Search

Summary A field demonstration test using CO2 foam for enhanced oil recovery (EOR) is being implemented in a heterogeneous carbonate reservoir in the Permian Basin of Texas. CO2 as an oil recovery agent part of carbon capture, utilization, and storage (CCUS) has gained recent attention due to growing concerns regarding greenhouse gas emissions. Current CO2 flood performance suffers due to an unfavorable mobility ratio between injected CO2 and reservoir fluids resulting in poor macroscopic sweep efficiency. Foam aims to mitigate the technical challenges of ongoing CO2 injection by improving macroscopic sweep efficiency and oil recovery while storing CO2. As part of a field pilot research program, this study presents project and operational design, baseline data collection program, and pilot monitoring to mitigate the technical challenges with current CO2 injection and verify foam mobility control and CO2 storage. Pilot performance is assessed with the data collection program and includes a tracer program to characterize interwell connectivity, time lapse cross well seismic to improve the reservoir characterization and monitor saturations, injection profiles and fall-off tests to determine zones of injection and injection pressure, and daily measurements of rate and pressure at various stages throughout pilot operation.

Summary A CO2 foam field pilot research program has been initiated to test and advance the technology of CO2 foam systems with mobility control to optimize CO2 integrated EOR and CO2 storage. Previous CO2 foam pilot tests have analyzed field scale displacement mechanisms, foam’s effects on gas mobility, reservoir injectivity, and overall recovery. Past tests have shown variable amounts of success, establishing the need for a more integrated methodology for advancing CO2 foam technology for EOR. This work describes initial design, generation of geologic and dynamic reservoir models, laboratory investigations, and the application of a reservoir management workflow for a CO2 foam field pilot in the Permian Basin of west Texas, USA. Application of a reservoir management workflow guides a systematic approach from data gathering, model generation, and decision making to final implementation and analysis of the CO2 foam field pilots. Initial pilot design begins with an improved reservoir characterization, field pilot selection criteria, and laboratory studies. Laboratory work investigating foam’s behavior at variable pressures found that increased reservoir pressure will result in more favorable CO2 foam behavior as it will recover oil more effectively, considering the economic limits on CO2 and surfactant usage.

Carbon dioxide has been successfully used in fields as EOR agent; and because of technical, commercial and environmental reasons, it has received considerable attention in recent years over other solvents. Based on experience with CO2 flooding worldwide, it is well understood that despite its high local displacement efficiency, the process suffers from poor sweep efficiency due to reservoir heterogeneity, viscous instability and gravity override. Application of foam has been found to mitigate these limitations at laboratory scale, however understanding of CO2-Foam flow behaviour at a larger scale is limited industry-wide. Some of the previous pilots have shown technical success especially near wellbore, but there exist a need to establish an integrated methodology to scale-up the CO2-Foam technology efficiently and effectively. As part of an ongoing research program, we have identified a field with heterogeneous carbonate reservoir onshore in west Texas, USA to run CO2-Foam field trial. The research emphasizes on implementing a modelling, monitoring and verification approach as part of the roadmap. Static model created by integrating petrophysical logs and core data in-line with geologic framework, and dynamic model created based on analysis of reservoir engineering data including RCA, SCAL, PVT, pressure data and coreflood experiments forms the basis for reservoir simulation study for the pilot area. In this paper, we provide an overview of different elements of numerical model and demonstrate application of a probabilistic framework to incorporate the uncertainties associated with model inputs. The success will be validated via appropriate monitoring plan in the ongoing pilot research program.

Miscible CO2 and CO2-foam laboratory injection tests were performed to study Enhanced Oil Recovery (EOR) processes in strongly water-wet fractured carbonate core material to evaluate the potential of foam for mobility control. The experimental results demonstrate a significant oil recovery potential during pure scCO2 injection in baseline unfractured cores: endpoint oil recovery was up to 98%OOIP and 80%OOIP was produced after 2PVof scCO2 injection starting at Swi. Recovery and production rates were significantly lower and slower for fractured cores where oil recovery was mainly driven by diffusion: 58-68%OOIP was recovered after 10PV injected. By switching to scCO2-foam injection after 1-2PV of pure scCO2, a viscous component was added to the oil displacement process, which increased oil recovery rates and final recoveries for all experiments. Integrated EOR (IEOR) schemes of waterfloods followed by tertiary CO2 and CO2-foam injection was also investigated for intricate fracture systems. Magnetic Resonance Imaging (MRI) provided in situ visualization of local development in oil saturations and fluid displacement fronts during waterflood and CO2 injection. It is shown that CO2 mobility control using CO2-foam significantly increase oil recovery during CO2 injection and will meet the challenges of low macroscopic sweep efficiency and the adverse water-shielding effect in CO2-EOR.

