North Sea Reservoir Research Articles

Geochemical modeling of diagenetic reactions between albitization of K-feldspar and plagioclase feldspar in sandstone reservoirs under the influence of CO2 partial pressure

Diagenetic albitization has been observed in sedimentary basins around the world. This process significantly changes the original composition of sandstones and the chemistry of the formation waters under the influence of partial pressure of CO2. The transformation of detrital feldspars into albite is considered a crucial diagenetic process in the Gulf Coast and North Sea reservoirs. Earlier studies suggest that plagioclase albitization typically happens before that of K-feldspar. In the Gulf Coast's Frio Sandstone, located in the Upper Oligocene at depths between 900 and 2400 m, detrital plagioclase is often dissolved and replaced by albite, while K-feldspar mostly dissolves without much substitution. Similarly, in the North Sea reservoirs, especially in the upper section of the Upper Triassic Lunde Formation at depths beyond 2900 m, plagioclase tends to undergo albitization, whereas K-feldspar remains largely unaffected or experiences minimal transformation. This research focuses on analyzing the differences in the albitization patterns of detrital and K-feldspar plagioclase through the KINDISP and Geochemist's Workbench (GWB) geochemical modeling tools, aiming to compare them. These diagenetic processes are crucial for reservoir geology, as they influence the concentration of silica in water, which, in turn, affects quartz cementation. This study aims to explore the variations in the albitization behavior of detrital and K-feldspar plagioclase using the KINDISP and Geochemist's Workbench (GWB) geochemical models and conduct a comparative analysis between them. Understanding these diagenetic reactions becomes relevant for reservoir geology analysis, as such phenomena control the aqueous silica concentration to some extent, which is consequently reflected in the quartz cementation. The dissolution of plagioclase and K-feldspar releases silica into the pore fluids. As the concentration of silica in the fluid increases, it leads to the precipitation of quartz as overgrowths on detrital quartz grains, a process known as quartz cementation. This was observed particularly in simulations involving temperature increases up to 150 °C, where the equilibrium between albite and anorthite was closely linked to the stability of quartz (Ben et al., 1993). The removal of feldspar through albitization reduces porosity and permeability but contributes silica to the system, which promotes quartz cementation. This, in turn, decreases the reservoir quality by filling pore spaces with secondary quartz, reducing the rock's ability to store and transmit fluids. Thus, the study highlights the importance of these diagenetic processes in reservoir evaluation, as the balance between feldspar dissolution and quartz cementation ultimately controls reservoir properties.

Simple MATLAB and Python scripts for multi-exponential analysis.

Multi-exponential decay is prevalent in magnetic resonance spectroscopy, relaxation, and imaging. This paper describes simple MATLAB and Python functions and scripts for regularized multi-exponential analysis methods for 1D and 2D data and example test problems and experiments. Regularized least-squares solutions provide production-quality outputs with robust stopping rules in ~5 and ~20 lines of code for 1D and 2D inversions, respectively. The software provides an open-architecture simple solution for transforming exponential decay data to the distribution of their decay lifetimes. Examples from magnetic resonance relaxation of a complex fluid, a Danish North Sea crude oil, and fluid mixtures in porous materials-brine/crude oil mixture in North Sea reservoir chalk-are presented. Developed codes may be incorporated in other software or directly used by other researchers, in magnetic resonance relaxation, diffusion, and imaging or other physical phenomena that require multi-exponential analysis.

Flow-Through Experiments of Reactive Ba-Sr-Mg Brines in Mons Chalk at North Sea Reservoir Temperature at Different Injection Rates

