Assessment of CO2 Injectivity During Sequestration in Depleted Gas Reservoirs

Abstract

Depleted gas reservoirs are appealing targets for carbon dioxide (CO 2 ) sequestration because of their storage capacity, proven seal, reservoir characterization knowledge, existing infrastructure, and potential for enhanced gas recovery. Low abandonment pressure in the reservoir provides additional voidage-replacement potential for CO 2 and allows for a low surface pump pressure during the early period of injection. However, the injection process poses several challenges. This work aims to raise awareness of key operational challenges related to CO 2 injection in low-pressure reservoirs and to provide a new approach to assessing the phase behavior of CO 2 within the wellbore. When the reservoir pressure is below the CO 2 bubble-point pressure, and CO 2 is injected in its liquid or supercritical state, CO 2 will vaporize and expand within the well-tubing or in the near-wellbore region of the reservoir. This phenomenon is associated with several flow assurance problems. For instance, when CO 2 transitions from the dense-state to the gas-state, CO 2 density drops sharply, affecting the wellhead pressure control and the pressure response at the well bottom-hole. As CO 2 expands with a lower phase viscosity, the flow velocity increases abruptly, possibly causing erosion and cavitation in the flowlines. Furthermore, CO 2 expansion is associated with the Joule–Thomson (IJ) effect, which may result in dry ice or hydrate formation and therefore may reduce CO 2 injectivity. Understanding the transient multiphase phase flow behavior of CO 2 within the wellbore is crucial for appropriate well design and operational risk assessment. The commonly used approach analyzes the flow in the wellbore without taking into consideration the transient pressure response of the reservoir, which predicts an unrealistic pressure gap at the wellhead. This pressure gap is related to the phase transition of CO 2 from its dense state to the gas state. In this work, a new coupled approach is introduced to address the phase behavior of CO 2 within the wellbore under different operational conditions. The proposed approach integrates the flow within both the wellbore and the reservoir at the transient state and therefore resolves the pressure gap issue. Finally, the energy costs associated with a mitigation process that involves CO 2 heating at the wellhead are assessed.

You learn as long as you drill; research synthesis from the Longyearbyen CO2 Laboratory, Svalbard, Norway

“…The severe underpressure encountered in the lower and middle storage units (Braathen et al, 2012;Birchall et al, in review) would lead to gas-phase CO 2 in the initial phase, though this may change to a denser liquid phase as reservoir pressure increases during injection. Clearly, the shallow reservoir depth and the severe underpressure are potential operational challenges, with similarities to sequestering CO 2 in depleted (i.e., anthropogenic underpressure) hydrocarbon fields (Hoteit et al, 2019), and careful site-specific evaluation is required to maintain adequate injection rates. The water-injection tests, however, clearly confirm better than expected fluid injectivity, even given the low-moderate permeability.…”

Co-Optimization of CO2 Storage and Enhanced Gas Recovery Using Carbonated Water and Supercritical CO2

“…Despite their density and viscosity contrasts, these two components are miscible at reservoir conditions [22]. Their miscibility is driven by mechanical mixing, dispersion, and molecular diffusion [18,[24][25][26][27]. A major problem caused by this mixing is the early breakthrough of CO 2 to the production wells [19,28,29].…”

Semi-Analytical Solution to Assess CO2 Leakage in the Subsurface through Abandoned Wells

“…There are currently around 60 large-scale CCS facilities under operation or development worldwide, resulting in 30 million metric tons (Mt) of CO 2 captured and stored per year in 2020 [9]. The storage potential of CCS is different for various underground formations like saline aquifers and depleted oil and gas reservoirs [10][11][12]. Subsurface reservoirs with production history could be preferred because of their cost-effectiveness in using existing infrastructure and knowledge about the subsurface geology.…”