CO2-Foams for Enhanced Oil Recovery and CO2 Storage

Abstract

Human prosperity, economic growth and energy supply have shown a strong positive correlation from the start of the industrial revolution until the present. During the 20th century, cheap and reliable energy from fossil sources became abundantly available. Concerns regarding climate change, however, are increasingly problematized by contemporary scientists and policymakers. In particular, the emission of carbon dioxide (CO2) is considered an important issue to solve, as it is the main contributor to the greenhouse effect. Reducing CO2 emissions, while providing the world with cheap, plentiful and reliable energy will therefore be vital for a prosperous future. Atmospheric CO2 accumulation can be mitigated by capturing CO2 and storing it in suitable underground formations. Large-scale implementation of carbon capture and storage (CCS) can contribute to stabilize atmospheric greenhouse gas concentrations. For profit maximizing companies, implementation costs related to CCS are high compared to that associated with atmospheric release. Economic incentives can be significantly increased by using CO2 as an input parameter in a production process, thereby adding value to the end product. One alternative is to use anthropogenic CO2 for enhanced oil recovery (EOR), which promotes investments into safe CO2 storage while improving the oil production process. This synergy is likely to accelerate technological advances related to CO2 storage and reduce lifecycle emissions from the oil production projects. At reservoir conditions, CO2 has several advantageous characteristics for EOR purposes. For this reason, it has been implemented as an oil displacement agent for more than 50 years. Pure CO2 injection, however, has some inherent challenges due to density and viscosity differences between reservoir fluids and CO2. The former discrepancy causes CO2 to migrate towards the top of the reservoir, while the latter discrepancy promotes formation of viscous fingers and gas channeling through high permeable zones. Both effects are detrimental to oil recovery and CO2 storage, since unstable displacement fronts decrease sweep efficiency and reduce storage. Consequently, project profitability will be adversely affected through lower oil recovery. Reducing CO2 mobility is important to mitigate flow instabilities. In-situ foam generation is one possible solution, where a mixture of CO2 and brine with a foaming agent (surfactants or nanoparticles) has proven to significantly reduce CO2 mobility and front propagation. Foams are inherently thermodynamically unstable, but this aspect can be improved by optimizing type and concentration of the foaming agent. Surfactants have shown to generate strong foams through laboratory experiments (and partly in field trials), but might destabilize at tough reservoir conditions such as high temperatures and salinities. Nanoparticles are currently being evaluated as a foam agent and several laboratory results show great promise. High adhesive energies on interfaces, low cost and ability to remain stable in harsh environments are all properties advocating for further research. Compared to surfactants, nanoparticles as foaming agents for EOR is a novel technology and has as of yet not been tested in fields. This dissertation is part of two larger research projects on CO2-foam applications for storage and enhanced oil recovery: «Nanoparticles to Stabilize CO2-foam for Efficient CCUS in Challenging Reservoirs» (the Research Council of Norway project number 268216) and «CO2 Storage from Lab to On-Shore Field Pilots Using CO2-Foam for Mobility Control in CCUS» (the Research Council of Norway project number 249742). By implementing a bottom-up scientific approach, foam systems in sandstones and carbonates have been evaluated and optimized for EOR and CO2 storage performance. This dissertation consists of two parts. The first part contains the introduction, theoretical background and a review of key findings. It is intended to corroborate and summarize the six scientific papers listed in the second part. The main objective of this work is to provide new insight into CO2-foam behavior in porous media and optimize foam performance for field application. Adapting an experimental approach, two areas of focus are prioritized: i) delineating causal relationships between concepts and principles related to CO2-foam behavior in porous media; and ii) providing input to a field-scale simulation model to optimize foam performance in field trial. Paper 1 demonstrates the broad applicability of CO2 injection in a CCUS context. Ultralow permeabilities associated with shale oil formations exclude conventional waterflooding for EOR. Supercritical CO2 enabled flow through the matrix core plugs, resulting in (enhanced) oil production and associated CO2 storage. Observations indicated adverse effects from pure CO2 injection, including low sweep efficiency, early CO2 breakthrough and low oil recovery. Paper 2 implements a bottom-up multi-scale approach to evaluate surfactant-stabilized CO2-foams with a preselected field specific nonionic surfactant. Observations indicated strong foam generation with resulting flow diversion from co-injection of CO2 and surfactant solution on pore-scale. Increased thermodynamic stability was quantified during static, no-flow, tests over several days. Input parameters for a commercial foam simulation model were obtained from CO2 and CO2-foam injections in reservoir core plugs (end-point relative permeabilities, maximum mobility reduction factor and viscoelastic properties). The laboratory data suggested an optimal volumetric gas fraction between 0.60 and 0.70. EOR and CO2 storage were evaluated at reservoir conditions, showing higher CO2 storage and increased oil recovery during foam injections in presence of oil. Results indicated a carbon neutral oil production from CO2-foam injection, where 96% of the carbon atoms in the produced oil was stored (as CO2) in an ax-ante storage process. Paper 3 extends on the bottom-up approach from Paper 2 and evaluates CO2-foam performance in reservoir core plugs with reservoir fluids. Surfactant concentration (0.5 wt%), injection strategy (multi-cycle SAG) and slug sizes (macroscopic average gas fraction of 70%) were determined for field injection, based on experimental data and simulations. Paper 4 evaluated nanoparticles as possible foam stabilizers for CO2-foams in sandstones. Loss to the formation (retention) and stability during nanofluid flow through porous media were measured at 20ºC, with no observed decrease in flow potential. The ability of nanoparticles to stabilize CO2-foams was determined by comparing co-injections of nanofluid and CO2 to baseline co-injections (CO2 and brine without foaming agent). Foam generation and stabilization effects were observed through higher apparent viscosities. Results showed increased apparent viscosities from surfactant-stabilized foams (compared to nanoparticle-stabilized foams) administered at the same experimental conditions. Injection history and gas saturation indicated strong hysteretic effects during foam scans. Paper 5 extends on Paper 4 to investigate CO2-foam performance with two different nanoparticles and a surfactant in presence of crude oil. The temperature was increased from 20ºC to 60ºC, while the other experimental conditions remained constant. Emphasis was put on increasing statistical significance of reported data by performing several injection tests at identical conditions. Results showed that nanoparticles have a higher stabilizing effect on CO2-foams compared to surfactants, implying more resistance to destabilization from crude oil. Incremental oil recoveries, however, are similar for surfactant and nanoparticle-stabilized CO2-foams, suggesting different EOR mechanisms governing the displacement processes. Paper 6 examines the ability of nanoparticles to stabilize CO2-foams at tough reservoir conditions, such as increased temperatures, brine salinities and ionic strengths. The CO2 storage potential was quantified during foam injections in core plugs, and a parameter for calculating CO2 utilization was implemented. Nanoparticle-stabilized foams increased oil production and CO2 storage potential by displacing more oil and water during tertiary EOR compared to baseline injections.