Saturation Build-up Research Articles

Impact of Pressure-Dependent Interfacial Tension and Contact Angle on Capillary Heterogeneity Trapping of CO2 in Storage Aquifers

Summary Carbon dioxide (CO2) capillary trapping increases the total amount of CO2 that can be effectively immobilized in storage aquifers. This trapping, manifesting itself as accumulated CO2 columns at a continuum scale, is because of capillary threshold effects that occur below low-permeability barriers. Considering that capillary pressure is dictated by heterogeneous pore throat size, the trapped CO2 column height and associated CO2 saturation will vary spatially within a storage aquifer. This variation will be influenced by two pressure-dependent interfacial parameters—CO2/brine interfacial tension (IFT) and CO2/brine/rock contact angle. Our objective is to understand how the pressure dependence of these two parameters affects the heterogeneity of capillary trapped CO2 at a continuum scale. Our conceptual model is a 1D two-zone system with the upper zone being a flow barrier (low permeability) and the lower zone being a flow path (high permeability). The inputs to this model include microfacies-dependent capillary pressure vs. saturation curves and permeability values. The input capillary pressure curves were collected in the literature that represents carbonate microfacies (e.g., dolograinstone) in a prevalent formation in the Permian Basin. We then used the Leverett j-function to scale the capillary pressure curve for the two zones that are assigned with the same or different microfacies. During scaling, we considered the influence of pressure on both the IFT and contact angle of CO2/brine/dolomite systems. We varied the zone permeability contrast ratio from 2 to 50. We then assumed capillary gravity equilibriums and calculated the CO2 saturation buildup corresponding to various trapped CO2 column heights. The CO2 saturation buildup is defined as the CO2 saturation in the lower layer minus that in the upper one. We found that the saturation buildup can be doubled when varying pressure in a storage aquifer, after considering pressure-dependent IFT and contact angles. Thus, assuming these two parameters to be constant across such aquifers would cause large errors in the quantification of capillary trapping of CO2. The whole study demonstrates the importance of considering pressure-dependent interfacial properties in predicting the vertical distribution of capillary trapped CO2. It has important implications in developing a better understanding of leakage risks and consequent storage safety.

The use of variable delay multipulse chemical exchange saturation transfer for separately assessing different CEST pools in the human brain at 7T.

PurposeCurrent challenges of in vivo CEST imaging include overlapping signals from different pools. The overlap arises from closely resonating pools and/or the broad magnetization transfer contrast (MTC) from macromolecules. This study aimed to evaluate the feasibility of variable delay multipulse (VDMP) CEST to separately assess solute pools with different chemical exchange rates in the human brain in vivo, while mitigating the MTC.MethodsVDMP saturation buildup curves were simulated for amines, amides, and relayed nuclear Overhauser effect. VDMP data were acquired from glutamate and bovine serum albumin phantoms, and from six healthy volunteers at 7T. For the in vivo data, MTC removal was performed via a three‐pool Lorentzian fitting. Different B1 amplitudes and mixing times were used to evaluate CEST pools with different exchange rates.ResultsThe results show the importance of removing MTC when applying VDMP in vivo and the influence of B1 for distinguishing different pools. Finally, the optimal B1 and mixing times to effectively saturate slow‐ and fast‐exchanging components are also reported. Slow‐exchanging amides and rNOE components could be distinguished when using B1 = 1 μT and tmix = 10 ms and 40 ms, respectively. Fast‐exchanging components reached the highest saturation when using a B1 = 2.8 μT and tmix = 0 ms.ConclusionVDMP is a powerful CEST‐editing tool, exploiting chemical exchange‐rate differences. After MTC removal, it allows separate assessment of slow‐ and fast‐exchanging solute pools in in vivo human brain.

English

This study is concerned with the water coning phenomenon that takes place around production wells of hydrocarbon reservoirs. In this paper, the development of artificial neural networks to predict the water saturation buildup around vertical and horizontal wells with a good level of accuracy is described. In the development of expert systems, it is assumed that water encroachment originates from an active aquifer which is located under the hydrocarbon reservoir (reservoir with bottom water drive). A high-fidelity numerical model is utilized in generating training data sets that are used in structuring and training the artificial neural networks. The artificial expert systems that are developed in this paper are universal and are capable of predicting the change of water saturation around the wellbore as a function of time and the prediction process is faster than a reservoir simulator and requires less data, which saves time and effort. With the help of these models, it will be possible to predict the position of high water saturation zones around the wellbore ahead of time so that remedial actions such as closing the perforations that produce the water can be implemented on a timely basis. Key words: Bottom water drive, water coning, neural network, water saturation, vertical well, horizontal well. &nbsp

Heterogeneity effects on pressure and CO2 saturation during core-scale multiphase flow tests