SUMMARY The effect of micro-scale heterogeneities on front instabilities during secondary, liquid CO2 injections for enhanced oil recovery in standard-sized chalk core plugs was investigated. The rock structure and displacement process was imaged in an industrial CT-scanner to probe the effect of micro-scale heterogeneities on the flow patterns and development of plume and CO2 fingers during injections. Heterogeneities in the chalk samples include fractures, healed shear bands and remnants of burrows. A one-component mineral oil was placed in contact with CO2 at the experimental conditions to promote reproducibility between repeated tests. The chalk is considered homogeneous on a standard-sized plug level, and varies only slightly in porosity and permeability within a large number of cores. The high spatial resolution CT scanning revealed submm healed shear bands running through the length of the core which potentially can cause a permeability decrease or diversion of the injected fluid. Total oil recovery from CO2 injection was around 90% regardless of heterogeneities, and there was no visible difference in CO2 arrival at the outlet. With no permeability contrast through the length of the core, the production of oil took place with less than one pore volume (PV) of CO2 injected. With a permeability contrast through the length of the core, more than one PV of CO2 was required to reach end-point oil saturation. Imaging the dynamic properties of a CO2 flood in the industrial CT showed how micro scale heterogeneities impact the flooding characteristics of a small core sample, as the healed shear bands diverted flow to a certain degree. It is also demonstrated how a larger permeability contrast will make the recovery more dependent on diffusion, which is a slower process than viscous displacement. The results demonstrate the need for characterization of micro-scale heterogeneity, because high permeability streaks and fractures will dominate flow during CO2 injection for EOR.

Multiphase flow and fluid displacements at pore-level were visualized in two-dimensional micromodels retaining essential characteristics of porous rocks. Microvisual data during CO2 injection for enhanced oil recovery was obtained from high resolution images using UV-sensitive dye to improve contrast. The dominating mechanisms were piston-like displacement of one fluid by another, either by a stable moving interface or through Haines-like jumps. Film thickening, film drainage, snap-off mechanisms and capillary trapping of CO2 were also observed. Both stable and unstable flow regimes were identified as the front advanced through the network during two-phase flow. In the latter regime, instabilities in the displacements were manifested by capillary fingering perpendicular to the main flow direction. Oil was found to be spreading in the water-oil-gas system at the experimental conditions. This led to an efficient oil production at pore-level from CO2 gas injection, even at high water saturation. The injected gaseous CO2 contacted only oil in three-phase systems, and led to direct oil displacement, whereas water was displaced through double or multiple displacement events.

Core-flood experiments using chalk outcrop cores with petrophysical properties similar to North Sea chalk reservoirs have been conducted and history-matched. The objectives were to enhance the understanding of the mechanisms of fluid displacement in permeable chalk and to evaluate the imaging technique with respect to measuring three-phase saturations in chalk cores. The displacements included miscible brine/brine, drainage, miscible oil floods and water floods. The brine and oil phases were respectively labelled with gamma-emitting 22 Na and 59 Fe tracers. Fluid saturations were measured by a Germanium detector moved along the length of the core. In this investigation, emphasis has been placed on local in situ saturation development, recovery efficiency, fluid-front behaviour and tracer adsorption. The benefits from knowing the local in situ saturations, the identification of rock heterogeneity and the reproducibility of the saturation imaging have been emphasized. A good comparison was obtained between in situ fluid saturation information and that from effluent fluid measurements. The additional information on local fluid saturations obtained from the in situ measurements, coupled with petrophysical measurements, has enhanced the characterization of chalk cores and thus will contribute to a better understanding of displacement mechanisms during hydrocarbon recovery from chalk reservoirs. The nuclear tracer imaging technique was found suitable for measurements of three-phase fluid saturations.