In hydrofractured shales, elevated formation pore pressures drive movement of fluids toward hydrofractures, but other forces are equally important. Connate waters are saline to hypersaline, and have much higher osmotic potentials than the dilute hydrofracturing/treatment waters. Moreover, very low water saturations and small matrix pore sizes produce high in situ capillary potentials. Strong capillary and osmotic potentials drive matrix imbibition of dilute fracking fluids, and the resulting counterflow of hydrocarbons may account for a significant fraction of initial hydrocarbon yields. However, strong capillary and osmotic pressures can result in formation damage through water blocking or sanding, adversely affecting hydrocarbon production. In oil shales, imbibition of aqueous fracking fluids provides access to matrix mineral surfaces, allowing chemical amendments in process fluids to modify oil adhesion and improve oil mobility. While gas sorption in shales is physisorption, oil adhesion is controlled by surface complexation and is affected by the surface chemistry of the oil and of the minerals, and the chemistry of the intervening water layer. Shale solid surfaces are likely dominated by illite and kerogen; oil‐illite adhesion is controlled by electrostatics. Oil adhesion to the mineral matrix is favored by lower salinities and low pH.
Various versions of deep borehole nuclear waste disposal have been proposed in the past in which effective sealing of a borehole after waste emplacement is generally required. In a high temperature disposal mode, the sealing function will be fulfilled by melting the ambient granitic rock with waste decay heat or an external heating source, creating a melt that will encapsulate waste containers or plug a portion of the borehole above a stack of the containers. However, there are certain drawbacks associated with natural materials, such as high melting temperatures, inefficient consolidation, slow crystallization kinetics, the resulting sealing materials generally being porous with low mechanical strength, insufficient adhesion to waste container surface, and lack of flexibility for engineering controls. In this study, we showed that natural granitic materials can be purposefully engineered through chemical modifications to enhance the sealing capability of the materials for deep borehole disposal. The present work systematically explores the effect of chemical modification and crystallinity (amorphous vs. crystalline) on the melting and crystallization processes of a granitic rock system. The approach can be applied to modify granites excavated from different geological sites. Several engineered granitic materials have been explored which possess significantly lower processing and densification temperatures than natural granites. Those new materials consolidate more efficiently by viscous flow and accelerated recrystallization without compromising their mechanical integrity and properties.
This report represents completion of milestone deliverable M2SF-18SNO10309013 "Inventory and Waste Characterization Status Report and OWL Update that reports on FY2018 activities for the work package (WP) SF-18SNO1030901. This report provides the detailed final information for completed FY2018 work activities for WP SF-18SN01030901, and a summary of priorities for FY2019. This status report on FY2018 activities includes evaluations of waste form characteristics and waste form performance models, updates to the OWL development, and descriptions of the two planned management processes for the OWL. Updates to the OWL include an updated user's guide, additions to the OWL database content for wastes and waste forms, results of the Beta testing and changes implemented from it. There are two processes being planned in FY2018, which will be implemented in FY2019. One process covers methods for interfacing with the DOE SNF DB (DOE 2007) at INL on the numerous entries for DOE managed SNF, and the other process covers the management of updates to, and version control/archiving of, the OWL database. In FY2018, we have pursued three studies to evaluate/redefine waste form characteristics and/or performance models. First characteristic isotopic ratios for various waste forms included in postclosure performance studies are being evaluated to delineate isotope ratio tags that quantitatively identify each particular waste form. This evaluation arose due to questions regarding the relative contributions of radionuclides from disparate waste forms in GDSA results, particularly, radionuclide contributions of DOE-managed SNF vs HLW glass. In our second study we are evaluating the bases of glass waste degradation rate models to the HIP calcine waste form. The HIP calcine may likely be a ceramic matrix material, with multiple ceramic phases with/without a glass phase. The ceramic phases are likely to have different degradation performance from the glass portion. The distribution of radionuclides among those various phases may also be a factor in the radionuclide release rates. Additionally, we have an ongoing investigation of the performance behavior of TRISO particle fuels and are developing a stochastic model for the degradation of those fuels that accounts for simultaneous corrosion of the silicon carbide (SiC) layer and radionuclide diffusion through it. The detailed model of the TRISO particles themselves, will be merged with models of the degradation behavior(s) of the graphite matrix (either prismatic compacts or spherical "pebbles") containing the particles and the hexagonal graphite elements holding the compacts.