Summary North Sea Chalk reservoirs in Norway are potential candidates for enhanced hydrocarbon recovery by modifying the injected brine composition. This work investigates how barium (Ba), strontium (Sr), and magnesium (Mg) brines interact when injected into chalk. Ba and Sr are often associated with mineral precipitation and occur in formation water, while Mg is present in seawater, commonly injected in chalk. Relatively clean (>99% calcite) outcrop chalk cores from Mons, Belgium, were flooded at 130°C in triaxial cells with four brines containing 0.12 mol/L divalent cations, either 0.06 mol/L Sr and Ba, 0.06 mol/L Sr and Mg, or 0.12 mol/L Ba or Sr. Each brine was injected in a separate core, with 100–150 pore volumes (PV). The injection rate varied between 0.5 and 8 PV/D. Produced brine was analyzed continuously and compared with the injected composition. After flooding, the cores flooded with only Ba or only Sr were cut into slices and analyzed locally in terms of scanning electron microscopy (SEM), matrix density, specific surface area (SSA), and X-ray diffraction (XRD). In all experiments, the produced divalent cation concentration was reduced compared with the injected value. The total reduction of injected cation concentration closely equaled the produced Ca concentration (from calcite dissolution). When flooding 0.12 mol/L Sr, the Sr concentration depleted 55%, while when flooding 0.12 mol/L Ba, 15% Ba depleted. When injecting equal concentrations of Ba and Sr, 40% Sr and 7% Ba depleted, while with equal concentrations of Mg and Sr injected, ~50% Sr was retained and almost no Mg depleted. Sr appeared to dominate and suppress other reactions. There was less sensitivity in steady-state concentrations with variation in injection rate. The similar modification of the brine regardless of residence time suggests the reactions reached equilibrium. Cutting the cores revealed a visually clear front a few centimeters from the inlet. The material past the front was indistinguishable from unflooded chalk in terms of density, SSA, microscale structure, porosity, and composition [XRD and SEM-energy-dispersive spectroscopy (EDS)]. The material near the inlet was clearly altered. Images, XRD, SEM-EDS, and geochemical simulations indicated that BaCO3 and SrCO3 formed during BaCl2 and SrCl2 flooding, respectively. Geochemical simulations also predicted an equal exchange of cations to occur. The matrix densities, porosities, and the distance traveled by the front corresponded with these minerals and suggested that the chalk was completely converted to these minerals behind the front. It was demonstrated that Ba, Sr, and Mg brines and their mixtures can be highly reactive in chalk without clogging the core, even after 100 + PV. This is because the precipitation of minerals bearing these ions is associated with simultaneous dissolution of calcite. The Ca-, Ba-, and Sr-mineral reactions are effectively in equilibrium. Previous investigations with MgCl2 (in pure and less pure chalk, at 130°C) show injection rate-dependent results (Andersen et al. 2022) and smoother alterations [Mg precipitation was seen from inlet to outlet (Zimmerman et al. 2015)], indicating that Mg-mineral reactions at same conditions have a longer time scale. The limited distance mineral alteration has occurred, suggesting that adsorption processes, happening in parallel, can explain previous observations (Korsnes and Madland 2017) of Ba and Sr injection strengthening chalk. Flushing out formation water with these ions during injection may be a new water-weakening mechanism.

The potential importance of exploiting export markets for CO2 transport and storage services in realising the economic value of Scottish CCS

Previous research investigating the UK economy impacts of introducing a new Scottish CO2 Transport and Storage (T&S) industry linked to carbon capture and storage (CCS) has focussed on supply chain and funding requirements in introducing such a new sector to service proximate Scottish industrial emissions via onshore pipelines. However, Scottish plans extend to shipping CO2 from outside Scotland for storage in North Sea reservoirs by also servicing sequestration requirements from elsewhere in the UK and/or overseas. This will involve investment in greater industry capacity but could ease associated domestic funding requirements. Here, we introduce improved economy-wide structural (input-output) data reflecting how a Scottish T&S sector may emerge from current Oil and Gas industry supply chain capacity to a computable general equilibrium (CGE) model, extending to simulate emergence of an export base. Our central finding is that exploiting overseas T&S export opportunities is crucial where the policy aim is to generate greater economic activity without increasing demands on the public purse. However, any extent of real wage bargaining and consequent producer cost pressure as labour demand increases will act to dampen expansionary power, displacing export production and employment, while driving consumer price impacts that limit real income and public budget gains.

Impact of Gas Liberation Effects on the Performance of Low Permeability Reservoirs

Production from the North Sea reservoirs often results in a pressure decrease below the bubble point. The gas is liberated from oil, in the form of bubbles or as a continuous flowing phase. In such cases, the two phases, gas and oil, flow in the reservoir simultaneously, and the flow is governed by the values of relative permeabilities. Traditional core flooding in low permeability rocks is challenging, therefore we use a novel experimental approach to determine the oil relative permeabilities below the critical gas saturation. A mathematical model has been created to reconstruct both the gas and the oil relative permeabilities for the whole saturation range. Laboratory observations have shown that in low-permeable rocks the relative permeabilities may strongly decrease, even when the amount of the liberated gas is small. The goal of this work is to verify, on a specific example, whether the designed model for the relative permeabilities may explain the observed production behavior for a low-permeable chalk reservoir in the North Sea. We perform a sensitivity study using the parameters of relative permeabilities and analyze the corresponding differences in well productivities. A reasonably good match of <10% can be obtained to the historical well production data. A few cases where the match was not satisfactory (14% to 65%) are also analyzed, and the difference is attributed to the imprecise fluid model. The developed experimental and modeling methodology may be applied to other reservoirs developed by the solution gas drive mechanism.

