Experimental Investigation of Critical Parameters Controlling CH4− CO2 Exchange in Sedimentary CH4 Hydrates

Sequestration of CO2 in natural gas hydrate reservoirs may offer stable long-term deposition of a greenhouse gas while benefiting from CH4 gas production. In this paper, we review old and present new experimental studies of CH4–CO2 exchange in CH4 hydrate-bearing sandstone core plugs. CH4 hydrate was formed in Bentheim sandstone core plugs to prepare for subsequent lab-scale CH4 gas production by CO2 replacement. The effect of temperature, diffusion length, salinity, water saturation, CH4 hydrate saturation, and co-injection of chemicals (N2 and monoethanolamine) with the injected CO2 were measured. The measurements prove the critical role of water saturation in these processes: formation of CO2 hydrate severely reduced the injectivity for water saturations above 0.1 fractions. The results presented in this paper are important when assessing natural gas hydrate reservoirs as candidates for CO2 injection with concurrent CH4 gas production.publishedVersio

Unsteady-state CO2 foam injection for increasing enhanced oil recovery and carbon storage potential

The efficiency of CO2 injection for enhanced oil recovery and carbon storage is limited by severe viscosity and density differences between CO2 and reservoir fluids and reservoir heterogeneity. In-situ generation of CO2 foam can improve the mobility ratio to increase oil displacement and CO2 storage capacity in geological formations. The aim of this work was to investigate the ability of CO2 foam to increase oil production and associated CO2 storage potential, compared to other CO2 injection methods, in experiments that deploy field-scale injection strategies. Additionally, the effect of oil on CO2 foam generation and stability was investigated. Three different injection strategies were implemented in the CO2 enhanced oil recovery and associated CO2 storage experiments: pure CO2 injection, water-alternating-gas and surfactant-alternating-gas. Foam generation during surfactantalternating-gas experiments showed reduced CO2 mobility compared to water-alternatinggas and pure CO2 injections indicated by the increase in apparent viscosity. CO2 foam increased oil recovery by 50% compared to pure CO2 injection and 25% compared to water-alternating-gas. In addition, CO2 storage capacity increased from 12% during pure CO2 injection up to 70% during surfactant-alternating-gas injections. Experiments performed at high oil saturations revealed a delay in foam generation until a critical oil saturation of 30% was reached. Oil/water emulsions in addition to CO2 foam generation contributed to CO2 mobility reduction resulting in increased CO2 storage capacity with foam.Cited as: Sæle, A., Graue, A., Alcorn, Z. P. Unsteady-state CO2 foam injection for increasing enhanced oil recovery and carbon storage potential. Advances in Geo-Energy Research, 2022, 6(6): 472-481. https://doi.org/10.46690/ager.2022.06.0

Effects of salinity on hydrate stability and implications for storage of CO2 in natural gas hydrate reservoirs

The win-win situation of CO2 storage in natural gas hydrate reservoirs is attractive for several reasons in addition to the associated natural gas production. Since both pure CO2 and pure methane form structure I hydrate there is no expected volume change by replacing the in situ methane with CO2, and there is not net production of associated water which requires extra handling. The geo-mechanical implication of the first of these may be a very important issue since hydrates in unconsolidated sediments are the most promising targets for exploitation of natural gas. The stability of CO2 stored in the form of hydrate is probably one of the safest options today, even though also this option relates to safety of sealing cap-rock or clay layer. The stability of hydrates in a reservoir depends on many factors, including the interactions between minerals, surrounding fluids and hydrate. The natural level of salinity increases with depth in a reservoir. In addition formation of hydrate will lead to increased salinity of the fluids surrounding the formed hydrate. This may lead to liquid pockets of residual aqueous solution with increased salinity as well as very non-uniform hydrate. The latter due to the fact that hydrate composition and stability relates to properties of surrounding fluids. In the work presented here methane hydrates were formed in several sandstone cores. The cores were all partially saturated with brine of different salinities in order to identify the effect salinity has on the fill fraction, the amount of methane per available structural site in hydrates. The results indicate that salinities lower than regular sea water composition has no significant impact on the fill fraction of methane hydrate in porous media. When the salinity surpasses regular sea water composition there is a significant drop in fill fraction. The methane hydrate fill fraction is dominated by total brine salinity rather than brine distribution in the core.publishedVersio

Unsteady-state CO2 foam injection for increasing enhanced oil recovery and carbon storage potential