Carbon capture and storage (CCS) technologies can help manage current emission levels of greenhouse gases while enhancing energy security and diversifying energy economy. For a successful and effective CO2 geological storage, a comprehensive understanding of the multiphase flow properties of the CO2/water system in permeable rocks is crucial because they control the engineering design and management of industrial CO2 storage projects. In this study, we conducted multiphase flow tests at a core-scale to understand the migration behaviors of CO2 and water in a stratified geologic media (sandstone interbedded with silt). A core-flooding apparatus combined with an X-ray scanning system provided high-resolution experimental dataset of continuous data on the differential pressure (ΔP) across a core plug and CO2 saturation maps over time. During the multiphase flow tests, we captured dynamic fluctuation in ΔP as CO2 front advanced by displacing water through different geologic media. The spatio-temporal evolution of CO2 saturation in each geologic media revealed two increasing stages, implying that the capillary pressure of the downstream geologic media affects the upstream CO2 saturation. In addition, multiphase transport simulations were conducted to assess the sensitivity of model parameters. Permeability and porosity were respectively sensitive to pressure and CO2 saturation. Overall, the parameters of the silt layer were more sensitive to the pressure and CO2 saturation build-up compared to those of the sand layer. Additionally, history matching was conducted to validate the model by sequentially matching ΔP and CO2 saturation within the stratified system. Finally, we extended the core-scale modeling work further to field-scale and investigated the impact of boundary conditions and heterogeneity on both pressure and CO2 saturation distribution.

Numerical Analysis of CO2 and Water Displacement in Natural Rock Cores Based on a Fully Heterogeneous Model

AbstractBased on a core flooding experiment, a multiphase flow model considering the heterogeneity of porosity, permeability, capillary pressure, and relative permeability (i.e., the fully heterogeneous model) is proposed to analyze CO2/water displacement in a natural sandstone core. Our results indicate (1) the fractal model approximately represents the porosity-permeability relationship of the core and combining it with the Leverett’s J-function, it can be used to effectively describe the heterogeneity of capillary pressure; (2) although hypothetically assuming petro-physical properties at a few locations where obviously inhomogeneous structure and significant fluctuations of CO2 saturation are observed, the fully heterogeneous model is generally applicable to model CO2/brine two-phase flow in the sandstone core and can potentially reflect the CO2 saturation buildup; (3) the heterogeneity in capillary pressure plays an important role in generating local fluctuations of CO2 saturation profile and causing...

Capillary heterogeneity trapping of CO2 in a sandstone rock at reservoir conditions

The storage of CO2 in deep subsurface porous rocks is being developed worldwide for the mitigation of emission from large industrial sources such as power plants and steel manufacturing. A main concern of this technology is in ensuring that the upwardly buoyant CO2 does not migrate to the surface. Simulation studies suggest that substantial amounts of CO2 can be trapped within permeable sections of a reservoir by capillary forces and intra‐reservoir heterogenities, but there is little experimental observation of these phenomena. We report the results of CO2 core flooding experiments at high pressure and temperature performed to investigate the impact of natural capillary heterogeneity in a sandstone rock on CO2 saturation buildup and trapping. CO2 and water were injected through a Mt. Simon sandstone core at 9 MPa pore pressure and 50°C. The core had two regions of distinct capillarity: An upstream 10 cm long region of the core consisted of a relatively high permeability and homogenous sand. A downstream 3 cm long region of the core consisted of a low permeability region characterized by significant cross‐bedding and a high capillary entry pressure for CO2. During a drainage process of CO2 displacing water, CO2 builds up upstream of the capillary barrier. Once in place, CO2 on the upstream side of the barrier cannot be displaced during 100% water flooding leading to trapped saturations that are a factor 2–5 times higher than what would be expected from residual trapping alone.

Parallel simulation of concentration dynamics of nano-particles in High Gradient Magnetic Separation

In this paper, the concentration dynamics of weakly magnetic nano-particles dispersed in a fluid medium during the process of High Gradient Magnetic Separation is studied by using a computational approach. The continuity equations describing the time rate of change of the particle volume concentration in the system are solved numerically by using the finite difference method as initial and boundary value problems. Features of the concentration distribution in the system are depicted both in transient and steady states. Saturation buildup at the steady state and the time required for the occurrence of saturation buildup are given as basic guides for experiments. Parallel algorithms are implemented for simulations of concentration dynamics. The approaches are based on a distributed model, utilizing the message passing interface. Two schemes of parallel computing are developed based on different data-partitioning patterns and benchmark results are compared.

Effect of surfactants on wettability of near-wellbore regions of gas reservoirs

The flow of gas in tight, low-pressure gas wells can be partially blocked by the water saturation build-up near the hydraulic fracture face if the drawdown pressure does not exceed the capillary pressure. To increase the productivity, the water saturation may be reduced by alteration of the near-wellbore wettability from water-wet conditions to intermediate-wet conditions. Many surfactants have been identified which change the wettability of carbonate and sandstone rocks from water-wet to intermediate-wet in water–air–rock systems. Among fluorosilanes, as the number of fluoro groups increases, rocks become less water-wet. One day of aging period and 1 wt.% concentration appear to be sufficient for altering wettability. Interaction with field brine plays a crucial role in selection of appropriate surfactants. The increase in gas relative permeability due to the change in wettability is a function of the pressure gradient.

