Pore to core scale investigations of optimal voidage replacement ratio in carbonate rocks

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Waterflooding has been used to aid oil recovery for roughly a century, but oil recovery mechanisms are still not fully delineated. Improved understanding of recovery mechanisms benefits efforts to increase recovery efficiency. Two variants of waterflooding that are emerging to maximize waterflood recovery are low salinity (LSW) injection and voidage replacement ratio (VRR) less than one. Low salinity waterflood involves the injection of a brine of low salinity. The brine is either diluted in total or certain ionic modifications are introduced. VRR is described as the amount of fluid injected to the amount produced. In VRR < 1 processes, the amount injected is less than that produced. The study sheds light on VRR and LSW independently and then combines their effect to achieve greater oil recovery. This work mainly focuses on understanding the pore-level mechanisms of the processes of interest through conducting pore-scale micromodel experiments. Increases in oil recovery due to low salinity waterfloods have been widely investigated. The literature is abundant with studies attempting to pinpoint the relevant mechanisms involved in the LSW process. Recently, there was clear evidence of spontaneous formation of emulsions during LSW under certain conditions. Here, spontaneous emulsification is examined during LSW using pore-scale observations within etched silicon micromodels as well as pore-scale mass transfer calculations. Spontaneous emulsification is observed when "low salinity water" and crude oil are brought into contact under non-equilibrium conditions. In such cases, the crude oil was preequilibrated through exposure to a formation brine that had substantial salinity and divalent cations. The experimental and numerical modeling schemes presented here demonstrate a novel description of water-in-oil emulsion formation. An osmotic imbalance between water and oil phases drives water into the oil phase where it reaches a supersaturated state. Spontaneous nucleation of the water phase produces emulsions. On the other hand, there are to the best of our knowledge no studies investigating the process of VRR less than one in light oil carbonate reservoirs. The literature is rich in description of such a mechanism for heavy and viscous oil but lacks similar depiction for light oil carbonate rocks. Kim et al. (2016 and 2019) demonstrated an optimum VRR in a sandpack system. The results were encouraging to extend a similar process to carbonate settings. Carbonate rocks are inherently heterogeneous. The nature of heterogeneity in carbonate reservoirs adds another level of complexity in understanding fluid flow. Looking at VRR from a pore-scale lens aids the pinning down of the main mechanisms contributing to improved oil recovery through both qualitative and quantitative approaches. To perform VRR < 1 experiments successfully, design and fabrication of a novel microfluidic device that tolerates high-pressure conditions was compulsory. The micromodel was fabricated in two sequential stages, considering that the production and injection ports were etched all the way through the silicon substrate. The fabrication of this type of micromodel is extremely taxing. It requires great attention to details and is time consuming. Several VRR < 1 experiments were successfully completed utilizing the high-pressure micromodel. The optimum VRR of 0.8 produced 42% of the OOIP. The total oil recovery from solution gas drive (VRR = 0) plus waterflooding (VRR=1) equaled that of VRR = 0.8. The pore-scale observations from VRR = 0.8, compared to other experiments, revealed that three-phase flow and specifically evolved gas bubbles play a major role in improving the oil recovery. The amount of trapped/resident gas within the system was the greatest in case of the optimum VRR. The results suggest that small gas mobility favorably impacts fluid flow behavior. The interplay of three-phase flow leads to creation of new water flow paths and recovery of additional oil from micropores that were not accessed during two-phase flow. Other factors enhancing flow behavior include formation of water-in-oil emulsions and change in wettability. Coreflood experiments and simulation results confirmed the presence of an optimum VRR in Indiana limestone core plugs. The total recovery from a VRR = 0.7 coreflood experiment was 80% of OOIP. The coreflood experiments were history matched using the CMG STARS reservoir simulator. Additional simulation runs with the history-matched model revealed that VRR = 0.8 produces more oil than VRR = 0.7, but not by a significant quantity. Hence, the results suggest that improved recovery is not overly sensitive to the exact value of VRR and that VRR < 1 recovery processes for light-oil carbonate reservoirs are potentially robust


Type of resource text
Form electronic resource; remote; computer; online resource
Extent 1 online resource
Place California
Place [Stanford, California]
Publisher [Stanford University]
Copyright date 2020; ©2020
Publication date 2020; 2020
Issuance monographic
Language English


Author Aldousary, Salem Saad
Degree supervisor Kovscek, Anthony R. (Anthony Robert)
Thesis advisor Kovscek, Anthony R. (Anthony Robert)
Thesis advisor Castanier, Louis M
Thesis advisor Horne, Roland N
Degree committee member Castanier, Louis M
Degree committee member Horne, Roland N
Associated with Stanford University, Department of Energy Resources Engineering


Genre Theses
Genre Text

Bibliographic information

Statement of responsibility Salem Saad Aldousary
Note Submitted to the Department of Energy Resources Engineering
Thesis Thesis Ph.D. Stanford University 2020
Location electronic resource

Access conditions

© 2020 by Salem Saad Aldousary
This work is licensed under a Creative Commons Attribution 3.0 Unported license (CC BY).

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