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REVIEW 4 major objections 4 minor 43 references

Sensitivity of Trapping Efficiency and Relative Permeability to Experimental Methodology in Laboratory Core Flooding

T0 review · 4 major / 4 minor · reviewed 2026-08-15 · deepseek-v4-flash

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Pith's one-line read Injection technique, not just rock properties, controls measured CO2 trapping.

desk verdict A genuinely useful experimental comparison that raises an important question, but the headline attribution is confounded by unequal capillary numbers between the two injection protocols. read the letter →

arxiv 2505.09044 v1 pith:3DVFIE2Q submitted 2025-05-14 physics.geo-ph

Catherine Spurin , Catherine Callas , Takeshi Kurotori , Hamdi A. Tchelepi , Sally M. Benson This is my paper · ORCID
classification physics.geo-ph
keywords CO2storagecorefloodingtrappingefficiencyrelativepermeabilityco-injectionsingle-phaseinjectioncapillaryendeffectsresidual
verification ladder T0 review T1 audit T2 compute T3 formal

The pith

A machine-rendered reading of the paper's core claim, the machinery that carries it, and where it could break.

The reading

This paper argues that how a core-flood experiment is run—co-injecting gas and water together or injecting them one at a time—changes two quantities used to build reservoir models: trapping efficiency and pressure-derived relative permeability. In gas/water experiments on Indiana limestone, co-injection produced significantly higher residual trapping than single-phase injection, even after boundary-affected regions are excluded from the analysis. If co-injection data are used to predict a CO2 plume that is actually injected single-phase, the amount of CO2 stranded in the pore space would be overestimated and pore-volume utilization underestimated. The paper concludes that experimental methodology itself shapes the measured petrophysical parameters, so carbon storage projects need measurement or modelling choices that match the intended field injection strategy.

What carries the argument

The central object is the trapping-efficiency relationship—residual non-wetting-phase saturation plotted against initial saturation after drainage—together with the differential pressure across the core, which is the input for relative permeability. The mechanism is the contrast between two injection protocols: co-injection, in which both phases enter the core at fixed fractional flow, and single-phase injection, in which one phase at a time is pumped through the core. The paper combines time-resolved CT saturation profiles with frequency-domain analysis of the pressure signal to show that capillary end effects and gas dissolution appear differently under the two protocols, and that these differences, not just rock properties, set the shape of the trapping curve and the pressure response.

What would settle it

Repeat the gas/water co-injection and single-phase experiments on the same core at matched flow conditions and compare the trapping-efficiency curves; if the curves collapse onto a single relationship, the claim that injection methodology changes trapping would be refuted.

Watch

Extended reading notes

Core claim

The central claim is that steady-state co-injection, the standard laboratory method, does not reproduce the trapping and pressure response of single-phase injection, which is closer to field CO2 storage operations. Using CT-imaged core floods with gas/water and oil/water fluid pairs, the paper shows that co-injection drainage leaves a lower initial non-wetting phase saturation but a substantially higher residual saturation after imbibition. The single-phase gas experiment develops a region near the inlet where gas saturation drops close to zero, and this boundary-dominated region influences the differential pressure used to compute relative permeability. The same trends appear for oil/water but are less extreme. The paper interprets the pattern as co-injection creating more tortuous gas pathways that enhance trapping, while single-phase injection produces stronger capillary end effects and dissolution gradients, and these effects persist even when the end sections are cropped from the analysis.

Load-bearing premise

The comparison assumes that the different trapping and pressure responses come from injecting phases together versus one at a time, and not from the different pumping speeds used in the two protocols or from using a different rock core for one of the oil experiments.

Editorial extensions

If this is right

  • Co-injection core-flood data used without correction can overestimate residual trapping for single-phase CO2 storage operations, leading reservoir models to underestimate how far the plume will spread.
  • Single-phase injection experiments need to account for boundary-dominated pressure data, because the saturation gradient near the inlet can dominate the pressure drop and distort relative permeability values.
  • Co-injection of water with gas enhances residual trapping but lowers pore-volume utilization, so field-scale choices between co-injection and water-alternating-gas strategies involve a trade-off between plume spread and trapping.
  • The orientation of rock heterogeneities matters more under single-phase injection than under co-injection, so heterogeneity uncertainty is larger when characterizing storage sites with single-phase protocols.
  • Gas/water systems respond more strongly to injection method than oil/water systems, which means CO2 storage characterization should not default to oil-industry co-injection workflows.