The efficiency of CO2 injection for enhanced oil recovery (EOR) and carbon storage is limited by severe viscosity and density differences between CO2 and reservoir fluids and reservoir heterogeneity. In-situ generation of CO2 foam can improve the mobility ratio to increase oil displacement and CO2 storage capacity in geological formations. The aim of this work was to investigate the ability of CO2 foam to increase oil production and associated CO2 storage potential, compared to other CO2 injection methods, in experiments that deploy field-scale injection strategies. Additionally, the effect of oil on CO2 foam generation and stability was investigated. Three different injection strategies were implemented in the CO2 EOR and associated CO2 storage experiments: pure CO2 injection, water-alternating-gas (WAG) and surfactant-alternating-gas (SAG). Foam generation during SAG experiments showed reduced CO2 mobility compared to WAG and pure CO2 injections indicated by the increase in apparent viscosity. CO2 foam increased oil recovery by 50% compared to pure CO2 injection and 25% compared to WAG. In addition, CO2 storage capacity increased from 12% during pure CO2 injection up to 70% during SAG injections. Experiments performed at high oil saturations revealed a delay in foam generation until a critical oil saturation of 30% was reached. Oil/water emulsions in addition to CO2 foam generation contributed to CO2 mobility reduction resulting in increased CO2 storage capacity with foam.publishedVersio

Transport and storage of CO2 in natural gas hydrate reservoirs

Storage of CO2 in natural gas hydrate reservoirs may offer stable long term deposition of a greenhouse gas while benefiting from methane production, without requiring heat. By exposing hydrate to a thermodynamically preferred hydrate former, CO2, the hydrate may be maintained macroscopically in the solid state and retain the stability of the formation. One of the concerns, however, is the flow capacity in such reservoirs. This in turn depends on three factors; 1) thermodynamic destabilization of hydrate in small pores due to capillary effects, 2) the presence of liquid channels separating the hydrate from the mineral surfaces and 3) the connectivity of gas- or liquid filled pores and channels. This paper reports experimental results of CH4- CO2 exchange within sandstone pores and measurements of gas permeability during stages of hydrate growth in sandstone core plugs. Interactions between minerals and surrounding molecules are also discussed. The formation of methane hydrate in porous media was monitored and quantified with magnetic resonance imaging techniques (MRI). Hydrate growth pattern within the porous rock is discussed along with measurements of gas permeability at various hydrate saturations. Gas permeability was measured at steady state flow of methane through the hydrate-bearing core sample. Experiments on CO2 injection in hydrate-bearing sediments was conducted in a similar fashion. By use of MRI and an experimental system designed for precise and stabile pressure and temperature controls flow of methane and CO2 through the sandstone core proved to be possible for hydrate saturations exceeding 60%.publishedVersio

Pressure Measurements for Monitoring CO2 Foam Pilots

This study focuses on the use of pressure measurements to monitor the effectiveness of foam as a CO2 mobility control agent in oil-producing reservoirs. When it is applied optimally, foam has excellent potential to improve reservoir sweep efficiency, as well as CO2 utilization and storage, during CO2 Enhanced Oil Recovery (EOR) processes. In this study, we present part of an integrated and novel workflow involving laboratory measurements, reservoir modeling and monitoring. Using the recorded bottom-hole pressure data from a CO2 foam pilot study, we demonstrate how transient pressures could be used to monitor CO2 foam development inside the reservoir. Results from a recent CO2 foam pilot study in a heterogeneous carbonate field in Permian Basin, USA, are presented. The injection pressure was used to evaluate the development of foam during various foam injection cycles. A high-resolution radial simulator was utilized to study the effect of foam on well injectivity, as well as on CO2 mobility in the reservoir during the surfactant-alternating gas (SAG) process. Transient analysis indicated constant temperature behavior during all SAG cycles. On the other hand, differential pressures consistently increased during the surfactant injection and decreased during the subsequent CO2 injection periods. Pressure buildup during the periods of surfactant injection indicated the development of a reduced mobility zone in the reservoir. The radial model proved to be useful to assess the reservoir foam strength during this pilot study. Transient analysis revealed that the differential pressures during the SAG cycles were higher than the pressures observed during the water-alternating gas (WAG) cycle which, in turn, showed foam generation and reduced CO2 mobility in the reservoir. Although pressure data are a powerful indicator of foam strength, additional measurements may be required to describe the complex physics of in situ foam generation. In this pilot study, it appeared that the reservoir foam strength was weaker than that expected in the laboratory.publishedVersio

Unsteady-State CO2 Foam Generation and Propagation: Laboratory and Field Insights

This work presents a multiscale experimental and numerical investigation of CO2 foam generation, strength, and propagation during alternating injection of surfactant solution and CO2 at reservoir conditions. Evaluations were conducted at the core-scale and with a field-scale radial simulation model representing a CO2 foam field pilot injection well. The objective of the experimental work was to evaluate foam generation, strength, and propagation during unsteady-state surfactant-alternating-gas (SAG) injection. The SAG injection rapidly generated foam based upon the increased apparent viscosity compared to an identical water-alternating-gas (WAG) injection, without surfactant. The apparent foam viscosity of the SAG continually increased with each subsequent cycle, indicating continued foam generation and propagation into the core. The maximum apparent viscosity of the SAG was 146 cP, whereas the maximum apparent viscosity of the WAG was 2.4 cP. The laboratory methodology captured transient CO2 foam flow which sheds light on field-scale CO2 foam flow. The single-injection well radial reservoir simulation model investigated foam generation, strength, and propagation during a recently completed field pilot. The objective was to tune the model to match the observed bottom hole pressure data from the foam pilot and evaluate foam propagation distance. A reasonable match was achieved by reducing the reference mobility reduction factor parameter of the foam model. This suggested that the foam generated during the pilot was not as strong as observed in the laboratory, but it has propagated approximately 400 ft from the injection well, more than halfway to the nearest producer, at the end of pilot injection.publishedVersio

