1 Effective Constitutive Relations for Simulating CO 2 Capillary Trapping in Heterogeneous Reservoirs with Fluvial Sedimentary Architecture

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Effective Constitutive Relations for Simulating CO2 Capillary Trapping in Heterogeneous

Reservoirs with Fluvial Sedimentary Architecture

Naum I. Gershenzon1, Robert W. Ritzi Jr.1, David F. Dominic1, Edward Mehnert2

1Department of Earth and Environmental Sciences, Wright State University, 3640 Col. Glenn

Hwy., Dayton, OH 45435, USA

2Illinois State Geological Survey, Prairie Research Institute, University of Illinois at Urbana-

Champaign, 615 East Peabody Drive, Champaign, IL 61820, USA

Corresponding author: Naum I. Gershenzon,

Tel: +1 937-775-2052,

e-mail: naum.gershenzon@wright.edu

Published in Geomechanics and Geophysics for Geo-Energy and Geo-Resources, 3, pages 265–

279 (2017); DOI 10.1007/s40948-017-0057-3

In the article several formulae should be corrected; see erratum to this article at the end.

Abstract

Carbon dioxide (CO2) storage reservoirs commonly exhibit sedimentary architecture that reflects

fluvial deposition. The heterogeneity in petrophysical properties arising from this architecture

influences the dynamics of injected CO2. We previously used a geocellular modeling approach to

represent this heterogeneity, including heterogeneity in constitutive saturation relationships. The

dynamics of CO2 plumes in fluvial reservoirs was investigated during and after injection. It was

shown that small-scale (centimeter to meter) features play a critical role in capillary trapping

processes and have a primary effect on physical- and dissolution-trapping of CO2, and on the

ultimate distribution of CO2 in the reservoir. Heterogeneity in saturation functions at that small

scale enhances capillary trapping (snap off), creates capillary pinning, and increases the surface

area of the plume. The understanding of these small-scale trapping processes from previous work

is here used to develop effective saturation relationships that represent, at a larger scale, the integral

effect of these processes. While it is generally not computationally feasible to represent the small-

scale heterogeneity directly in a typical reservoir simulation, the effective saturation relationships

for capillary pressure and relative permeability presented here, along with an effective intrinsic

permeability, allow better representation of the total physical trapping at the scale of larger model

grid cells, as typically used in reservoir simulations, and thus the approach diminishes limits on

cell size and decreases simulation time in reservoir simulations.

Keywords: CO2 sequestration, CO2 trapping, fluvial reservoir, effective constitutive relations

1. Introduction

One of the strategies being evaluated for reducing the atmospheric accumulation of

greenhouse gasses is to capture carbon dioxide (CO2) and inject it into geologic reservoirs for

permanent sequestration (e.g., IPCC, 2005, Gale et al. 2015). Assessment of this strategy includes

computational studies of how reservoir heterogeneity, over a range of scales, affects processes

governing the dynamics, distribution, trapping, dissolution, mineralization, and ultimate fate of

injected CO2. Injection of CO2 is also used for enhanced oil recovery (e.g., Ampomah et al. 2016;

Dai et al. 2016; Soltanian et al. 2016). Here the focus is on the dynamics, distribution, and capillary

trapping of CO2 in the permeable part of the reservoir.

As reviewed by Krevor et al. (2015), a significant body of evidence, including results from

laboratory studies, computational studies, and from field pilot injection tests, now indicates that

residual trapping in the permeable part of the reservoir will be a primary mechanism for physically

immobilizing CO2 until it dissolves and mineralizes. Capillary trapping processes can be expected

create residual CO2 saturations of 20 to 30 percent in the permeable part of the reservoir; residual

CO2 that will not reach structural seals (e.g., shale cap-rock). Reservoirs without structural seals

are now being considered in some inventories of U.S. storage capacity. Krevor et al. (2015)

reviewed the pore-scale process of snap-off trapping within this context, and how it is represented

in constitutive relationships through the hysteresis in capillary pressure and relative permeability

as a function of phase saturation. One of their conclusions was that the influence of natural rock

heterogeneity on residual trapping processes should be further investigated.

