Publications
9 results found
Selem AM, Agenet N, Blunt MJ, et al., 2022, Pore-scale processes in tertiary low salinity waterflooding in a carbonate rock: Micro-dispersions, water film growth, and wettability change, Journal of Colloid and Interface Science, Vol: 628, Pages: 486-498, ISSN: 0021-9797
HYPOTHESIS: The wettability change from oil-wet towards more water-wet conditions by injecting diluted brine can improve oil recovery from reservoir rocks, known as low salinity waterflooding. We investigated the underlying pore-scale mechanisms of this process to determine if improved recovery was associated with a change in local contact angle, and if additional displacement was facilitated by the formation of micro-dispersions of water in oil and water film swelling. EXPERIMENTS: X-ray imaging and high-pressure and temperature flow apparatus were used to investigate and compare high and low salinity waterflooding in a carbonate rock sample. The sample was placed in contact with crude oil to obtain an initial wetting state found in hydrocarbon reservoirs. High salinity brine was then injected at increasing flow rates followed by low salinity brine injection using the same procedure. FINDINGS: Development of water micro-droplets within the oil phase and detachment of oil layers from the rock surface were observed after low salinity waterflooding. During high salinity waterflooding, contact angles showed insignificant changes from the initial value of 115°, while the mean curvature and local capillary pressure values remained negative, consistent with oil-wet conditions. However, with low salinity, the decrease in contact angle to 102° and the shift in the mean curvature and capillary pressure to positive values indicate a wettability change. Overall, our analysis captured the in situ mechanisms and processes associated with the low salinity effect and ultimate increase in oil recovery.
Selem A, Agenet N, Blunt M, et al., 2022, Observations of water-in-oil micro-dispersions as a displacement mechanism in secondary and tertiary low salinity waterflooding, Fourth EAGE WIPIC Workshop, Publisher: European Association of Geoscientists & Engineers
Alhosani A, Selem AM, Lin Q, et al., 2021, Disconnected gas transport in steady‐state three‐phase flow, Water Resources Research, Vol: 57, Pages: 1-26, ISSN: 0043-1397
We use high-resolution three-dimensional X-ray microtomography to investigate fluid displacement during steady-state three-phase flow in a cm-sized water-wet sandstone rock sample. The pressure differential across the sample is measured which enables the determination of relative permeability; capillary pressure is also estimated from the interfacial curvature. Though the measured relative permeabilities are consistent, to within experimental uncertainty, with values obtained without imaging on larger samples, we discover a unique flow dynamics. The most non-wetting phase (gas) is disconnected across the system: gas flows by periodically opening critical flow pathways in intermediate-sized pores. While this phenomenon has been observed in two-phase flow, here it is significant at low flow rates, where capillary forces dominate at the pore-scale. Gas movement proceeds in a series of double and multiple displacement events. Implications for the design of three-phase flow processes and current empirical models are discussed: the traditional conceptualization of three-phase dynamics based on analogies to two-phase flow vastly over-estimates the connectivity and flow potential of the gas phase.
Selem AM, Agenet N, Gao Y, et al., 2021, Pore-scale imaging and analysis of low salinity waterflooding in a heterogeneous carbonate rock at reservoir conditions, Scientific Reports, Vol: 11, Pages: 1-14, ISSN: 2045-2322
X-ray micro-tomography combined with a high-pressure high-temperature flow apparatus and advanced image analysis techniques were used to image and study fluid distribution, wetting states and oil recovery during low salinity waterflooding (LSW) in a complex carbonate rock at subsurface conditions. The sample, aged with crude oil, was flooded with low salinity brine with a series of increasing flow rates, eventually recovering 85% of the oil initially in place in the resolved porosity. The pore and throat occupancy analysis revealed a change in fluid distribution in the pore space for different injection rates. Low salinity brine initially invaded large pores, consistent with displacement in an oil-wet rock. However, as more brine was injected, a redistribution of fluids was observed; smaller pores and throats were invaded by brine and the displaced oil moved into larger pore elements. Furthermore, in situ contact angles and curvatures of oil–brine interfaces were measured to characterize wettability changes within the pore space and calculate capillary pressure. Contact angles, mean curvatures and capillary pressures all showed a shift from weakly oil-wet towards a mixed-wet state as more pore volumes of low salinity brine were injected into the sample. Overall, this study establishes a methodology to characterize and quantify wettability changes at the pore scale which appears to be the dominant mechanism for oil recovery by LSW.