Reading between the lines

Editorial extensions of the paper, not claims the author makes directly.

  • If this result generalizes, historical co-injection measurements of CO2 trapping may need re-examination, and reservoir simulators may need separate hysteresis parameters for co-injection and single-phase scenarios.
  • The most direct rival explanation is the differing flow rates between the two protocols; a repeat of the gas experiments at matched flow conditions on the same core would isolate the injection-technique effect from capillary-number effects.
  • The observation that the slow-evolving inlet region can be mapped by saturation change with time could be developed into a quantitative correction that removes boundary-dominated pressure contributions from single-phase relative permeability data.
  • A practical consequence for storage operations is that water-alternating-gas injection may offer a better field-scale balance between maximizing residual trapping and controlling plume migration than co-injection.
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Editorial analysis

A structured set of objections, weighed in public.

Desk editor's note, referee report, and a circularity audit.

Referee Report

4 major / 4 minor

Summary. The paper reports a comparative core-flood study on Indiana limestone, contrasting steady-state co-injection experiments with single-phase injection experiments for two fluid pairs (gas/water and oil/water). Using CT-derived saturation profiles, trapping-efficiency relationships, and differential pressure measurements, the authors find that co-injection leads to higher residual trapping efficiency and different pressure responses than single-phase injection. They conclude that co-injection experiments may overestimate residual trapping for field CO2 storage operations and that the choice of laboratory methodology materially affects how core-scale data should be upscaled.

Significance. If the central attribution is valid, the paper addresses a practically important question: whether standard steady-state co-injection measurements, widely used to parameterize reservoir models, are representative of the single-phase-dominated injection sequences typical of CO2 storage operations. The study's strengths include direct CT imaging of saturation, a comparison across two fluid systems, and the absence of fitted parameters in the primary measured outputs (saturation and pressure); Land-model fits are used only as an interpretive tool. The finding that injection methodology shifts trapping curves, if confirmed with proper controls, would have clear implications for experimental protocols and for field-scale modeling of residual trapping. However, the load-bearing comparison is currently confounded by differences in flow rate, capillary number, and, in the oil experiments, rock sample, so the significance is conditional on resolving those confounds.

