The electromagnetic heating of oil wells and reservoirs refers to thermal processes for the improved production of oil from underground reservoirs. The source of the heat, generated either in the wells or in the volume of the reservoir, is the electrical energy supplied from the surface. This energy is then transmitted to the reservoir either by cables or through metal structures that reach the reservoir. The main effect, because of the electrical heating systems used in practice in enhanced oil recovery, has been the reduction of the viscosity of heavy and extra heavy crudes and bitumens, with the corresponding increase in production. Focus is centered on systems (and the models that describe their effects) that have been used for the electromagnetic heating in the production of extra heavy petroleum and bitumen.
Geochemical data measured on oil samples produced from wells landed in the Austin Chalk, the Eagle Ford Formation, and the Buda Formation and on petroleum samples sequentially extracted from Upper Eagle Ford and Lower Eagle Ford marl and calcareous shale core pucks using several solvents were used to estimate the amount and properties of producible oil, immobile adsorbed/dissolved oil, and non-producible bitumen in those core samples. Crushed core samples obtained from two monitor wells located on the San Marcos Arch where Eagle Ford source-rock beds have reached different levels of maturity were sequentially extracted using a weak solvent (cyclohexane; CH), two stronger solvents (toluene and DCM), and a very strong solvent (chloroform-methanol; CM). Similar geochemical data were measured on the core extracts (after heating them to evaporate the solvents), and on native and topped oil samples. The CH extracts exhibit n-alkane profiles characteristic of crude oil, but extracts obtained using stronger solvent do not resemble oil. C15-C35 HC compounds present in produced oils are more abundant in CH extracts (which principally contain producible oil and adsorbed/dissolved oil) than in extracts obtained using stronger solvents (which principally contain bitumen). The SARA composition of topped oil samples also is more similar to the composition of core extracts obtained using CH than extracts obtained using stronger solvents (which contain significantly more resins and asphaltenes). The extract obtained from lower-maturity marl core pucks using CH contains much more sulfur (≈4.4 wt%) than the CH extract obtained from more thermally mature marl core pucks (≈2.0 wt%). Calibrations between the API gravity, C7 temperature, and sulfur content of native and topped oil samples were used to estimate the gravity and sulfur content of core extracts obtained using different solvents. The amount of resin-rich immobile oil in the core extracts was estimated using reasonable assumptions about the composition of that component. The Lower Eagle Ford marl at the higher-maturity monitor well contains ≈0.35 wt% of ≈30-31°API producible oil and ≈0.27 wt% of non-producible bitumen. That reservoir contains only ≈0.12 wt% of ≈27°API producible oil and ≈0.38 wt% of non-producible bitumen at the lower-maturity monitor well. The LEF calcareous shale contains approximately the same amount of producible oil as the overlying marl at the more mature monitor well, but it contains much less non-producible bitumen (≈0.12 wt%).
Li, Qingyun (SLAC National Accelerator Laboratory / Stanford University) | Jew, Adam (SLAC National Accelerator Laboratory) | Cercone, David (National Energy Technology Laboratory) | Bargar, John (SLAC National Accelerator Laboratory) | Brown, Gordon E. (SLAC National Accelerator Laboratory / Stanford University) | Maher, Katherine (Stanford University)
Laboratory experiments have shown that hydraulic fracturing fluids (HFF) can chemically interact with iron(Fe)-bearing minerals in shale, releasing Fe(II) which is then oxidized to form Fe(III)-(hydr)oxide scale. The Fe(III)-(hydr)oxide scale can occlude pore space and reduce oil and gas production in wells. Our previous experimental studies show that Fe(III)-(hydr)oxides can precipitate even under acidic conditions where Fe(II) oxidation is unexpected. This is due to bitumen that is extracted from shale by chemical additives in HFF, which can aid in Fe(II) oxidation and lead to the precipitation of Fe(III)-(hydr)oxides. In this numerical modeling study, we built two geochemical models to simulate our experimental observations. One model was developed to construct the rate law of Fe(II) oxidation in the presence of bitumen in a shale-free system, while the other model was used to understand the chemical reaction network and quantify the impact of bitumen on iron oxidation/precipitation during shale-HFF interactions. Our modeling results have shown that in both high- and low-carbonate shale systems, the presence of bitumen can increase the rate of iron oxidation/precipitation by more than an order of magnitude compared to bitumen-free systems. In addition, the availability of dissolved oxygen to pyrite grains is critical for Fe dynamics during shale-HFF interactions. The chemical reaction network obtained from this study, along with the bitumen-aided Fe(II) oxidation rate law, pave the way for future modeling studies on chemical reactions during hydraulic fracturing and their influence on formation damage and lost hydrocarbon production.