Selem AM, Agenet N, Blunt MJ, et al., 2021, Pore-scale imaging of tertiary low salinity waterflooding in a heterogeneous carbonate rock at reservoir conditions
We investigated pore-scale oil displacement and rock wettability in tertiary low salinity waterflooding (LSW) in a heterogeneous carbonate sample using high-resolution three-dimensional imaging. This enabled the underlying mechanisms of the low salinity effect (LSE) to be observed and quantified in terms of changes in wettability and pore-scale fluid configuration, while also measuring the overall effect on recovery. The results were compared to the behavior under high salinity waterflooding (HSW). To achieve the wetting state found in oil reservoirs, an Estaillades limestone core sample was aged at 11 MPa and 80°C for threeweeks. The moderately oil-wet sample was then injected with high salinity brine (HSB) at a range of increasing flow rates, namely at 1, 2,4, 11, 22 and 42 µL/min with 10 pore volumes injected at each rate.Subsequently, low salinity brine (LSB) was injected following the same procedure. X-ray micro-computed tomography (micro-CT) was usedto visualize the fluid configuration in the pore space.A total of eight micro-CT images, with a resolution of 2.3 µm/voxel, wereacquired after both low salinity and high salinity floods.These high-resolution images were used to monitor fluid configuration in the porespace and obtain fluid saturations and occupancy maps. Wettabilitywascharacterized by measurements of in situ contactanglesand curvatures. The results show that the pore-scale mechanisms of improved recovery in LSW are consistent with the development of water micro-dropletswithin the oil and the expansion of thin water films between the oil and rock surface. Before waterflooding and during HSW, the measured contact angles were constant and above 110°, while the meancurvature and the capillary pressure values remained negative, suggesting that the HSB did not change the wettability state of the rock. However, with LSW the capillary pressure increased towards positive values as the wettability shifted towards a mixed-wet state. The flu
Selem A, Agenet N, Gao Y, et al., 2021, PORE-SCALE IMAGING OF CONTROLLED-SALINITY WATERFLOODING IN A HETEROGENEOUS CARBONATE ROCK AT RESERVOIR CONDITIONS, Pages: 2272-2276
Controlled salinity water-flooding (CSW) is a promising enhanced oil recovery technique, yet the pore-scale mechanisms that control the process remain poorly understood especially in carbonate rocks. The aim of this experimental study is, therefore, to gain novel insights into CSW and characterize oil, water and the pore space in carbonates. X-ray imaging combined with a high-pressure high-temperature flow apparatus was used to image and study in situ CSW in a complex carbonate rock. To establish the conditions found in oil reservoirs, the Estaillades limestone core sample (5.9 mm in diameter and 10 mm in length) was aged for three weeks at 11 MPa and 80°C. This weakly oil-wet sample was then flooded by injecting low salinity brine at a range of increasing flow rates. Tomographic images were acquired at 2.9-micron spatial resolution after each flow rate. A total of 60 pore volumes of low salinity brine were injected recovering 85% of the oil initially in place in macro-pores. Contact angles and brine-oil curvatures were obtained to characterize wettability changes within the rock pore space. Our analysis shows that wettability alteration towards a mixed wet system caused by low salinity brine was the main mechanism for increased oil recovery.
Alhosani A, Scanziani A, Lin Q, et al., 2020, Three-phase flow displacement dynamics and Haines jumps in a hydrophobic porous medium, Proceedings of the Royal Society A: Mathematical, Physical and Engineering Sciences, Vol: 476, ISSN: 1364-5021
We use synchrotron X-ray micro-tomography to investigate the displacement dynamics during three-phase—oil, water and gas—flow in a hydrophobic porous medium. We observe a distinct gas invasion pattern, where gas progresses through the pore space in the form of disconnected clusters mediated by double and multiple displacement events. Gas advances in a process we name three-phase Haines jumps, during which gas re-arranges its configuration in the pore space, retracting from some regions to enable the rapid filling of multiple pores. The gas retraction leads to a permanent disconnection of gas ganglia, which do not reconnect as gas injection proceeds. We observe, in situ, the direct displacement of oil and water by gas as well as gas–oil–water double displacement. The use of local in situ measurements and an energy balance approach to determine fluid–fluid contact angles alongside the quantification of capillary pressures and pore occupancy indicate that the wettability order is oil–gas–water from most to least wetting. Furthermore, quantifying the evolution of Minkowski functionals implied well-connected oil and water, while the gas connectivity decreased as gas was broken up into discrete clusters during injection. This work can be used to design CO2 storage, improved oil recovery and microfluidic devices.
