case study of monitoring CO2 injection in a carbonate land reservoir. I show how fantastic marine-like repeatability of 4% NRMS (Normalized Root-Mean Square error) can be achieved in complex desert environments when surveys are done in the same season. Scaling up such monitoring to more extensive areas demands Distributed Acoustic Sensing (DAS) to optimize instrumentation costs. I show a deep seismic imaging field demonstration using shallow DAS vertical arrays and compare it to conventional 2D surface seismic. I conclude by explaining how DAS antennas can decrease the density of the monitoring array, thus providing a robust system for monitoring mass-scale CO2 sequestration.
As part of the energy transition value drivers and workflows in the Oil &Gas industry are changing significantly. In addition to the strong focus on de-carbonisation fast delivery of HCM projects is of utmost importance.
For the past years Petroleum Development Oman’s Hydrocarbon Maturation Centre (HMC) has consolidated reservoir knowledge in Formation specific thematic catalogues for PDO’s acreage. The objective of this multidisciplinary collection of data, experience and insights is to reduce FDP cycle times by providing users web-based access to standardised datasets, workflows and past development decisions and thereby leveraging the use of analogues for development decision making. However, despite the vast amount of analogue information specific development decisions such as optimal pattern type, well spacing, water throughput, etc. and corresponding recovery factors and production profiles commonly are still evaluated using reservoir simulation.
PDO is therefore developing a new web-based tool that leverages the extensive analogue knowledge, multi-scenario modelling, and machine learning to eliminate or significantly reduce the requirement for such time- consuming reservoir simulation studies.
For several reservoirs we generated 10,000’s of sector models covering all static and dynamic uncertainty ranges and simulated all plausible development concepts. The entire dataset is then used to train a ML model.
The generated sector model library is searchable and can be used to identify geological analogues. The AI webtool then can predict recovery factors, forecast ranges etc. for any analogue or new sector model for the available development concepts at a click of a button. This allows a fast & robust evaluation of subsurface development options with clarity on trade off’s, eliminates repetitive modelling & simulation requirements, and significantly accelerates simulation-based forecasting by 50% and more.
In this study, we used an offshore 3D dataset provided by TGS and another onshore 3D legacy dataset. Together, these 2 surveys cover tens of thousands of square kilometers of Mesozoic carbonates in the Gulf of Mexico (GOM). The offshore volume images several upper Jurassic to Lower Cretaceous carbonate shelf margins of the Northeastern GOM along the Florida Escarpment while the onshore volume only shows Albian margins in the Maverick Basin, an intrashelf basin located in the western GOM. To interpret these two 3D volumes, we used a combination of traditional horizon mapping with Paleoscan automatic horizon stack extraction to generate hundreds of accurate horizon-slices that were painted with a color blending of 3 spectral decomposition bands (25, 40, and 55 Hz). This high-resolution seismic geomorphology techniques allows to extract the seismic expression of complex carbonate geomorphology and to image the spatial and temporal distribution of single carbonate architectural element that have the potential to be reservoir geobodies in the subsurface. We will show examples of beach/strand-plain accretion of the Upper Jurassic Smackover ramp, evaporite karst and dissolution features of the uppermost Jurassic shelf, reticular ridges interpreted has being coral-stromatoporid/Lithocodium reef buildups on the Berriasian shelf, spectacular sinuosidal tidal bars and channels of the upper Aptian shelf as well as Albian patch reef and bar complex along the Maverick Intrashelf margin. Finally, we will compare a karst network is located at the Albian shelf edge that extend for 2-5 km in the sip direction and more than 40 km in the strike direction with seismic model of a size equivalent modern cave. These large regional seismic volumes image large portion of entire carbonate shelf, margin to slope systems at a high-enough resolution that allows to image and interpret individual architectural elements and their spatio-temporal evolution. Precise horizon-slices combined with spectral decomposition blending provides a level of details that cannot be seen on traditional vertical or time/depth slices only.
Karst and fractured aquifers are characterized by a duality of infiltration and flow. Flow and transport modelling in these systems is highly challenging and requires a thorough characterization of the subsurface and extensive collection of data. This talk provides a short review on the evolution of modeling in karst aquifers, to later zoom to one experimental poorly studied site in Mount Lebanon: the Nahr El Kalb surface water/ aquifer system composed of limestone and dolostones of Jurassic to Cenomanian age. A high-resolution monitoring is taking place since 2014 to characterize the subsurface, understand spring responses, conceptualize flow and transport in complex systems, and simulate flow in variably heterogeneous systems of Mount-Lebanon. Different methods have been applied for the characterization of flow and transport in different types of karst systems with variable heterogeneities, hydrodynamic conditions, and climatic input: 1) snow-governed versus rain governed springs, 2) fissured karst aquifers, 3) highly complex heterogenous karst with little knowledge of the subsurface, and 4) highly complex karst with a cave access. Such utilized methods include times series analysis, tracer experiments, micropollutants sampling campaigns, stable isotope studies in addition to the use of stochastic geomodelling to infer from surface characteristics information about preferential flow in the subsurface. Selected distributed and lumped flow models will be presented such as 1) distributed integrated hydrological model, 2) semi distributed linear reservoir model, 3) 2-D dual continuum, 4) discrete fractured network models, and 5) convolution neural network models (CNN), that have been tailored to simulate flow in spring catchment areas to account for the degree of karstification and varying hydrodynamic responses. In this talk we illustrate a modeling approach can be scaled up to the region for a better sustainable groundwater management in poorly studied aquifer systems.
The distribution of porosity and permeability in carbonate rocks is controlled by diagenesis, which affects fluid flow in subsurface environments. Quantifying the relationship between diagenetic petrographic characteristics and changes in permeability is challenging. In this presentation we utilise pore-scale models to demonstrate how typical carbonate sediments and their diagenetic histories can be used to quantify the evolution of petrophysical properties in carbonate rocks. The models were generated by creating 3D pore architecture models from 2D binarized images of typical textural changes of carbonate sediments following hypothetical diagenetic pathways. Flow properties were then calculated from the resulting network representation of the pore system. The evolution scenarios displayed "diagenetic tipping points," where permeability decreased dramatically for only a small decrease in porosity. The models also showed how diagenesis alters capillary entry pressures and relative permeabilities, providing trends that can be applied to real rocks. The values of porosity and permeability derived from these models were similar to those measured in nature. These diagenetic pathway models can be used to predict flow behaviour during burial and uplift scenarios by using "diagenetic back-stripping" of real carbonate rocks.
Fracturing of various types of rocks by water and by CO2 are presented with consideration of thermoporoelasticity. The phase-field approach with incorporation of critical energy release rate is the basis of the rock failure and fracture propagation. There are advantages in formulation based on the Euler-Lagrange equation in simulation of fracturing. The mixed finite element may be a natural choice for discretization in fracturing. We can predict fracture branching without parameter adjustment. At superhot temperatures found in many regions of the world, the estimate of renewable geothermal energy exceed hydrocarbon energy resources. At higher temperatures even without thermal stress, fracture intensity from fracture branching and from natural microfractures may provide the path for effective heat extraction. At superhot temperatures, there may be a significant reduction in breakdown pressure. CO2 fracturing is even more effective than water fracturing in such conditions. Lower fracturing pressure reduces seismic activity and helps with safety of fracturing.