Reaction Kinetics Determined from Coreflooding and Steady-State Principles for Stevns Klint and Kansas Chalk Injected with MgCl2 Brine at Reservoir Temperature

Summary A methodology is presented for determining reaction kinetics from coreflooding: A core is flooded with reactive brine at different compositions with injection rates varied systematically. Each combination is performed until steady state, when effluent concentrations no longer change significantly with time. Lower injection rate gives the brine more time to react. We also propose shut-in tests where brine reacts statically with the core for a defined period and then is flushed out. The residence time and produced brine composition are compared with the flooding experiments. This design allows characterization of the reaction kinetics from a single core. Efficient modeling and matching of the experiments can be performed as the steady-state data are directly comparable to equilibrating the injected brine gradually with time and do not require spatial and temporal modeling of the entire dynamic experiments. Each steady-state data point represents different information that helps constrain parameter selection. The reaction kinetics can predict equilibrium states and time needed to reach equilibrium. Accounting for dispersion increases the complexity by needing to find a spatial distribution of coupled solutions and is recommended as a second step when a first estimate of the kinetics has been obtained. It is still much more efficient than simulating the full dynamic experiment. Experiments were performed injecting 0.0445 and 0.219 mol/L MgCl2 into Stevns Klint (Denmark) and Kansas (USA) chalks at 100 and 130°C (North Sea reservoir temperature). Injection rates varied from 0.25 to 16 pore volume per day (PV/D), while shut-in tests provided equivalent rates down to 1/28 PV/D. The results showed that Ca2+ ions were produced and Mg2+ ions retained (associated with calcite dissolution and magnesite precipitation, respectively). This occurred in a substitution-like manner, where the gain of Ca was similar to the loss of Mg2+. A simple reaction kinetic model based on this substitution with three independent tuning parameters (rate coefficient, reaction order, and equilibrium constant) was implemented together with advection to analytically calculate steady-state effluent concentrations when injected composition, injection rate, and reaction kinetic parameters were stated. By tuning reaction kinetic parameters, the experimental steady-state data were fitted efficiently. The parameters were determined to be relatively accurate for each core. The roles of reaction parameters, pore velocity, and dispersion were illustrated with sensitivity analyses. The determined reaction kinetics could successfully predict the chemical interaction in reservoir chalk and outcrop chalk containing oil with strongly water-wet or mixed-wet state. The steady-state method allows computationally efficient matching even with complex reaction kinetics. Using a comprehensive geochemical description in the software PHREEQC, the kinetics of calcite and magnesite mineral reactions were determined by matching the steady-state concentration changes as function of (residence) time. The simulator predicted close to the identical production of Ca as loss of Mg. The geochemical software predicted much higher calcite solubility in MgCl2 than observed at 100 and 130°C for Stevns Klint and Kansas. The methodology supports reactive flow modeling in general, but especially oil-bearing chalk reservoirs, which are chemically sensitive to injected seawater in terms of wettability and rock strength.

Virtual outcrop-based analysis of channel and crevasse splay sandstone body architecture in the Middle Jurassic Ravenscar Group, Yorkshire, NE England

Well-exposed fluvio-deltaic deposits of the Middle Jurassic Ravenscar Group (Yorkshire coast) provide a direct analogue for North Sea reservoirs, but previous studies were restricted to a few accessible bays. This study used lidar and drone photogrammetry to create near-continuous virtual outcrops, 21 km long and 30–150 m thick, in an area which is largely inaccessible. Remote sensing data were supplemented by 45 outcrop logs and data from 27 pre-existing, behind-outcrop boreholes to improve understanding of the geometries, architectures and stacking patterns of 10 distinct sandbody types; the most important reservoir analogue units are channels and crevasse splay bodies. Channel bodies are 30–2038 m wide and 2–28 m thick with W / T ratio ranges of 5–105; the majority are multi-storey with an average thickness of 8 m and width of 182 m, while the single-storey channel bodies average 4 m thick and 50 m wide. Crevasse splays are 15–>1285 m wide and 0.3–6.5 m thick with W / T ratio ranges of 50–>541. There is a marked lateral and vertical change in channel body dimensions and facies proportion. The study suggests that the channel architecture and depositional nature of these successions are controlled by base-level fluctuation and floodplain topography. Supplementary material : Fieldwork-based sedimentary logs, borehole core-based sedimentary logs with facies proportions, workflow to prepare virtual outcrop, method to estimate true width of sandbody, correlation panel of crevasse splay bodies, interpreted virtual outcrops, and dimensional data of channel, crevasse splay and crevasse channel bodies are available at https://doi.org/10.6084/m9.figshare.c.5795793