Scale formation during unconventional stimulation can reduce porosity and permeability which, in turn, can affect hydrocarbon flow in oil and gas wells. Operators add iron (Fe) control agents such as citrate and methanol to the hydraulic fracturing fluid (HFF) to prevent the deposition of Fe(III)-(hydr)oxide (Fe(OH)3) minerals in the pore space of shale (FracFocus). Our previous studies have shown that even with Fe control agents, Fe(OH)3 can still precipitate (Harrison et al. 2017, Jew et al. 2017). The Fe in these Fe(III)-bearing precipitates comes primarily from dissolution of pyrite (FeS2), a common mineral in shale, during shale-HFF interactions. In unconventional reservoirs, Fe is released from corrosion of downhole steel in addition to dissolution of native pyrite due to injection of a 15% hydrochloric acid spearhead, resulting in more severe scaling. During pyrite dissolution and pipe corrosion, Fe is released to fluid in the Fe(II) oxidation state, and is further oxidized by dissolved oxygen (O2) in the fluid to Fe(III), which readily precipitates upon acid neutralization. Our previous studies also found that Fe(II) oxidation can be aided by aqueous bitumen leached from shale by organic compounds in the fracturing fluid (Jew et al. 2017). The effect of bitumen on Fe(II) oxidation is enormous, especially under acidic conditions, where bitumen was found to promote Fe(II) oxidation and Fe(OH)3 precipitation that otherwise would not occur. This phenomenon is important, because in most hydraulic fracturing operations, the acid spearhead is the first chemical injected down the borehole for cleaning purposes. Subsequent injections of slickwater/slurry allow for the acid to be pushed into the stimulated rock volume (SRV). Under the acidic conditions along the fluid flow pathways, the formation of Fe(III)-(hydr)oxide scale depends on not only the dissolved O2 concentration in solution but also bitumen-aided Fe(II) oxidation.
As a Flow Measurement Consultant at NEL, Craig’s responsibilities include working on a large variety of R&D, training and consultancy projects focused on single and multi-phase metering technology. He performs a variety of roles including project formulation, project management, technical lead, planning/delivering test work, data analysis and report writing. Craig has spent 10 years at NEL completing work in the technical areas of engineering design and review for custody transfer and fiscal metering measurement systems, measurement allocation philosophy documents, measurement system audits and financial exposure calculations. Currently, Craig is undertaking a doctorate degree at Coventry University in heavy oil and bitumen flow measurement and as part of the work has developed a Reynolds number correction method calculating flow and fluid physical properties in real-time. Risk management in thermal wellbore integrity can be promoted by the proper collection, processing and interpretation of data from various types of wellbore instrumentation.
It’s no secret that oil majors are among the biggest corporate emitters of pollution. What may be surprising is that they’re reducing their greenhouse-gas footprints every year, actively participating in a trend that’s swept up most corporate behemoths. The Canadian and Alberta governments and three energy companies said on 11 May that they will spend CAD 70 million (USD 51.14 million) to develop three new clean technology projects, aimed at cutting costs and carbon emissions in the country’s oil sands.
An improved occupational health and safety system comes into effect on 1 June to better protect Alberta workers and ensure they have the same rights as other Canadians. The Alberta Energy Regulator has issued two draft directives that will require upstream oil and gas operators to reduce methane emissions from upstream oil and gas sites by 45% from 2014 levels by 2025. On 16 June 2017, the Alberta Oil Sands Advisory Group released its report Recommendations on Implementation of the Oil Sands Emissions Limit Established by the Alberta Climate Leadership Plan.
The oil and gas major has set aside $100 million to fund projects that will deliver new greenhouse gas emissions reductions in its upstream oil and gas operations. The emissions intensity of upstream Canadian oil sands production will continue to decline in coming years, falling to 30% below 2009 levels by 2030, a new report by business information provider IHS Markit says. On 26 April 2018, Canada's minister of environment and climate change announced new regulations under the Canadian Environmental Protection Act, 1999, to reduce methane emissions in the oil and gas sector by almost half.
Things are so tough in the Canadian oil sands that competitors are considering whether to start sharing some of what they know about producing more and doing it for less. Collaboration should speed progress for everyone, but companies with something to give are looking for something in return. Tiny bubbles, called nanobubbles, are the focal point of a new innovation aimed at transforming produced water from a costly byproduct into a valuable asset.