Best Practice in Coring and Core Analysis

McPhee, Colin; Reed, Jules; Zubizarreta, Izaskun

doi:10.1016/b978-0-444-63533-4.00001-9

Cited by 66 publications

(53 citation statements)

References 4 publications

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“…A set of laboratory methods is available to define the wettability of core plugs, e.g., contact angle measurements, the Amott–Harvey method, and the U.S. Bureau of Mines (USBM) method [ 3 ]. One of the most well-known and widely used methods to deduce or assess wettability is the Amott imbibition test, which is applied not only to sandstones but also carbonates [ 4 , 5 ].…”

Section: Introductionmentioning

confidence: 99%

Variations in Wettability and Interfacial Tension during Alkali–Polymer Application for High and Low TAN Oils

Arekhov¹,

Hincapie

Clemens

et al. 2020

Polymers

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The injection of chemicals into sandstones can lead to alterations in wettability, where oil characteristics such as the TAN (total acid number) may determine the wetting state of the reservoir. By combining the spontaneous imbibition principle and the evaluation of interfacial tension index, we propose a workflow and comprehensive assessment to evaluate the wettability alteration and interfacial tension (IFT) when injecting chemical-enhanced oil-recovery (EOR) agents. This study examines the effects on wettability alteration due to the application of alkaline and polymer solutions (separately) and the combined alkali–polymer solution. The evaluation focused on comparing the effects of chemical agent injections on wettability and IFT due to core aging (non-aged, water-wet and aged, and neutral to oil-wet), brine composition (mono vs. divalent ions); core mineralogy (~2.5% and ~10% clay), and crude oil type (low and high TAN). Amott experiments were performed on cleaned water-wet core plugs as well as on samples with a restored oil-wet state. IFT experiments were compared for a duration of 300 min. Data were gathered from 48 Amott imbibition experiments with duplicates. The IFT and baselines were defined in each case for brine, polymer, and alkali for each set of experiments. When focusing on the TAN and aging effects, it was observed that in all cases, the early time production was slower and the final oil recovery was longer when compared to the values for non-aged core plugs. These data confirm the change in rock surface wettability towards a more oil-wet state after aging and reverse the wettability alteration due to chemical injections. Furthermore, the application of alkali with high TAN oil resulted in a low equilibrium IFT. By contrast, alkali alone failed to mobilize trapped low TAN oil but caused wettability alteration and a neutral–wet state of the aged core plugs. For the brine composition, the presence of divalent ions promoted water-wetness of the non-aged core plugs and oil-wetness of the aged core plugs. Divalent ions act as bridges between the mineral surface and polar compound of the in situ created surfactant, thereby accelerating wettability alteration. Finally, for mineralogy effects, the high clay content core plugs were shown to be more oil-wet even without aging. Following aging, a strongly oil-wet behavior was exhibited. The alkali–polymer is demonstrated to be efficient in the wettability alteration of oil-wet core plugs towards a water-wet state.

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Section: Introductionmentioning

confidence: 99%

Variations in Wettability and Interfacial Tension during Alkali–Polymer Application for High and Low TAN Oils

Arekhov¹,

Hincapie

Clemens

et al. 2020

Polymers

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“…For relative permeability, the steady state method is widely considered to provide the most reliable results in the midsaturation range (McPhee et al, ). Here a stable fluid distribution at a known fractional flow, f w , is established while the saturation and pressure drop are recorded.…”

Section: Introductionmentioning

confidence: 99%

Imaging and Measurement of Pore‐Scale Interfacial Curvature to Determine Capillary Pressure Simultaneously With Relative Permeability

Lin

Bijeljic

Pini

et al. 2018

Water Resources Research

104

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There are a number of challenges associated with the determination of relative permeability and capillary pressure. It is difficult to measure both parameters simultaneously on the same sample using conventional methods. Instead, separate measurements are made on different samples, usually with different flooding protocols. Hence, it is not certain that the pore structure and displacement processes used to determine relative permeability are the same as those when capillary pressure was measured. Moreover, at present, we do not use pore‐scale information from high‐resolution imaging to inform multiphase flow properties directly. We introduce a method using pore‐scale imaging to determine capillary pressure from local interfacial curvature. This, in combination with pressure drop measurements, allows both relative permeabilities and capillary pressure to be determined during steady state coinjection of two phases through the core. A steady state waterflood experiment was performed in a Bentheimer sandstone, where decalin and brine were simultaneously injected through the core at increasing brine fractional flows from 0 to 1. The local saturation and the curvature of the oil‐brine interface were determined. Using the Young‐Laplace law, the curvature was related to a local capillary pressure. There was a detectable gradient in both saturation and capillary pressure along the flow direction. The relative permeability was determined from the experimentally measured pressure drop and average saturation obtained by imaging. An analytical correction to the brine relative permeability could be made using the capillary pressure gradient. The results for both relative permeability and capillary pressure are consistent with previous literature measurements on larger samples.

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“…Conventionally, subsurface flow models at the aquifer scale employ a continuum approach based on extended Darcy's law, resolving subsurface features at scales of 10s to 100s of meters to tractably simulate plume migration. These models are generally populated with multiphase flow parameters (relative permeability, capillary pressure and trapping) which are derived from viscous limit core flood experiments, measured at high flow rates on subsurface rock cores preferentially selected for homogeneity (McPhee et al 2015) While this approach is effective for high capillary number flows occurring in homogeneous media, it breaks down when the capillary number is low and small-scale capillary heterogeneities (i.e. laminae and bedding features below seismic resolution of ~10m) start to impact the flow regime.…”

Section: Introductionmentioning

confidence: 99%

High Resolution Modelling And Steady-State Upscaling Of Large Scale Gravity Currents In Heterogeneous Sandstone Reservoirs

Jackson¹,

Mayachita²,

Krevor³

2018

Proceedings

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We investigate the impact of small-scale heterogeneities (<10m) and gravity on large scale O(100m) lateral CO2 plume migration at varying capillary number, Nc and gravity number, Ngv. For isotopically correlated heterogeneities, plume migration was slowed signicantly at low Nc and high Ngv. For anisotropic cases akin to sedimentary geological structures, the plume speed was correspondingly enhanced, with breakthrough times reduced by up to 20% at large correlation lengths. Using relative measures, the capillary pressure was found to be the major control on plume migration as opposed to permeability, at low Nc. Using single, homogenized upscaled functions, we were able to capture the effects of small scale heterogeneities at low or high Nc and moderate Ngv. However, the relative enhancement of the impact of heterogeneities at high Ngv (and low Nc) could not be captured using single homogeneous functions for the entire domain. Without including enhanced gravity effects in the upscaling procedure, which generate anisotropic upscaled functions, the full effects of small-scale heterogeneities in gravity segregated flow could be signicantly underestimated in large scale models, leading to inaccurate plume migration estimates.

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Best Practice in Coring and Core Analysis

Cited by 66 publications

References 4 publications

Variations in Wettability and Interfacial Tension during Alkali–Polymer Application for High and Low TAN Oils

Variations in Wettability and Interfacial Tension during Alkali–Polymer Application for High and Low TAN Oils

Imaging and Measurement of Pore‐Scale Interfacial Curvature to Determine Capillary Pressure Simultaneously With Relative Permeability

High Resolution Modelling And Steady-State Upscaling Of Large Scale Gravity Currents In Heterogeneous Sandstone Reservoirs

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