Experimental investigation of low salinity water-flooding in tight chalk oil reservoirs

Chalk reservoirs, due to their high storage capacity and very low permeability, are one of the most interesting cases for reservoir engineering research on carbonates. They exhibit complex fluid-rock interactions because of their chemically active porous media. This study investigates the effect of brine composition, injection scenario, and temperature on oil recovery by low salinity water-flooding in chalk core samples from a Danish North Sea reservoir. The mechanisms governing oil-brine-rock interactions were also explored. Actual reservoir chalk core samples, without any open fractures, were selected using computed tomography analyses. These cores were saturated with representative fluids (crude oil and synthetic formation brine) and aged at reservoir conditions for approximately three weeks. The role of brine chemistry has been investigated through effluent analysis by ion chromatography, and results indicate that low salinity diluted seawater promotes rock-surface reactions if left to incubate for at least 48 h. Rock dissolution, observed through the monitoring of effluent ions, increased both with increase in temperature and decrease in brine salinity. The recovery curves show that formation water and diluted seawater produce significantly more oil (of the order of 10 % more) at the secondary stage compared to seawater. Additionally, there is also some indication of an effect of low salinity brine at the tertiary stage. These experiments were performed on reservoir materials and corresponding crude oil samples and provide new data on the low salinity flooding potential for chalk, and provide further evidence for the applicability of the low salinity effect in carbonates.

Investigation of sand production prediction shortcomings in terms of numerical uncertainties and experimental simplifications

Sand production is one of the main research topics in the petroleum industry. This problematic phenomenon is related to the mechanical and hydrodynamic behavior and reservoir specifications. Sand production often leads to equipment damage and significant losses. This is usually studied by experimental and numerical methods. This study first gives a brief overview of the methods used to predict sand production in terms of experimental tests, numerical simulation, and field data. The main objective of this research is to highlight the shortcomings of these methods. In addition, experimental hollow cylinder test data and widely used continues numerical simulation are used to investigate these shortcomings. This study is performed by scrutinizing the most important and basic parameters in numerical modeling including two constitutive models (Mohr-Coulomb elastic-perfectly plastic and Mohr-Coulomb cohesion softening/friction hardening failure criteria) and various element sizes and shapes. Since most studies use continuum approaches, it was decided to use a finite difference program. Further, to reduce the undesirable influencing factors the fracture energy regularization method was implemented to diminish mesh dependency related to energy dissipation. In addition, a mesh size sensitivity analysis was performed to show the effects of size, shape and pattern of mesh on the results and cumulative probability distribution versus absolute relative error diagrams were applied to compare the accuracy of the models. After all, the best model of prediction was selected to simulate a real sand production in an oil well with 50° inclination and 6 SPF in North Sea Reservoir. Review of experimental papers shows that these tests usually have several hypotheses for simplification. Rock strength, stress state, fluid flow properties, test duration, and sample dimensions are the most important parameters in sand production tests. Researchers usually focus on only one or two of these parameters, which may lead to many errors in contrast to reality. In addition, numerical methods have some deficiencies such as mesh size problems, lack of critical-state-based constitutive models, sanding criteria, and lack of sufficient research for the calibration procedure in the DEM model. A small change in both the numerical simulation input data and the experimental procedure leads to different results. Indeed, the experimental test of sand production with multiple hypotheses can qualitatively simulate the steps and shape of well or perforation failure not the exact sand production rate. Also, numerical simulation results are very sensitive due to uncertainties and errors of the model and input data. It has been shown that the results are highly dependent on every simple parameter such as the shape of the elements. The differences between experimental results and numerical modeling in only one perforation can be 2 to 10 times. Despite all errors and uncertainties in both the laboratory and modeling studies, the simulation of a real sand production in North Sea Reservoir with same sized element was relatively acceptable. This level of accuracy of the model can be very helpful in subsequent decision making and sand control management.