major comments (4)
  1. [Table II and Section II.C] The central claim that co-injection versus single-phase injection changes trapping efficiency is undermined by unequal capillary numbers across the compared runs. For gas/water imbibition, the single-phase run uses water at 5 ml/min (Ca = 6.0e-7) while the co-injection run uses water at 5 ml/min plus gas at 1 ml/min (Ca = 8.9e-8), nearly an order of magnitude difference. If trapping efficiency depends on capillary number in this regime, the co-injection curve in Fig. 3a could lie above the single-phase curve even if the injection method had no intrinsic effect. The drainage capillary numbers also differ (1.4e-8 vs 2.0e-8). The paper asserts that flow was capillary-dominated but does not demonstrate that trapping is independent of Ca across this range. A matched-capillary-number control run, or an explicit demonstration of Ca insensitivity, is needed to attribute the observed differences to the injection technique rather than to flow rate.
  2. [Section II.A and Fig. 3b] The oil/water comparison uses two different cores: Indiana core 1 for co-injection and Indiana core 2 for single-phase injection. Since Indiana limestone is explicitly described as heterogeneous with millimeter-scale bimodal porosity (Section II.A), the different trapping curves in Fig. 3b could reflect sample heterogeneity rather than injection methodology. The authors acknowledge this ('the comparison is less direct in this case'), but the acknowledgment does not remove the confound. Without a repeat on the same core or a characterization of the two cores' trapping behavior under identical conditions, the oil-experiment result cannot support the paper's general conclusion about methodology-dependent trapping.
  3. [Title, Abstract, and Sections III.C and IV] The title and abstract promise a comparison of 'relative permeability' between injection techniques, but the paper never presents relative permeability curves or their numerical values. Section III.C reports differential pressure, and the conclusions discuss pressure-derived relative permeability qualitatively, yet no relative permeability is computed or shown. If relative permeability is a central output, the manuscript should either present the calculated curves or explicitly scope the claim to pressure response and trapping efficiency. As written, the claim that relative permeability is affected by injection methodology is not directly supported by any quantitative relative permeability data.
  4. [Section III.C and Fig. 5] The interpretation that the single-phase gas imbibition pressure response is 'dominated' by the near-inlet region where saturation drops to zero is plausible but not directly demonstrated. Figure 5 shows a difference in pressure behavior, but without a spatial analysis of pressure contribution (e.g., local pressure gradients or a comparison of the inlet region with the rest of the core), the statement that end effects 'dominated the differential pressure measurement' remains an inference. A quantitative decomposition or a control experiment excluding the inlet region would strengthen this load-bearing interpretive step.
minor comments (4)
  1. [Section II.C, Eq. (2)] The saturation calculation uses CT numbers acquired at different times with potential drift; the paper should state whether any correction for CT number drift or beam hardening was applied, and how the 20-second scan time affects the reported saturation precision beyond the statement in Section III.C.
  2. [Section III.B, Fig. 3 caption] The caption says 'between between' and should be corrected to 'between'. Also, the figure would benefit from error bars or a replicate measurement, given that the central comparison is based on a single experimental run per condition.
  3. [Section I, Introduction] The phrase 'traditional focus on co-injection experiments may overlook important physical flow phenomena' is vague; the introduction would be strengthened by citing specific prior steady-state co-injection studies and stating what flow physics is missed (e.g., transient trapping, film flow, or non-equilibrium effects).
  4. [Section III.D] The porosity-saturation analysis in Fig. 7 is used to infer dissolution effects, but the paper does not provide an independent measure of dissolved gas. A brief justification of why dissolution, rather than, say, capillary heterogeneity or residual trapping patterns, explains the negative porosity-saturation correlation would improve the argument.

Circularity Check

0 steps flagged · score 0.0 of 10

No significant circularity: the paper's claims are direct experimental comparisons with externally measured CT saturations and pressure drops.

full rationale

The central claim that co-injection and single-phase injection protocols yield different trapping efficiency and pressure-derived relative permeability is an experimental comparison, not a derived prediction from fitted parameters. Trapping efficiencies are computed directly from CT-measured saturations using the stated porosity and CT-number equations (Eqs. 1-2), and pressure responses are measured across the core. Land-model fits are used only as interpretive descriptions of the trapping curves, not as inputs that generate the reported differences. No parameter is fitted to a subset of data and then renamed as a prediction, and no load-bearing conclusion depends on an unverified self-citation. The cited prior works are used for experimental apparatus, image processing, capillary number calculation, spectral analysis, and Land-model interpretation; these are methodological references rather than premises that force the paper's conclusions. The main scientific limitation, that co-injection and single-phase runs used different flow rates and capillary numbers (Table II), is a potential confounding of the attributed cause, but it is an experimental-design concern, not a circularity of the derivation. Accordingly, the appropriate finding is no circularity with score 0.

Assumptions & free parameters 0 free parameters · 5 assumptions · 0 invented entities

The central claim is an experimental comparison, so the main non-verified inputs are the domain assumptions above: the proxy fluid, the capillary-dominated flow assumption, core equivalence, CT calibration, and volume sufficiency.

assumptions (5)
  • domain assumption Nitrogen is a valid proxy for CO2 with equivalent residual trapping because of similar viscosity and density.
    Stated in Section II.B, citing Wildenschild et al. [31].
  • domain assumption The chosen flow rates ensure capillary-dominated flow, so differences in capillary number between protocols do not affect the comparison.
    Section II.C states flow rates 'were chosen to ensure flow was in the capillary dominated regime', but Table II reports different capillary numbers for the two protocols.
  • domain assumption The two Indiana cores used for oil experiments are petrophysically equivalent for the comparison.
    Section II.A states a different core was used for oil single-phase injection because of difficult oil removal; differences between cores could confound the oil results.
  • domain assumption Saturation calculated from CT images is linearly related to CT number via Equation 2, with no significant beam hardening or image noise bias.
    Equations 1-2 assume a linear mixing model; the paper cites standard methods but does not independently calibrate for this core.
  • domain assumption Injecting 300 ml (about 5 pore volumes) is sufficient to reach end-state drainage and imbibition saturations.
    Section II.C fixes injected volume at 300 ml for all experiments; no verification that residual saturation was stable by end of injection.

