Some of the longest and most comprehensive marine ecosystem monitoring programs were established in the Gulf of Alaska following the environmental disaster of the Exxon Valdez oil spill over 30 years ago. These monitoring programs have been successful in assessing recovery from oil spill impacts, and their continuation decades later has now provided an unparalleled assessment of ecosystem responses to another newly emerging global threat, marine heatwaves. The 2014–2016 northeast Pacific marine heatwave (PMH) in the Gulf of Alaska was the longest lasting heatwave globally over the past decade, with some cooling, but also continued warm conditions through 2019. Our analysis of 187 time series from primary production to commercial fisheries and nearshore intertidal to offshore oceanic domains demonstrate abrupt changes across trophic levels, with many responses persisting up to at least 5 years after the onset of the heatwave. Furthermore, our suite of metrics showed novel community-level groupings relative to at least a decade prior to the heatwave. Given anticipated increases in marine heatwaves under current climate projections, it remains uncertain when or if the Gulf of Alaska ecosystem will return to a pre-PMH state.

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TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractA displacement process in a chalk core plug with an induced axial fracture uses the fluid system H 2 O-D 2 O-n-decane. Initially the plug contains a mixture of D 2 O and n-decane with oil saturation equal to 88 %. The plug is flooded with H 2 O. The displacement process is monitored by NMR with a chemical shift technique enabling spatial resolution of the H 2 O and oil signals. The D 2 O component is not directly detected, but is calculated from the difference between the actual signal intensities and the signal intensities in a situation where the pore space is completely saturated with H 2 O and oil.H 2 O-D 2 O-oil constitutes a partly miscible fluid system which is an analogy to the injection water-formation water-oil system of a hydrocarbon reservoir under waterflooding.The injected H 2 O traverses the sample as a well-defined front together with capillary uptake from the fracture plane. Ahead of the H 2 O front the D 2 O of the sample is mobilized and travels as a bank in front of the H 2 O. Though the initial concentration of D 2 O is only 12 % the D 2 O concentration reaches 50 % at the bank.The experiment was simulated by means of ECLIPSE with a fair match of the displacement process.The injected H 2 O has only made limited contact with the produced oil of the sample. In case of chemical EOR processes connected to waterflooding of hydrocarbon reservoirs a similar displacement situation could seriously affect the efficiency of the EOR process.

Summary This paper presents a novel technique to determine multicomponent diffusion coefficients for carbon dioxide (CO2) injection in a North Sea chalk field (NSCF) in Norway at reservoir conditions. The constant-volume-diffusion (CVD) method is used, consisting of an oil-saturated-chalk core in contact with an overlying free space, which is filled with the CO2. The experimental data are matched with an equation-of-state (EOS) -based compositional model. Transport by diffusion controls the dynamics of the constant-volume system and, together with phase equilibria, allows a consistent estimation of diffusion coefficients needed to describe the observed changes in system pressure. We conduct two experiments at reservoir conditions: One uses a core plug saturated with live oil and the other with stock-tank oil (STO). Once the experiments are completed, EOS-based compositional simulation is performed to match the experimental data by use of the oil- and gas-diffusion coefficients as history-matching parameters. The modeling work is conducted with a commercial reservoir simulator by use of a 2D radial-grid model to describe the experimental setup. The experiment uses an outcrop chalk core mounted in a vertically oriented core holder. The chalk is shorter than the core holder, thus resulting in an overlying void space. The system is initially saturated with oil at reservoir conditions. CO2 is then injected from the top, forming an overlying CO2 chamber and displacing oil toward the bottom of the core holder. Once CO2 fills the overlying bulk space, the system is isolated with no further injection or production. The CO2 and oil reach and remain in equilibrium locally at the gas/oil interface throughout the test, beginning and maintaining the diffusion mechanism. Diffusion of CO2 into the oil results in a decreasing pressure, which is the main history-matching parameter. The multicomponent diffusion coefficients are found to match the model pressure/time prediction to the experimental data. This suggests the modeling work flow incorporates a representative EOS model and the main transport dynamics controlled by diffusion are being treated properly. Proper simulation of CO2 injection in fractured-chalk reservoirs requires the ability to model multicomponent diffusion accurately. The proposed CVD method provides such modeling capabilities. Our modeling and experimental work indicate the novelty of the CVD method to determine the diffusion coefficients of a system where diffusion is the dominant displacement mechanism. The fact that the oil is contained within a low-permeability-chalk sample reduces density-driven convection that could result because of nonmonotonic oil-density changes as CO2 dissolves into the oil.