Water Saturation Modeling Challenges in Oil-Down-to Wells: An Example from a Multidarcy North Sea Reservoir

Summary The initial water saturation in a reservoir is important for both hydrocarbon volume estimation and distribution of multiphase flow properties such as relative permeability. Often, a practical reservoir engineering approach is to relate relative permeability to flow property regions by binning of the initial water saturation. The rationale behind this approach is that initial water saturation is related to both the pore-throat radius distribution and the wettability of the rock, both of which affect relative permeability. However, pore-throat radius and wettability are usually not explicitly included in geomodel property modeling. Therefore, the saturation height model should not only capture an average hydrocarbon pore volume but also reflect the underlying mechanisms from hydrocarbon migration history and its impact on initial water saturation distribution. This work introduces and describes a new term, excess water, for more precise classification of saturation height model scenarios in reservoirs in which multiple mechanisms have interacted and caused a complex water saturation distribution. An example of the presence of transition zones related to drained local perched aquifers (excess water) in oil-down-to (ODT) wells is shown using a limited data set from a North Sea reservoir. The physical basis for drainage and imbibition transition zones connected to both regional and perched aquifers is given. The distribution of initial water saturation in reservoirs containing excess water is demonstrated through numerical modeling of oil migration over millions of years. Highly permeable reservoirs are more likely to have locally trapped water because of lower capillary forces. A static situation occurs in areas where the capillary forces cannot maintain a high enough water saturation for further water drainage. On the other hand, both high- and low-permeability reservoirs may have significant excess water because of ongoing dynamic effects. In both cases, long distances for water to drain laterally to a regional aquifer enhance the possibility for a dynamic excess water situation.

CO2 Flow Regimes Comparison between North Sea and US Classes of Reservoirs

SummaryCarbon dioxide (CO2) enhanced oil recovery (EOR) has long been practiced in the US as an efficient mean for enhancing oil production. Many of the US CO2-EOR developments have been designed horizontally. This is because of a viscous-dominated CO2 flow regime that is prevalent in these developments driven by thin and low-permeability reservoirs. Reservoirs and fluid properties are different in the North Sea. Pays are usually thicker with better petrophysical properties. Lighter oils can also be found in North Sea reservoirs. This suggests that a dissimilar flow regime might prevail CO2 displacements in the North Sea developments, which could favor a dissimilar CO2-EOR process design. This study thus compares CO2 flow regimes between several North Sea and US reservoirs. We use scaling analysis to characterize and compare CO2 flow regimes between these two classes of reservoirs. Scaling analysis characterizes CO2 displacement in each reservoir system using three dimensionless numbers: gravity, effective aspect ratio, and mobility ratio. Displacement experiments conducted in stochastically generated permeability fields, under exactly matched magnitudes of the derived dimensionless numbers, reveal the prevailing CO2 flow regime in each reservoir system. Results of scaling analysis indicate that CO2 flooding in the North Sea reservoirs can be generally characterized with a larger gravity number, smaller effective aspect ratio, and smaller mobility ratio than the average US CO2 flooded reservoirs. Flow regime analysis indicates that unlike the majority of the US CO2 flooded reservoirs, CO2 flow regimes tend to be more gravity-dominated in the North Sea class of reservoirs. CO2 flow regimes in the North Sea systems are expected to suffer from a higher degree of instability because of thicker North Sea pays, which limit effective crossflow. Understanding the differences and characteristics of CO2 flow regimes in the North Sea prospects can help operators design their CO2 flooding more efficiently, which could increase the recovery factor (RF) as well as address CO2 storage requirements, a necessary consideration for CO2-EOR deployment in the North Sea.

CO2 mobility control improvement using N2-foam at high pressure and high temperature conditions