Production of gas from waterflood residual oil: gas saturation build-up and relative permeabilities

When solution gas is released from waterflooded residual oil by depressurization, the gas becomes mobilized after the critical gas saturation has been reached, but the gas saturation continues to increase as more gas is generated. The rate of gas saturation change plus the unrecoverable gas (gas saturation remaining at the end of the depressurization) are important in determining the economic performance of the process. The values depend upon the rate of gas generation and the gas relative permeability. Experiments are reported to measure water and gas relative permeabilities when gas is released from waterflooded residual oil. The values for the gas phase were extremely low, approximately an order of magnitude lower than would be predicted using a Corey-type equation suggesting that gas relative permeabilities measured in normal gas–water displacement experiments are not applicable to the depressurization of waterflooded reservoirs. The low values of gas relative permeabilities can be explained by the fact that the filaments which form the channels for gas flow are not stable, and that the flow is intermittent. Visual observations of the flow behaviour in micromodels have confirmed this. As a result, the effective total area for flow at any particular gas saturation is substantially reduced, thus reducing the permeability to the gas. New algorithms need to be introduced into the network models for estimating relative permeabilities in these situations before they can be used to represent the cyclical nature of filament rupture and reformation.

Comments on the hysteresis of the saturation buildup in the axial HGMS configuration

The values of the saturated buildup mass m/sub s/ during the process of deposition-removal of paramagnetic particles in the axial HGMS configuration were studied. When removing particles from a saturated buildup by decreasing the magnetic field H or increasing the flow velocity /spl nu/, a quasiremanence appears concretized in a mass difference /spl Delta/m/sub s/. The mass difference depends on both the field decrease /spl Delta/H and velocity increase /spl Delta//spl nu/. Besides the final state parameters H, /spl nu/, the saturated buildup mass depends also on the deposition history, thus showing a hysteresis phenomenon. The cause of this phenomenon consists in the higher friction force, due to the increased coefficients of static friction between the particles.

Third SPE Comparative Solution Project: Gas Cycling of Retrograde Condensate Reservoirs

Nine companies participated in this artificial modeling study of gas cycling in a rich retrograde-gas-condensate reservoir. Surface oil rate predictions differ in the early years of cycling but agree better late in cycling. The amount of condensate precipitated near the production well and its rate of evaporation varied widely among participants. The explanation appears to be in K-value techniques used. Precomputed tables for K values produced rapid and thorough removal of condensate during later years of cycling. Equation-of-state (EOS) methods produced a stabilized condensate saturation sufficient to flow liquid during the greater part of cycling, and the condensate never completely revaporized. We do not know which prediction is more nearly correct because our PVT data did not cover the range of compositions that exists in this area of the reservoir model.

Particle accumulation on a single wire in transverse HGMS configuration

An experimental investigation of particle accumulation on a single wire in the transverse HGMS configuration is presented. For saturation buildup we obtain a monotonic decrease of the coefficient of static frictionfsat with the flow velocityva on the basis of the “friction model”. The power law of the dependence of the saturation accumulation area onva, predicted by this model, is experimentally verified. Furthermore, we present an empirical law describing the dependence of the accumulation area on timeτ and on flow velocityva for the entire buildup process. From the investigation of the initial accumulation we conclude that existing theories of the so-called capture radius do not satisfactorily describe the situation near the end of a capture wire.

A new model for the explanation of the saturation buildup in the transverse HGMS-configuration

A model for the description of saturation buildup curves on single-capture elements is presented. It avoids the principal difficulties connected with the so-called SEB model in the case of the transverse HGMS-geometry. The basic idea of this model consists of the “linking” of the normal and tangential components of the forces acting at the buildup surface by a force of static friction. In contrast to the SEB-model the fact that the saturation buildup surface is neither circular nor concentric with the cross section of the capture element is taken into account. After evaluating two sets of experimental data and calculating the coefficient of static frictionf the “model of static friction” is submitted to a first examination. Within the accuracy of these preliminary measurements and even with an approximate evaluation of the fluid drag force the usefulness of the proposed method is established.

Particle buildup on single spheres in HGMS

Experimental and theoretical investigations of the initial and saturated buildup on single spheres are presented here. It is found that the time dependence of the initial accumulation radii can be expressed in terms of power laws and also that the saturation buildup can be well described by the static equilibrium model if the particle radius is used as a fitting parameter. Furthermore, a characteristic asymmetry of the buildup in the transverse configuration is reported and found to be of hydrodynamic origin.