The STarT back screening tool (SBT) allocates low back pain (LBP) patients into three risk groups and is intended to assist clinicians in their decisions about choice of treatment. The tool consists of domains from larger questionnaires that previously have been shown to be predictive of non-recovery from LBP. This study was performed to describe the distribution of depression, fear avoidance and catastrophising in relation to the SBT risk groups. A total of 475 primary care patients were included from 19 chiropractic clinics. They completed the SBT, the Major Depression Inventory (MDI), the Fear Avoidance Beliefs Questionnaire (FABQ), and the Coping Strategies Questionnaire. Associations between the continuous scores of the psychological questionnaires and the SBT were tested by means of linear regression, and the diagnostic performance of the SBT in relation to the other questionnaires was described in terms of sensitivity, specificity and likelihood ratios.In this cohort 59% were in the SBT low risk, 29% in the medium risk and 11% in high risk group. The SBT risk groups were positively associated with all of the psychological questionnaires. The SBT high risk group had positive likelihood ratios for having a risk profile on the psychological scales ranging from 3.8 (95% CI 2.3 - 6.3) for the MDI to 7.6 (95% CI 4.9 - 11.7) for the FABQ. The SBT questionnaire was feasible to use in chiropractic practice and risk groups were related to the presence of well-established psychological prognostic factors. If the tool proves to predict prognosis in future studies, it would be a relevant alternative in clinical practice to other more comprehensive questionnaires.
During spontaneous counter-current imbibition of brine into oil-filled porous rock, it is generally assumed that the flow rates of the brine and oil are equal and in opposite directions. However, significant scatter and inconsistent dimensionless times were observed in experiments using matched-viscosity fluids in two ends open (TEO) sandstone cores using an established correlation factor. In further TEO experiments, the oil production at each end face was measured separately and ranged from being equal and symmetrical to highly asymmetrical, with almost all of the mobile oil being produced from one end in nominally duplicate tests. The dimensionless time for scaled imbibition increased with increasing asymmetry in oil production. Thus, for imbibition into cores with the TEO boundary condition, although the overall flows of brine and oil have to be equal, the individual flows at each end face are not necessarily equal and opposite. The asymmetry in oil production during imbibition with the TEO boundary condition was further investigated by imaging the in situ fluid saturations during imbibition, this time using homogeneous chalk and fluids with differing viscosities. In all cases, the amount of brine imbibed at each end face was almost equal even though there was sometimes significant asymmetry in the oil production. This behavior was probably caused by most of the capillary pressure driving imbibition being dissipated in the brine. With only small pressure differences required to produce the oil, any inhomogeneities in the rock which change the production capillary back pressure at the open faces can have a disproportionate effect on the symmetry of oil production.
Hydrogen (H 2 ) will play a key role in low-carbon energy transitions, and it is vital to implement hydrogen storage technologies to enable its safe and economic use at industrial scale. Underground hydrogen storage (UHS) in porous media such as aquifers, depleted hydrocarbon fields, and coal seams has been proposed as widely available long-term and large-scale storage options (Iglauer et al., 2021;Muhammed et al., 2022). As for underground natural gas storage (UGS), UHS involves cyclic gas injection at peak supply (known as cushion gas) and withdrawal at peak demand (working gas). Despite the increasing attention to the topic worldwide, the fundamentals of multiphase hydrogen flow in porous media are still not well described. In particular, relative permeability hysteresis has not been addressed, although its impact has been previously assessed for UGS and CO 2 storage (Colonna et al., 1972;Juanes et al., 2006). The cyclic nature of the UHS suggests that distinct relative permeability functions must be implemented for hydrogen injection (drainage) and withdrawal (imbibition).Relative permeability is a crucial input parameter for the UHS numerical modeling at field scale (Kanaani et al., 2022;Lysyy et al., 2021;Wang et al., 2022). Laboratory gas-water relative permeability curves often have low endpoint gas saturations (<65%) and relative permeabilities (<40%) due to the rock heterogeneity, capillary end effects, gravity segregation, and/or maximum experimental capillary pressure (Krevor et al., 2012;Muller, 2011). Numerical and/or analytical methods are therefore required to validate and extrapolate relative permeabilities in a wider saturation range.Hydrogen-water relative permeability measurements are scarce in the open literature. Steady state drainage experiments resulted in low endpoint gas saturation (∼60%) and relative permeability (∼4%) (Yekta et al., 2018). The authors used experimental capillary pressure to analytically expand the relative permeability curves to higher
The ratio between the viscous and capillary forces, commonly denoted the Capillary Number Nc, is crucial in determining the remaining oil saturation. The impact on residual oil saturation by a systematic increase in Nc is determined in homogeneous chalk at wettabilities varying from nearly neutral-wet to strongly-water-wet conditions. In fractured chalk reservoirs waterflood residual oil saturation is strongly dependent on the wettability. The current results provide assistance in determining the potential target for tertiary oil recovery by measuring the amount of mobile oil at various Nc. A series of displacements of oil by water injection at constant pressure were carried out to determine the relation between oil recovery and applied capillary number in waterfloods at different wettability conditions. Maximum oil recovery at constant Nc occurred at wettability conditions reflecting an Amott Index to water at 0.3. The remaining oil decreased with increasing capillary number and significant trapped oil after completed spontaneous water imbibition was mobilized at moderately water-wet to nearly neutral-wet conditions. Similar results as reported in the literature for waterflooding residual oil saturations as function of wettability and PV water injected in sandstone were found for chalk at increasing capillary number. Distinct dome shaped curves of oil recovery as function of wettability, with consistent increase in oil recovery with increasing capillary number, reflected similarities to earlier results on waterflooding oil recovery. Introduction The opportunity window for implementing IOR schemes for a given reservoir in production is limited when reaching the tail production. It is vital that the amount of potential target oil for EOR is determined as early as possible, and in this respect that the ultimate immobile or residual oil saturation for the rock/crude/brine system at the wettability conditions present in the reservoir is determined. Oil recovery depends strongly on the wettability condition and the interaction between the capillary and viscous forces will accordingly change with wettability [1, 2]. This study emphasizes the impact from wettability on the residual oil saturation during increasing differential viscous pressure drops at various wettabilities. Capillary forces are responsible for fluid entrapment during an immiscible displacement in porous media. Laboratory studies have shown that more of the remaining oil may be recovered in immiscible displacements if increased viscous displacement is applied. By exceeding the capillary forces trapped residual oil may be mobilized [3]. The capillary forces are determined by the wettability conditions and the oil/water interfacial tension (IFT). The potential to mobilize capillary trapped oil depends on the pore geometry. The required viscous force needed to mobilize trapped oil is determined by the fluid dynamics of the displacing phase. Thus an important parameter determining mobilization of capillary trapped oil during immiscible fluid displacements is the capillary number; exhibiting the ratio of viscous forces to the capillary forces.
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