Gao Y, Raeini AQ, Selem AM, et al., 2020, Pore-scale imaging with measurement of relative permeability and capillary pressure on the same reservoir sandstone sample under water-wet and mixed-wet conditions, Advances in Water Resources, Vol: 146, Pages: 1-18, ISSN: 0309-1708
Using micro-CT imaging and differential pressure measurements, we design a comparative study in which we simultaneously measure relative permeability and capillary pressure on the same reservoir sandstone sample under water-wet and mixed-wet conditions during steady-state waterflooding experiments. This allows us to isolate the impact of wettability on a pore-by-pore basis and its effect on the macroscopic parameters, capillary pressure and relative permeability, while keeping the pore-space geometry unchanged.First, oil and brine were injected through a water-wet reservoir sandstone sample at a fixed total flow rate, but in a sequence of increasing brine fractional flows with micro-CT scans of the fluid phases taken in each step. Then the sample was brought back to initial water saturation and the surface wettability of the sample was altered after prolonged contact with crude oil and the same measurement procedure was repeated on the altered-wettability sample which we call mixed-wet.Geometric contact angles were measured, which discriminated the water-wet and mixed-wet cases with average values of 75° and 89° respectively. Additionally, an energy balance was used to determine the effective contact angles for displacement which indicated that a higher advancing contact angle of 116° was needed to displace oil in the mixed-wet case. For the water-wet experiment the filling sequence was pore-size dependent, with a strong correlation between pore size and oil occupancy. However, in the mixed-wet experiment the principal determinant of the filling sequence was the wettability rather than the pore size, and there was no correlation between pore size and the residual oil occupancy.The oil-water interfacial area had a larger maximum in the mixed-wet case which was supported by the observation of sheet or saddle-like menisci shapes present throughout the sample volume that impede the flow. These shapes were quantified by much larger negative Gaussian curvature
Selem AM, Dixon R, Hollis C, et al., 2017, Evidence of Exposure of the Upper Cretaceous Congost Carbonate Platform and Implications for Emergent Surfaces Identification From Subsurface Data, AAPG Annual Convention and Exhibition, Houston, Texas, April 2-5, 2017
Understanding the nature of emergent surfaces is critical to the development and production of carbonate reservoirs as they can coincide with areas of high porosity and permeability (e.g. thief zones) or degradation of reservoir properties (flow baffles). They can also be key surfaces for field- and basin scale correlation. Nevertheless, emergent surfaces are highly variable in character. Although it is possible for karstic terrain to form during geologically short time periods, on some platforms several million years of exposure can be invisible in the succession. The Congost Platform in the Tremp Basin, Spanish Pyrenees, is Turonian-Coniacian in age. It developed basinward of the underlying Pradina Platform after a fall in global sea level and comprises two principle successions. The lowermost succession comprises coral-rudist rich skeletal grainstones interbedded within skeletal wackestone, deposited within a shallow water lagoon fringed by a platform margin shoal. A subsequent fall in sea level in the mid-late Turonian led to a further basinward shift in facies belts, forming a platform fringed by coralgal boundstones. Platform growth was terminated by emergence in the early Coniacian. The emergent surface at this upper bounding surface shows little evidence for karstification. Petrographical data indicates dissolution and cementation of precursor aragonitic shell fragments by sparry calcite cements. Under CL, most pore filling cements show a dull-non luminescent-dull-bright-dull concentric zonation, with a gradual evolution from non-ferroan to ferroan calcite. It is possible that the oldest, non ferroan calcite was precipitated from meteoric water, but it is a volumetrically minor phase. Residual porosity has been occluded by burial calcite cements. A slight depletion in d13C beneath the unconformity is the only other evidence for diagenetic modification by meteoric water. Consequently, despite a humid climate and a lengthy period of emergence, the unconformity
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