Core-scale sensitivity study of CO2 foam injection strategies for mobility control, enhanced oil recovery, and CO2 storage

This paper presents experimental and numerical sensitivity studies to assist injection strategy design for an ongoing CO2 foam field pilot. The aim is to increase the success of in-situ CO2 foam generation and propagation into the reservoir for CO2 mobility control, enhanced oil recovery (EOR) and CO2 storage. Un-steady state in-situ CO2 foam behavior, representative of the near wellbore region, and steady-state foam behavior was evaluated. Multi-cycle surfactant-alternating gas (SAG) provided the highest apparent viscosity foam of 120.2 cP, compared to co-injection (56.0 cP) and single-cycle SAG (18.2 cP) in 100% brine saturated porous media. CO2 foam EOR corefloods at first-contact miscible (FCM) conditions showed that multi-cycle SAG generated the highest apparent foam viscosity in the presence of refined oil (n-Decane). Multi-cycle SAG demonstrated high viscous displacement forces critical in field implementation where gravity effects and reservoir heterogeneities dominate. At multiple-contact miscible (MCM) conditions, no foam was generated with either injection strategy as a result of wettability alteration and foam destabilization in presence of crude oil. In both FCM and MCM corefloods, incremental oil recoveries were on average 30.6% OOIP regardless of injection strategy for CO2 foam and base cases (i.e. no surfactant). CO2 diffusion and miscibility dominated oil recovery at the core-scale resulting in high microscopic CO2 displacement. CO2 storage potential was 9.0% greater for multi-cycle SAGs compared to co-injections at MCM. A validated core-scale simulation model was used for a sensitivity analysis of grid resolution and foam quality. The model was robust in representing the observed foam behavior and will be extended to use in field scale simulations.publishedVersio

Enabling Large-Scale Carbon Capture, Utilisation, and Storage (CCUS) Using Offshore Carbon Dioxide (CO2) Infrastructure Developments - A Review

Presently, the only offshore project for enhanced oil recovery using carbon dioxide, known as CO2-EOR, is in Brazil. Several desk studies have been undertaken, without any projects being implemented. The objective of this review is to investigate barriers to the implementation of large-scale offshore CO2-EOR projects, to identify recent technology developments, and to suggest non-technological incentives that may enable implementation. We examine differences between onshore and offshore CO2-EOR, emerging technologies that could enable projects, as well as approaches and regulatory requirements that may help overcome barriers. Our review shows that there are few, if any, technical barriers to offshore CO2-EOR. However, there are many other barriers to the implementation of offshore CO2-EOR, including: High investment and operation costs, uncertainties about reservoir performance, limited access of CO2 supply, lack of business models, and uncertainties about regulations. This review describes recent technology developments that may remove such barriers and concludes with recommendations for overcoming non-technical barriers. The review is based on a report by the Carbon Sequestration Leadership Forum (CSLF).publishedVersio

Effects of salinity on hydrate stability and implications for storage of CO2 in natural gas hydrate reservoirs

The win-win situation of CO2 storage in natural gas hydrate reservoirs is attractive for several reasons in addition to the associated natural gas production. Since both pure CO2 and pure methane form structure I hydrate there is no expected volume change by replacing the in situ methane with CO2, and there is not net production of associated water which requires extra handling. The geo-mechanical implication of the first of these may be a very important issue since hydrates in unconsolidated sediments are the most promising targets for exploitation of natural gas. The stability of CO2 stored in the form of hydrate is probably one of the safest options today, even though also this option relates to safety of sealing cap-rock or clay layer. The stability of hydrates in a reservoir depends on many factors, including the interactions between minerals, surrounding fluids and hydrate. The natural level of salinity increases with depth in a reservoir. In addition formation of hydrate will lead to increased salinity of the fluids surrounding the formed hydrate. This may lead to liquid pockets of residual aqueous solution with increased salinity as well as very non-uniform hydrate. The latter due to the fact that hydrate composition and stability relates to properties of surrounding fluids. In the work presented here methane hydrates were formed in several sandstone cores. The cores were all partially saturated with brine of different salinities in order to identify the effect salinity has on the fill fraction, the amount of methane per available structural site in hydrates. The results indicate that salinities lower than regular sea water composition has no significant impact on the fill fraction of methane hydrate in porous media. When the salinity surpasses regular sea water composition there is a significant drop in fill fraction. The methane hydrate fill fraction is dominated by total brine salinity rather than brine distribution in the core