Mwangi, Paulina; Brady, Patrick V.; Radonjic, Mileva; Thyne, Geoffrey
This paper examines the role of crude oil's organic acid surface active compounds (SAC) in determining the reservoir wettability over a range of salinities and temperatures. To isolate the effects of individual SACs, this project used model oil mixtures of pure decane and single SACs to represent the oleic phase. Due to the large number of experiments in this study, we used wettability measurement method by the modified flotation technique (MFT) to produce fast, reliable, and quantitative results. The results showed that oil wetting by decane increased with temperature for carbonate rocks. Sandstones oil wetting showed little temperature dependency. The presence of long-chained acids in decane increased oil wetting in sandstone and carbonate rocks as salinity was lowered, while the short-chained acid increased water wetting under the same conditions. The effect of organic acids on wettability was slightly enhanced with increasing temperature for all rock types.
Chen, Yongqiang; Xie, Quan; Sari, Ahmad; Brady, Patrick V.; Saeedi, Ali
Wettability of the oil/brine/rock system is an essential petro-physical parameter which governs subsurface multiphase flow behaviour and the distribution of fluids, thus directly affecting oil recovery. Recent studies [1–3] show that manipulation of injected brine composition can enhance oil recovery by shifting wettability from oil-wet to water-wet. However, what factor(s) control system wettability has not been completely elucidated due to incomplete understanding of the geochemical system. To isolate and identify the key factors at play we used SO42—free solutions to examine the effect of salinity (formation brine/FB, 10 times diluted formation brine/10 dFB, and 100 times diluted formation brine/100 dFB) on the contact angle of oil droplets at the surface of calcite. We then compared contact angle results with predictions of surface complexation by low salinity water using PHREEQC software. We demonstrate that the conventional dilution approach likely triggers an oil-wet system at low pH, which may explain why the low salinity water EOR-effect is not always observed by injecting low salinity water in carbonated reservoirs. pH plays a fundamental role in the surface chemistry of oil/brine interfaces, and wettability. Our contact angle results show that formation brine triggered a strong water-wet system (35°) at pH 2.55, yet 100 times diluted formation brine led to a strongly oil-wet system (contact angle = 175°) at pH 5.68. Surface complexation modelling correctly predicted the wettability trend with salinity; the bond product sum ([>CaOH2+][–COO−] + [>CO3−][–NH+] + [>CO3−][–COOCa+]) increased with decreasing salinity. At pH < 6 dilution likely makes the calcite surface oil-wet, particularly for crude oils with high base number. Yet, dilution probably causes water wetness at pH > 7 for crude oils with high acid number.
This report supplements Joint Workplan on Filler Investigations for DPCs (SNL 2017) providing new and some corrected information for use in planning Phase 1 laboratory testing of slurry cements as possible DPC fillers. The scope description is to "Describe a complete laboratory testing program for filler composition, delivery, emplacement in surrogate canisters, and post-test examination. To the extent possible specify filler material and equipment sources." This report includes results from an independent expert review (Dr. Arun Wagh, retired from Argonne National Laboratory and contracted by Sandia) that helped to narrow the range of cement types for consideration, and to provide further guidance on mix variations to optimize injectability, durability, and other aspects of filler performance.
Society of Petroleum Engineers - SPE Kingdom of Saudi Arabia Annual Technical Symposium and Exhibition 2018, SATS 2018
Al-Saedi, Hasan N.; Alkhamis, Mohammed; Brady, Patrick V.; Flori, Ralph E.