Here we consider natural rock heterogeneity associated with fluvial sedimentary

architecture, as found in a number of candidate CO2 reservoirs (Fig. 1). Recent work has shown

how this type of sedimentary architecture can influence the residual trapping process in the

permeable section of the reservoir (Gershenzon et al. 2014, 2015, 2016a, b, 2017; Trevisan et al.

2017a and b). Fig. 1 shows how fluvial bar deposits comprise sets of relatively finer- and coarser-

grained cross strata (FG and CG rock types hereafter). In fluvial reservoirs such as the Lower Mt.

Simon (Illinois, USA), these differences in grain size are the primary influence of variability in

intrinsic permeability (Ritzi et al., 2016) within the permeable section of the reservoir. Fig. 2 is a

model for these cross strata used in our previous work. As discussed in previous descriptions of

this model, at 24% the CG cross sets percolate in 3-D (i.e., connect along tortuous pathways across

any opposing boundaries of the domain) though this is not evident on the 2-D faces of the model.

Connectivity is mostly vertical across a single unit bar, and tortuous laterally branching

connections occur at the scale of assemblages of unit bars within a compound bar. Note also that

the cross strata dip downward in the direction of paleoflow. The nature of these connections is

important in the context of residual trapping. In addition to snap-off trapping, the sedimentary

architecture creates capillary pinning. Though the FG cross sets are permeable relative to cap-rock

seals and other larger-scale strata, their lower permeability relative to CG strata within the overall

bar deposits enhances residual trapping within the larger bar deposits.

Fig. 1. Reservoir rock originally deposited by fluvial processes contains compound bar deposits

(blue line), that comprise unit bar deposits (green line) that, in turn, comprise sets of finer- and

coarser-grained cross strata. In some such reservoirs, such as the Lower Mt. Simon (Illinois, USA),

these differences in grain size are the primary influence of variability in intrinsic permeability

(Ritzi et al., 2016).

Fig. 2 The image on the top shows the distribution of FG (red) and CG (blue) cross sets in the

simulated reservoir, and the panel on the bottom shows the corresponding permeability. The cross

sets are organized in unit bar deposits which are, in turn, organized within compound bar deposits.

See Gershenzon et al. (2015) for images showing the larger-scale stratification. Here, in imaging

permeability, only the coarser grained, more permeable cross sets are readily discerned, because

of the orders-of-magnitude larger permeability. Vertical exaggeration is 10×

As shown in Fig. 3, the heterogeneity inside of bar deposits creates a significant amount of

residual trapping which includes this capillary pinning. Consider a CG cross set as shown in Fig.

4, with thickness



. Because of downward dip and complex, tortuous connectivity, along with

vertical rise of buoyant CO2, the local thickness is relevant to trapping. CO2 has preferentially

entered the CG cross set because of the relatively higher permeability and lower entry pressure

through CG pathways. It will not buoyantly rise up into the overlying FG cross strata unless a

critical capillary pressure is exceeded:

CG e FG

P P g



= − 

(1)

where





is the buoyant force upward per area within this cross set;

2w CO

  

 = −

;



and

2CO



are the density of brine and supercritical CO2, respectively; g is the gravitational constant;

and

FGe

is the capillary entry pressure of CO2 for the FG rock type. Fig. 5 illustrates Eq. [1]. The

region included in the white square in Fig. 3 shows that at the saturation occurring within the CG

cross sets,

is not exceeded, and thus significant capillary pinning is occurring in the CG cross

sets in reservoir simulations. The larger body of work studying this process suggests that this result

will be common (Gershenzon et al. 2016b) over a wide range of scenarios.

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1EffectiveConstitutiveRelationsforSimulatingCO2CapillaryTrappinginHeterogeneousReservoirswithFluvialSedimentaryArchitectureNaumI.Gershenzon1,RobertW.RitziJr.1,DavidF.Dominic1,EdwardMehnert21DepartmentofEarthandEnvironmentalSciences,WrightStateUniversity,3640Col.GlennHwy.,Dayton,OH45435,USA2IllinoisS...

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1 Effective Constitutive Relations for Simulating CO 2 Capillary Trapping in Heterogeneous Reservoirs with Fluvial Sedimentary Architecture

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