The high mobility of CO2 in porous media is an issue in most subsurface CO2 projects worldwide, demonstrated by uncontrolled and rapid migration through the reservoir, early well breakthroughs and poor sweep efficiency. Improved mobility control of CO2 is needed to accelerate and improve the value-creation from subsurface CO2 projects, both in terms of energy produced and volumes of CO2 stored. Field-proven conformance and mobility control techniques, such as foam, provide a cost-effective and sustainable alternative to overcome geological and process constraints observed with CO2 flow in reservoirs.In this laboratory study, we have investigated CO2 mobility control by foam in sandstone core samples at typical North Sea reservoir conditions, 220 barg and 100°C, respectively. Two important aspects related to any field application of foam have been evaluated and discussed: I) Can strong CO2-foams be generated at reservoir conditions using AOS surfactant? If not, II) can relatively simple modifications to the foam system be made to improve foam properties and CO2 mobility control?Our results show that only high-mobility CO2-foams with low degree of CO2 mobility reduction are obtained at 220 barg and 100°C. An easy way to improve the foam properties at reservoir conditions is suggested by changing the gas-phase in foam to nitrogen (N2). The N2-foams display improved foam generation performance, larger mobility control in terms of mobility reduction factors (MRF) and ability to block subsequent CO2 injection.An alternative strategy for applying foam for CO2 conformance and mobility control in subsurface CO2 projects, which emerges from this study, is to initiate the foam treatment with nitrogen followed by subsequent CO2 injection to change the main direction of CO2 flow to enhance the displacement area or reduce uncontrolled CO2 production between the injecting and producing wells (as illustrated in the graphical abstract). The possible mechanisms explaining the observed differences in foam properties using CO2 versus N2, including implications that could be helpful for future studies and CO2 field applications are discussed further in more detail.The efficiency and limitations of miscible CO2 flooding to recover oil and simultaneously store CO2 after extensive water flooding are also demonstrated in this article, which are relevant to enhanced oil recovery (EOR) and subsequent CO2 storage applications, known as the Carbon Capture Utilization and Storage (CCUS).

Mineralogy and geochemistry of reservoir and non-reservoir chalk from the Norwegian continental shelf

A first and detailed study of the geochemistry and mineralogy characterizing the North Sea reservoir and non-reservoir chalk is provided in this work. The study is based on 185 cores from exploration and development wells in the North Sea. The cores related to reservoir development have different flooding status – unflooded or waterflooded at various temperatures – and are directly sampled from the Ekofisk field. Optical petrography shows a micritic carbonate matrix, with grains represented by various microfossils such as foraminifers and sponge spicules. Scanning electron microscopy (SEM) reveals post-depositional calcite precipitation and cementation. Dolomite is found only in the reservoir samples, but it is discussed as a diagenetic feature, unrelated to the hydrocarbon content or EOR exposure. The non-carbonate minerals observed with BSE-SEM and XRD include mostly quartz but also smectite, illite, kaolinite, mica, and pyrite. The abundance of clastic input varies, and there is a clear decrease in porosity stratigraphically downwards, with stronger cementation and higher compaction. δ 13 C reflects primary trends for Upper Cretaceous stages while δ 18 O in all samples is lower than the secular global isotopic values for this period. However, the δ 18 O values are not sufficiently low to imply a strong diagenetic overprint, but rather suggest the influence of a secondary fluid. This fluid cannot be a hydrocarbon-rich one, nor EOR fluids, as non-reservoir samples, as well as flooded and unflooded reservoir samples show very similar stable isotope values. • Mineralogical and geochemical characterization of broad North Sea chalk sample set. • Comparison between flooded and unflooded reservoir chalk and non-reservoir chalk. • The diagenetic overprint is low in all lithotypes. • The presence of hydrocarbons is not responsible for geochemical alterations. • The geochemical effect of EOR flooding of reservoir chalk is not obvious.

A new approach to thermal segregation in petroleum reservoirs: Algorithm and case studies

In many petroleum reservoirs, the fluid properties vary through the reservoir thickness. Variation of the composition, i.e. compositional grading, can affect reserve estimation, production and enhanced oil recovery strategies. Apart from gravity, the geothermal gradient may also contribute to the fluid distribution. Thermodiffusion is the governing phenomenon determining the contribution of the geothermal gradient. The non-equilibrium thermodynamics models are applied for the calculation of the compositional gradients under the varying temperature.In order to determine the variations in pressure and composition with depth and to be able to indicate if/where a gas-oil contact exists, we have developed a model based on the principles of irreversible thermodynamics, within the approach to thermodiffusion in porous media proposed by Montel et al. (2019). Based on the relationships where pressure, chemical potentials, and thermal gradient are linked, the distribution of hydrocarbons in a petroleum reservoir is described. A computational algorithm accounting for non-ideality of the mixture, characterization, and phase transitions has been developed. The model and the computational procedure have been validated by comparison with the case studies reported in the literature for a North Sea reservoir, and with sample component distributions produced by application of molecular dynamics simulations. It has been shown that the model is capable of predicting the fluid distributions with depth with no or a minimum of adjustable parameters. The thermal gradient modifies the predicted fluid distributions making them closer to the observed data points. Depending on the mixture composition, the thermal diffusion may either enforce the effect of gravity or counteract it.