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Cite this review

Pith. "Pith review of Sensitivity of Trapping Efficiency and Relative Permeability to Experimental Methodology in Laboratory Core Flooding." pith.science (2026). https://pith.science/paper/3DVFIE2Q

@misc{pith2026250509044,
  author       = {Pith},
  title        = {Pith review of: Sensitivity of Trapping Efficiency and Relative Permeability to Experimental Methodology in Laboratory Core Flooding},
  year         = {2026},
  howpublished = {\url{https://pith.science/paper/3DVFIE2Q}},
  note         = {Machine review of arXiv:2505.09044}
}
abstract

Understanding the migration and trapping of CO$_2$ in the subsurface is vital to geologic carbon storage projects. Traditional characterization methods employ steady-state co-injection experiments to determine relative permeability and trapping efficiency. Although laboratory studies aim to replicate reservoir conditions, co-injection experiments are often selected because they facilitate steady-state flow and reduce capillary end effects. The fundamental influence of this experimental design choice on measured petrophysical parameters remains inadequately characterized. This study presents a comparative analysis between co-injection and single-phase injection experiments, specifically investigating how experimental methodology influences both trapping efficiency and pressure differential across the core sample (which is used to calculate relative permeability). Our results demonstrate significant variations in trapping behavior between these injection techniques, suggesting that the traditional focus on co-injection experiments may overlook important physical flow phenomena. Differences between injection techniques could be strategically exploited in field applications to enhance residual trapping capacity in subsurface CO$_2$ storage operations. This work highlights the importance of understanding experimental artifacts in core flooding studies and their potential applications for improving carbon storage efficiency.

Figures

Figures reproduced from arXiv: 2505.09044 by the authors.

Figure 1
Figure 1. FIG. 1: Porosity profile for the Indiana samples used in this work. Indiana core 1 was used [PITH_FULL_IMAGE:figures/full_fig_p005_1.png] view at source ↗
Figure 2
Figure 2. FIG. 2: Saturation along the core after drainage (black) and imbibition (red) for (a) [PITH_FULL_IMAGE:figures/full_fig_p009_2.png] view at source ↗
Figure 3
Figure 3. FIG. 3: The relationship between between initial (post drainage) and residual (post [PITH_FULL_IMAGE:figures/full_fig_p011_3.png] view at source ↗
Figures from the paper (6 more)
Figure 4
Figure 4. Figure 4: FIG. 4: The saturation evolution during imbibition for a) the co-injection gas experiment, [PITH_FULL_IMAGE:figures/full_fig_p012_4.png]
Figure 5
Figure 5. Figure 5: The differential pressure during drainage heavily depended on the injection tech [PITH_FULL_IMAGE:figures/full_fig_p012_5.png]
Figure 5
Figure 5. Figure 5: FIG. 5: The pressure drop across the core for the final 30 mins of injection. The blue lines [PITH_FULL_IMAGE:figures/full_fig_p013_5.png]
Figure 6
Figure 6. Figure 6: FIG. 6: The pressure data transformed into the frequency domain for a) drainage and b) [PITH_FULL_IMAGE:figures/full_fig_p014_6.png]
Figure 7
Figure 7. Figure 7: FIG. 7: The relationship between saturation and porosity for each slice in the core. The [PITH_FULL_IMAGE:figures/full_fig_p015_7.png]
Figure 8
Figure 8. Figure 8: FIG. 8: The relationship between between initial gas saturation (post drainage) and [PITH_FULL_IMAGE:figures/full_fig_p017_8.png]

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