Understanding the Impact of Brine Hardness on Chemical Enhanced Oil Recovery Surfactants Performance: A Data Journey

Brine composition is one of the key parameters in the design of a surfactant based oil recovery process and is a condition imposed by the reservoir nature. This brine can contain a large variety of ions including monovalent and divalent cations (hardness), which impacts the surfactants solubility. Moreover, hardness evolution during the injection process can also impair surfactant formulations’ performances. Water treatment processes are useful ways to mitigate such risks, but they imply higher CAPEX for the process. As a consequence, the selection of the right surfactant will have a large impact on the cost and on crude oil production. This paper describes solution properties of the most common surfactants used in surfactant flooding i.e. Alkyl Benzene Sulfonates (ABS) and Internal Olefin Sulfonates (IOS) as a function of the brine hardness and will be compared with Internal Ketone Sulfonates (IKS), a new bio-based surfactant family.

Olefin-surface interactions modulate the activity of silica-supported Mo-based olefin metathesis catalysts

Molecularly defined and classical heterogenous Mo-based metathesis catalysts are shown to display distinct and unexpected reactivity patterns for the metathesis of long-chain α-olefins at low temperatures (< 100 °C). Namely, catalysts based on supported Mo oxo species, whether prepared via wet impregnation or surface organometallic chemistry (SOMC), exhibit strong activity dependencies on the α-olefin chain length, with slower reaction rates for longer substrate chain lengths. In contrast, molecular and supported Mo alkylidenes are highly active and do not display such dramatic dependence on chain length. 2D solid-state NMR analyses of post-metathesis catalysts, complemented by molecular dynamics calculations, evidence that the activity decrease observed for supported Mo oxo catalysts relates to the strong adsorption of internal olefin metathesis products due to interactions with surface Si-OH groups. Overall, this study shows that in addition to the nature and the number of active sites, the metathesis rates and overall catalytic performance depend on product desorption, even in the liquid phase with non-polar substrates. This study further highlights the need to consider adsorption when designing catalysts and the unique activity of molecularly defined supported metathesis catalysts prepared via SOMC.

Development of integrated technology influencing on the high-temperature Jurassic reservoirs with a heterogeneity permeability

An advance of the rate of reserves development over the water cut rate characterizes the production in the permeable-heterogeneous high-temperature Jurassic sandstone sediments by waterflooding. It is necessary to jointly influence on such oil reservoir by the methods of enhanced oil recovery and the injectivity profile aligement for increasing of additional production of them. Increasing the coefficients of oil displacement by water (Kdisp.) and the coverage of the reservoir by waterflooding this will allow. A significant quantity of projects related to the use of surfactant compositions to increase oil recovery in high-temperature reservoirs are based on the use of internal olefin sulfonates (IOS). However, such projects risk being unprofitable, without the use of tax incentives. The research presents a composition of inexpensive and available large-scale reagents, which can increase a positive economic profitability of the project, despite the fact that the residual oil saturation during the process decreases to a lesser extent compared to compositions containing IOS. On the example of several oilfields, developing a methodology developing of an oil deposit using the technology of complex stimulation based on surfactant and polymer gel compositions is shown. This study includes carrying out physicochemical and filtration experiments, as well as hydrodynamic modeling of the process.

Effect of the Concentration of Viscosifier on Desorption Kinetics of Methane From Synthetic Based Fluids

Synthetic-oil based drilling mud is currently the most commonly used type of drilling fluid for offshore drilling in the Gulf of Mexico, due to the environmental regulation in the area, as well as the numerous operational benefits they provide. However, early kick detection and well control decision-making are more challenging due to the solubility of formation gas in synthetic-based fluids. This partially contributes to the poor understanding of the mass transfer kinetics of formation gas in and out of synthetic fluids during these well control events. The objective of this work was to better understand the mass transfer of gas from a solution by evaluating the influence of viscosifier concentration on the desorption kinetics of methane from pure internal olefin and internal olefin-viscosifier mixture. The desorption coefficients were determined from a custom-built mass transfer apparatus. Different suspentone concentrations ranging from 0 to 5wt% by volume of liquid were used to investigate the influence of viscosifier concentration on the desorption coefficient. It was observed that the presence of suspension agents in the liquid phase decreased the mass transfer coefficient. This decrease could be due to an increase in the resistance to the flow of gas bubbles evolving from the liquid phase.

Oil Recovery by Alkaline/Surfactant/Foam Flooding: Effect of Drive-Foam Quality on Oil-Bank Propagation

Summary Alkaline/surfactant/foam (ASF) flooding is a novel enhanced–oil–recovery (EOR) process that increases oil recovery over waterflooding by combining foaming with a decrease in the oil/water interfacial tension (IFT) by two to three orders of magnitude. We conducted an experimental study regarding the formation of an oil bank and its displacement by foam drives with foam qualities within the range of 57 to 97%. The experiments included bulk phase behavior tests using n–hexadecane and a single internal olefin sulfonate surfactant, and a series of computed–tomography (CT) –scanned coreflood experiments using Bentheimer Sandstone cores. The main goal of this study was to investigate the effect of drive–foam quality on oil–bank displacement. The surfactant formulation was found to lower the oil/water IFT by at least two orders of magnitude. Coreflood results, at under-optimum salinity conditions yielding an oil/water IFT on the order of 10–1 mN/m, showed similar ultimate–oil–recovery factors for the range of drive–foam qualities studied. A more distinct frontal oil–bank displacement was observed at lower drive–foam qualities investigated, yielding an increased oil–production rate. The findings in this study suggested that dispersive characteristics at the leading edge of the generated oil bank in this work were strongly related to the surfactant slug size used, the lowest drive–foam quality assessed yielded the highest apparent foam viscosity (and, thus, the most stable oil–bank displacement), and drive–foam strength increased upon touching the oil bank when using drive–foam qualities of 57 and 77%.

Retention of Hydraulic Fracturing Water in Shale: The Influence of Anionic Surfactant

A tremendous amount of water-based fracturing fluid with ancillary chemicals is injected into the shale reservoirs for hydraulic fracturing, nearly half of which is retained within the shale matrix. The fate of the retained fracturing fluid is raising some environmental and technical concerns. Mitigating these issues requires a knowledge of all the factors possibly contributing to the retention process. Many previous studies have discussed the role of shale properties such as mineralogy and capillarity on fracturing fluid retention. However, the role of some surface active agents like surfactants that are added in the hydraulic fracturing mixture in this issue needs to be understood. In this study, the influence of Internal Olefin Sulfate (IOS), which is an anionic surfactant often added in the fracturing fluid cocktail on this problem was investigated. The effect on water retention of treating two shales “BG-2 and KH-2” with IOS was experimentally examined. These shales were characterized for their mineralogy, total organic carbon (TOC) and surface functional groups. The volume of retained water due to IOS treatment increases by 131% in KH-2 and 87% in BG-2 shale. The difference in the volume of retained uptakes in both shales correlates with the difference in their TOC and mineralogy. It was also inferred that the IOS treatment of these shales reduces methane (CH4) adsorption by 50% in KH-2 and 30% in BG-2. These findings show that the presence of IOS in the composition of fracturing fluid could intensify water retention in shale.