The Influence of Super-critical CO2 Saturation on the Mechanical and Failure Properties of a North Sea Reservoir Sandstone Analogue

Large-scale geological carbon storage in the North Sea will involve injecting CO2 in a super-critical state into deep saline aquifers. As CO2 is injected, stress changes due to fluid pressure and temperature changes may result in deformation and potentially may result in microseismicity if existing faults are reactivated. Microseismicity may provide additional information on in situ stress conditions and the progression of the CO2 plume. To assess failure criteria in the reservoir, we must know the mechanical response of reservoir sandstone due to injection of super-critical CO2 (scCO2) under reservoir stress conditions. This includes fracturing processes at the microstructural scale as well as at the macroscopic scale by reactivation of existing fractures. We conducted three triaxial tests on a sandstone analogue to deep North Sea reservoir rock: once pressurized, samples were saturated with either scCO2, brine, or a brine-scCO2 mixture. Each sample was then deformed axially to induce a through-going fracture, which was then reactivated—first by increasing the pore pressure under anisotropic stress conditions, then by axial reloading with a constant pore pressure. Throughout testing, we monitored acoustic emissions (AE) and measured ultrasonic P-wave velocities. AE were located within the sample, and their relative magnitudes were calculated, as well as their source mechanisms for a subset of high signal-noise ratio events. We observed: • Higher strength and stiffness for the sample saturated only with scCO2 than for samples containing brine, and a brine-scCO2 mixture. • No clear difference in fracture strength for samples with different fluid saturations. • Higher energy events released from fracturing of the stronger and stiffer scCO2-saturated rock. • For all samples, the AE response during fracture reactivation was more energetic and had a higher frequency content at higher effective stresses (by axial loading) than at lower effective stresses (by pore pressure increase). We found fluid saturation to have only a slight influence on the mechanical and failure properties. We observed no significant weakening with scCO2 saturation that might otherwise cause undesired inelastic deformation within the reservoir.

Enriched Galerkin discretization for modeling poroelasticity and permeability alteration in heterogeneous porous media

In this paper, we utilize the enriched Galerkin (EG) finite element method for the flow equation in Biot's system, which provides a robust locally conservative flux in heterogeneous porous media. The computational algorithm to solve the coupled system with the permeability alteration is presented with the linearization and Picard's iterative scheme. The block structure is utilized for the linear system in numerical discretization, and the computer code is shared in the open-source platform. In the numerical experiments, we compare the proposed EG method with the classical continuous Galerkin (CG) and discontinuous Galerkin (DG) finite element methods in different scenarios, including the North sea reservoirs setup. While DG and EG methods provide similar approximations for the pressure solutions, the CG method produces spurious oscillations in fluid pressure and volumetric strain solutions near the material interfaces, especially for the soft materials. The difference of flux approximation between EG and DG methods is insignificant; still, the EG method demands approximately two and three times fewer degrees of freedom than the DG method for two- and three-dimensional geometries.

Water‐flooding and consolidation of reservoir chalk – effect on porosity and Biot's coefficient

ABSTRACTImproved oil recovery from chalk reservoirs by water‐flooding may cause mechanical weakening and change in elasticity. Confined compressive strength testing of chalk from a North Sea reservoir was done in water‐saturated and oil‐saturated conditions. During testing, elastic wave velocities were sampled by ultrasonic transducers, so that subsequently Biot's coefficient could be modelled. The porosity declined via an ‘elastic phase’, a ‘transitional phase’, an ‘elastoplastic phase’ and a ‘strain hardening phase’, but Biot's coefficient indicates that these terms may be partly misleading. In the ‘elastic phase’, porosity and Biot's coefficient decrease, indicating elastoplastic deformation. In the ‘transitional phase’, Biot's coefficient increases as a reflection of breaking contact cement (pore collapse), whereas Biot's coefficient remains stable in the ‘elastoplastic phase’, indicating elastic deformation on the virgin curve. Plastic deformation takes place during phases of creep, where both porosity and Biot's coefficient decrease. Similarly, in the ‘strain hardening phase’, both porosity and Biot's coefficient decrease as a reflection of elastoplastic deformation. For chalk with 45%–47% porosity, the ‘transitional phase’ begins at 8 MPa axial stress when water‐saturated and at 12 MPa when oil‐saturated. For chalk with 41%–43% porosity, the corresponding stresses are 16 and 20 MPa. For chalk with 32%–36% porosity, the corresponding stresses are 23 and 31 MPa. Chalk samples with irreducible water saturation and movable oil were water‐flooded. They yield at stresses close to corresponding oil‐saturated samples, but after flooding show compaction trends not significantly different from the water‐saturated samples. Water‐flooding promotes pore collapse as reflected in an increasing Biot's coefficient. The consequent softening effect on acoustic impedance is small as compared with the effect of increasing fluid density. With respect to 4D seismic, water‐flooding causes distinctly higher acoustic impedance and Poisson's ratio irrespective of compaction.

