Catriona Reynolds

Characterizing flow behavior for gas injection: Relative permeability of CO2-brine and N2-water in heterogeneous rocks

We provide a comprehensive experimental study of steady state, drainage relative permeability curves with CO2-brine and N2-deionized water, on a single Bentheimer sandstone core with a simple two-layer heterogeneity. We demonstrate that, if measured in the viscous limit, relative permeability is invariant with changing reservoir conditions, and is consistent with the continuum-scale multiphase flow theory for water wet systems. Furthermore, we show that under capillary limited conditions, the CO2-brine system is very sensitive to heterogeneity in capillary pressure, and by performing core floods under capillary limited conditions, we produce effective relative permeability curves that are flow rate and fluid parameter dependent. We suggest that the major uncertainty in past observations of CO2-brine relative permeability curves is due to the interaction of CO2 flow with pore space heterogeneity under capillary limited conditions and is not due to the effects of changing reservoir conditions. We show that the appropriate conditions for measuring intrinsic or effective relative permeability curves can be selected simply by scaling the driving force for flow by a quantification of capillary heterogeneity. Measuring one or two effective curves on a core with capillary heterogeneity that is representative of the reservoir will be sufficient for reservoir simulation.

Dynamic fluid connectivity during steady-state multiphase flow in a sandstone

Significance The movement of immiscible fluids through permeable media occurs in many settings, including oil and water flow through rock. Here we present observations of a previously unidentified type of steady-state flow behavior that we term “dynamic connectivity.” We demonstrate that flow of the nonwetting phase occurs through a network of connections that continuously rearrange between filled pores. This observation suggests that we need to modify our models of two-phase flow that are fundamental to describing subsurface flow processes such as geologic CO2 storage and hydrocarbon recovery. The current conceptual picture of steady-state multiphase Darcy flow in porous media is that the fluid phases organize into separate flow pathways with stable interfaces. Here we demonstrate a previously unobserved type of steady-state flow behavior, which we term “dynamic connectivity,” using fast pore-scale X-ray imaging. We image the flow of N2 and brine through a permeable sandstone at subsurface reservoir conditions, and low capillary numbers, and at constant fluid saturation. At any instant, the network of pores filled with the nonwetting phase is not necessarily connected. Flow occurs along pathways that periodically reconnect, like cars controlled by traffic lights. This behavior is consistent with an energy balance, where some of the energy of the injected fluids is sporadically converted to create new interfaces.

Advanced Reservoir Characterization for CO2 Storage

Abstract Injection of CO2 into the subsurface is of interest for CO2 storage and enhanced oil recovery (EOR). There are, however, major unresolved questions around the multiphase flow physics and reactive processes that will take place after CO2 is injected, particularly in carbonate rock reservoirs. For example, the wetting properties of CO2-brine-rock systems will impact the efficiency of EOR operations and CO2 storage but reported contact angles range widely from strongly water-wet to intermediate wet. Similar uncertainties exist for properties including the relative permeability and the impact of chemical reaction on flow. In this presentation we present initial results from laboratory studies investigating the physics of multiphase flow and reactive transport for CO2-brine systems. We use traditional and novel core flooding techniques and x-ray imaging to resolve uncertainties around the CO2-brine contact angle, relative permeability, residual trapping, and feedbacks between chemical reaction and flow in carbonate rocks.

Multiphase Flow Characteristics of Heterogeneous Rocks From CO2 Storage Reservoirs in the United Kingdom

We have studied the impact of heterogeneity on relative permeability and residual trapping for rock samples from the Bunter sandstone of the UK Southern North Sea, the Ormskirk sandstone of the East Irish Sea, and the Captain sandstone of the UK Northern North Sea. Reservoir condition CO2-brine relative permeability measurements were made while systematically varying the ratio of viscous to capillary flow potential, across a range of flow rates, fractional flow, and during drainage and imbibition displacement. This variation resulted in observations obtained across a range of core-scale capillary number 0.2<Nc=ΔPLHΔPc<200. Capillary pressure heterogeneity was quantitatively inferred from 3-D observations of the fluid saturation distribution in the rocks. For each of the rock samples, a threshold capillary number, 5<Nc<30, was found, below which centimeter-scale layering resulted in a heterogeneous distribution of the fluid phases and a commensurate impact on flow and trapping. The threshold was found to be dependent on the capillary number alone, irrespective of the displacement path (drainage or imbibition) and average fluid saturation in the rock. The impact of the heterogeneity on the relative permeability varied depending on the characteristics of the heterogeneity in the rock sample, whereas heterogeneity increased residual trapping in all samples above what would be expected from the pore-scale capillary trapping mechanism alone. Models of subsurface CO2 injection should use properties that incorporate the impacts of heterogeneity at the flow regime of interest or risk significant errors in estimates of fluid flow and trapping.

Characterizing Drainage Multiphase Flow in Heterogeneous Sandstones

In this work, we analyze the characterization of drainage multiphase flow properties on heterogeneous rock cores using a rich experimental data set and mm-m scale numerical simulations. Along with routine multiphase flow properties, 3-D submeter scale capillary pressure heterogeneity is characterized by combining experimental observations and numerical calibration, resulting in a 3-D numerical model of the rock core. The uniqueness and predictive capability of the numerical models are evaluated by accurately predicting the experimentally measured relative permeability of N2—DI water and CO2—brine systems in two distinct sandstone rock cores across multiple fractional flow regimes and total flow rates. The numerical models are used to derive equivalent relative permeabilities, which are upscaled functions incorporating the effects of submeter scale capillary pressure. The functions are obtained across capillary numbers which span four orders of magnitude, representative of the range of flow regimes that occur in subsurface CO2 injection. Removal of experimental boundary artifacts allows the derivation of equivalent functions which are characteristic of the continuous subsurface. We also demonstrate how heterogeneities can be reorientated and restructured to efficiently estimate flow properties in rock orientations differing from the original core sample. This analysis shows how combined experimental and numerical characterization of rock samples can be used to derive equivalent flow properties from heterogeneous rocks.