Low salinity water flooding and steam flooding are two novel combination flooding methods that were combined due to the important role of both methods in increasing oil recovery (especially heavy oil). Low salinity flooding was examined by many laboratory and field works and showed an interesting result. Steam flooding was tested on heavy oil fields and the heavy oil recovery increased by reducing oil viscosity. Although the steam showed an improvement in heavy oil recovery, the density difference between steam and heavy oil raised a problems with steam gravity override, channeling, and early breakthrough. For that reason, we developed the low salinity alternating steam flood (LSASF) in order to gather the benefits of low salinity, reduce oil viscosity by steam, and prevent the steam problems mentioned earlier. The laboratory experiments showed that the optimum scenario was Scenario (3). The shorter the injected cycles, the more oil recovery. This combination of echnology can solve the steam flooding problems and support the steam by LS water, which has the ability to increase oil recovery.
The removal of silica, ubiquitous in produced and industrial waters, by novel mixed oxides is investigated in this present study. We have combined the advantage of high selectivity hydrotalcite (HTC, (Mg6Al2(OH)16(CO3)·4H2O)), with large surface area of active alumina (AA, (Al2O3)) for effective removing of the dissolved silica from cooling tower water. The batch test results indicated the combined HTC/AA is a more effective method for removing silica from CTW than using each of HTC or AA separately. The silica uptake was confirmed by Fourier transform infrared (FTIR), and Energy dispersive spectroscopy (EDS). Results indicate HTC/AA effectively removes silica from cooling tower water (CTW), even in the presence of large concentrations of competing anions, such as Cl−, NO3− HCO3−, CO32− and SO42−. The Single Path Flow Through (SPFT) tests confirmed to rapid uptake of silica by combined HTC/AA during column filtration. The experimental data of silica adsorption fit best to Freundlich isotherm model.
This workplan addresses filler attributes (i.e., possible requirements), assumptions needed for analysis, selection of filler materials, testing needs, and a long-range perspective on R&D activities leading to filler demonstration and a safety basis for implementation.
Xie, Quan; Saeedi, Ali; Delle Piane, Claudio; Esteban, Lionel; Brady, Patrick V.
The South West Hub project is one of the Australian Flagship Carbon Capture and Storage projects located in the south-west of Western Australia. To evaluate the injectivity potential during the forthcoming full-scale CO2 injection, we conducted three core-flooding experiments using reservoir core plugs from the well Harvey-1. We aimed to investigate whether the injection of CO2 leads to fines migration and permeability reduction due to the relatively high kaolinite content (up to 13%) in the injection interval of the target formation (i.e. the Wonnerup Member of the Lesueur Formation). We imaged the core samples before flooding to verify the presence of kaolinite at the pore-scale using scanning electron microscopy (SEM). We also examined the pore network of the core plugs before and after the core-flooding experiments using Nuclear Magnetic Resonance (NMR). Moreover, to gain a better understanding of any kaolinite fines migration, we delineated surface force using two models based on Derjaguin−Landau−Verwey−Overbeek (denoted by DLVO) theory coupled hydrodynamic force: (1) sphere/flat model representing interaction between kaolinite/quartz, and (2) flat/flat model representing interaction between kaolinite/kaolinite. Our core-flooding experimental results showed that CO2/brine injection triggered moderate to significant reduction in the permeability of the core samples with a negligible porosity change. NMR measurements supported the core-flooding results, suggesting that the relatively large pores disappeared in favour of a higher proportion of the medium to small pores after flooding. The DLVO calculations showed that some kaolinite particles probably lifted off and detached from neighbouring kaolinite particles rather than quartz grains. Moreover, the modelling results showed that the kaolinite fines migration would not occur under normal reservoir multiphase flow conditions. This is not because of the low hydrodynamic force. It is rather because the geometries of the particles dominate their interplay. Overall, both of the experimental and analytical modelling results point to the fines migration to be the most likely cause of the permeability impairment observed during core-flooding experiments.