Integration of Time-Lapse Seismic and Production Data: Analysis of Spatial Resolution

An analysis of spatial resolution is incorporated into an efficient model calibration approach with multi-scale data integration to examine the reliability of the estimated solution. The resolution is a measure of the degree of averaging of the local-scale (grid block) permeabilities during parameter estimation via inverse modeling. For a given set of data, it indicates the regions where our estimate is well constrained. By examining the spatial resolution in time-lapse seismic data integration, we can quantitatively evaluate the relative contribution of pressure and saturation changes on the calibrated permeability field. We illustrate this concept using synthetic and field applications. The synthetic example is a 5 spot pattern, where the time-lapse seismic data are incorporated as inferred pressure and saturation changes. The field example involves waterflooding of a North Sea reservoir with multiple seismic surveys. The results demonstrate that the analysis of spatial resolution provides quantitative information on our ability to estimate the subsurface heterogeneity. It is found that integration of seismic data based on inferred pressure changes better determine the barriers to the flow (e.g., low permeability areas), while calibrating the model based on saturation changes provides complementary information to identify the channels (e.g., high permeability regions).

Kinetics of Calcite Dissolution and Ca-Mg Ion Exchange on the Surfaces of North Sea Chalk Powders.

Calcite dissolution and Ca–Mg ion exchange on carbonate rock surfaces have been proposed as potential mechanisms occurring during smart waterflooding in carbonate reservoirs. However, there is still a lack of fundamental understanding of these reactions to quantitatively evaluate their effects in the reservoir flooding process. Especially, the data on precipitation and dissolution kinetics are insufficient. In this work, the equilibration kinetics of calcite dissolution and Ca–Mg exchange was experimentally studied. The behavior of three powders was compared: pure calcium carbonate, Stevns Klint outcrop chalk, and North Sea reservoir chalk. It was found that the equilibration time for calcite dissolution was of the order of seconds for a given surface-area-to-liquid-volume ratio. The existing theory of calcite dissolution could well reproduce our observations. The Ca–Mg exchange showed two-step kinetics: the first step was fast, and it dominated the process within the first hour of reaction; the second step was slow, and it continued longer than the time of observation (2 weeks). Characteristic times for the two steps were extracted by fitting the experimental curves. A two-layer adsorption model was proposed to characterize the kinetic process and successfully matched with experimental data. The findings were further extended to flow-through scenarios. By comparing with literature data and surface complexation models, it was concluded that calcite dissolution alone was unlikely to be able to explain the additional recovery reported in the literature. The Ca–Mg exchange process could dominate the fluid–rock interactions at a high temperature in pure calcium carbonate rocks, while competitive adsorption of cations appeared to control the process at a lower temperature. Different carbonate rocks possess different properties with regard to the ion-exchange process.

A new geometrical approach for fast prediction of front propagation

The challenge to predict the future is the very reason why we developed sophisticated methods to integrate data, whatever the domain of application. In the context of the subsurface flow characterisation, the 4D seismic data reflecting the reservoir time-lapsed changes as a result of production, requires detailed processing before derived valuable information is incorporated in a subsurface model update. This is a highly uncertain time-consuming process with embedded uncertainty, which is still a challenge in data assimilation procedure. In this study, we propose a new way to the problem of forecasting. A new framework is proposed to extract a proxy model for front prediction directly from time-lapse seismic data. Multiple time-lapsed seismic surveys present the evolution of processes happening in the subsurface. These, therefore can provide information on the propagation of saturation fronts. This paper is based on the simple idea that, different snapshots in time should be able to determine a velocity propagation of fronts and from this velocity, we can then predict their future unknown positions. This work applies a modified version of the Eikonal equation and a modified version of the fast-marching method. This new approach of forecasting a front position is a fast track prediction of fronts evolution. Also, this approach is more strongly based on selected information within the data. To test this approach, we used a water injection scenario from a North Sea reservoir, from which we generated the synthetic seismic data. We compared the results from our algorithm with results from the simulation model, showing that with few data inputs (only two fronts) and a short computing time of 90 s, this method is able to give a good approximation of the waterflood front evolution. It functions as a rapid solution for front prediction based directly on seismic data, irrespective of the shape of the front (isolated blobs), with the only prerequisite being that the sequence of measured fronts is monotonic.