(743e) Chemo-Mechanical Impacts on Morrow B Sandstone Reservoir and Caprock in an Active CO2 Injection Project, Farnsworth Field Unit, Texas.

Carbon capture, utilization, and storage (CCUS) is considered as one of the most effective technologies used to avert global warming. This technology uses CO₂ miscible and immiscible injections to enhance residual oil recovery after primary and secondary recovery phases. As such CCUS technology provides a solution to utilize and store CO₂ in underground reservoirs simultaneously. Unlike primary and secondary recovery stages, the usage of CO₂ as EOR and/or CO₂ sequestration medium introduces more complex geochemical and thermodynamical effects to the reservoirs. At the minimum miscibility pressure (MMP), the injected CO₂ dissolves in the oil phase, and this results in the alteration of fluid properties such as viscosity, density, compressibility, etc. The injected CO₂ may also undergo chemical reactions with the resident brine to form acidized brine. This acidized brine may react with the formation minerals leading to dissolution and/or precipitation of minerals that could ultimately alternate petrophysical properties such as porosity and permeability. Not only could these properties being changed by chemical reactions, but they may be changed due to stress changes during injection and production processes. More importantly, the stability of the caprock is analyzed to ensure that CO₂ is contained for a very long time without leaking. The injection of CO₂ may lead to an increase in the reservoir pore pressure. Variations in the pore pressure are always accompanied by changes in stress and strain; thus, the need to determine whether the mechanical damage is irreversible.

Objective

The main objective of this work is to investigate the chemo-mechanical impacts of CO₂ injection to a depleted oil reservoir and its caprock. A matured oil reservoir, Morrow B, from Farnsworth Unit, Texas will be studied through CO₂-water-alternate injection process.

Motivation

Even though current research works have brought on tremendous knowledge and insights, especially in the area of CO₂ storage, but there are still some aspects of numerical simulation of CO₂ sequestration operation that need further investigation, and that have served as the motivation for this work, and the novelties of this work are:

Novelty

1. CCUS operations involve three disciplines: hydrodynamics, geochemistry, and geomechanics. However, most of the published works have only coupled hydrodynamics with geochemistry or geomechanics, without considering the impacts of geochemistry and geomechanics concurrently. Therefore, this paper seeks to investigate the impacts of coupling all three disciplines.
2. To our best knowledge, most published simulation works lacked field data but used hypothetical cases to investigate the fundamental processes of CO₂ injection. In using a history-matched model, the simulation results could possess more confidence than an absolute hypothetical case.
3. While most CO₂ storage studies have concentrated on injection in deep saline aquifers, this work investigates the process in depleted oil reservoirs. It will expand the existing knowledge of CO₂ sequestration with comprehensive chemo-mechanical effects in depleted or matured oil reservoirs.

Methodology

The simulation model was constructed by an advanced multi-mechanism simulator that considered petrophysical and geological characterizations of the field. Laboratory experiments that investigated five hydraulic flow units (HFU) from the field were employed to populate the permeability and the relative permeability curves within the simulation model. The volume of CO₂ dissolved in the aqueous phase was modeled with Henry’s law under reservoir pressure, temperature, and salinity. The solubility of CO₂ in the oleic phase was governed by the CO₂ injection above the MMP. The relative gas hysteresis effect was employed to estimate the amount of residual CO₂ trapped in the porous media displacing the in-situ fluids. An Elemental Analysis (ELAN) was performed to determine the initial formation mineral compositions, and water samples collected from the field were analyzed to determine the initial formation brine ion composition. Further, the rock mechanical properties were acquired from core analysis and well logs. A numerical simulation model was then constructed with the afore mentioned input data and used to determine the amounts of CO₂ trapped by structural, residual, solubility, and mineral trapping mechanisms. The chemo-mechanical impacts on rock properties such as permeability and porosity were then investigated.

To couple the hydrodynamic and geomechanics, a two-way simulation approach was used. In this approach, the geomechanics model estimates stress and strain distributions and displacement using the pressure perturbations output from the hydrodynamic model within a prescribed time interval. The hydrodynamic model then updates the petrophysical properties using the output of the geomechanics model and estimates the pressure and saturation responses for the next time step interval. The numerical reservoir model was validated by a rigorous history matching process using 10-year of ternary recovery data. Four models were constructed from the history matched model: hydrodynamic-only model, coupled hydro-geochemical (HGC) model, coupled hydro-geomechanical (HGM) model, and coupled hydro-geochemical-mechanical (HGCM) model. These models were then used to forecast production for the next 20 years. Finally, the model ran for 1000 years post-injection period to monitor the CO₂ plume migration and its effects on the reservoir and to establish the long-term storage capacity of the field. The caprock integrity evaluation was based on multiple scenarios. The coupled hydro-geomechanical model simulation results with the current field operation strategies, that include production, and CO₂-water-alternate injection strategies, were analyzed for effects of pore pressure on group uplift, deformation, and CO₂ leakage into the overburden caprock. Other cases to be considered are to convert all CO₂-water-alternate wells into CO₂ injection-only wells, injecting at variable rates, and bottomhole pressure constraints without production. This will help ascertain the maximum allowable operating conditions in order to store CO₂ safely for a long time post-EOR operations.

Results

The preliminary results of this work showed that the geochemical reactions of CO₂ with the formation minerals did not have significant effects on porosity and permeability. The maximum change in porosity is 0.05%. However, after accounting for stresses within the reservoir, it exhibited relatively more impacts on porosity and permeability. The maximum changes in porosity and permeability are 0.6% and 2% respectively. Also, most CO₂ is stored as free gas in the reservoir, this is followed by residual gas, dissolution in oil, and aqueous phases. Considering the coupled hydro-geochemical-mechanical model, 48% of the stored CO₂ is free gas, 34% is stored as residual gas, 10% dissolved in the oleic phase and 8% dissolved in the aqueous phase. However, there is no CO₂ stored as carbonate mineral because calcite being the only carbonate mineral dissolved faster than it precipitated. Also, based on the preliminary results, the long-term fate analysis of the CO₂ storage shows that CO₂ is trapped within the reservoir and there is no leakage within the time frame of 1030 years considering the current field operating strategies. Other operating strategies would be considered to determine the maximum allowable CO₂ injection strategies for the Morrow B reservoir. The addition of geomechanics in CO₂ sequestration processes presents more realistic responses of the CO₂ injection to the depleted oil reservoir.

This study presents the evaluation of chemo-mechanical impacts during CO₂ injection in depleted oil reservoirs. The numerical simulation model successfully coupled hydrodynamic, geochemical, and geomechanical models by utilizing history-matched numerical simulation models to fill current gaps in CO₂ sequestration studies pertaining to oil reservoirs.