This paper discusses the successful design, laboratory testing, and performance of an innovative, low-solids, organophilic-clay-free invert-emulsion fluid (OCF-IEF) used to drill the reservoir section of an extended-reach-drilling (ERD) well. A reservoir-conditions coreflood study was undertaken to assist with design of drilling and completion fluids for a Norwegian field. Multiple fluids were tested, and the lowest permeability alterations did not correlate with the lowest drilling-fluid-filtrate-loss volumes. Nonaqueous drilling fluids have been used extensively by the industry, particularly in complex drilling scenarios. They carry some concerns, however, with implications for well integrity.
This work focuses on the laboratory techniques for developing, assessing, and analyzing innovative water-based drilling fluids containing iron oxide (Fe2O3) and silica (SiO2) nanoparticles. They also have the ability to maintain optimal rheological properties so that many drilling problems can be mitigated efficiently. Drilling-fluid loss is considered the major source of capital expenditure during drilling operations. Nanoparticles have proved to be more effective in reducing the filtrate losses than conventional fluid-loss reducers. Because they exhibit different adsorption and transportation behavior in different porous media, nanoparticles have been used successfully as stabilizers in emulsions and foams, as rheology modifiers, and as fluid-loss additives in surfactant/polymer or water-based drilling fluids.
The challenge for nanotechnology-based drilling fluids is that in order to gain acceptance, they cannot simply match the industry's conventional chemistries--they must outperform them. Calgary-based nFluids believes it is among the first to answer that call. The 4-year-old firm is now in the early stages of commercializing its nanoparticle additive that it says is compatible with all types of drilling fluids. Based on results from nine pilot wells and an independent study by the University of Missouri, the company reports that its nano-additive has achieved up to a 60% increase in wellbore strength, a 90% reduction in fluid losses, and a 50% reduction in friction during drilling--with the latter translating to a faster rate of penetration. Jeffrey Forsyth, the chief executive officer of nFluids, said that since the company formed, it reduced its original manufacturing cost by about half while driving big improvements in the technology's effectiveness.
One of my knives has a bolster made of superconducting materials including unusual elements such as yttrium, bismuth, thallium, and strontium. Young professionals may not remember the buzz in the industry when scientists discovered superconducting properties in materials at much higher temperatures. As scientific and engineering advances made the news, oil and gas technology was scoured for potential applications. I remember an industry leader claiming that the technology would revolutionize the economics of the industry. While superconducting materials do have high-tech applications, they are poor choices for knife bolsters; my knife reminds me that scientific advances must be translated into practical applications to impact our business.
The Advanced Energy Consortium (AEC) is an internationally recognized research organization dedicated to achieving transformational understanding of subsurface oil and natural gas reservoirs through the deployment of unique micro- and nanosensors (Johnson 2010). The AEC was formed in 2008 by the University of Texas at Austin's Bureau of Economic Geology and major oil and gas companies to focus on conducting precompetitive research to address challenges in upstream exploration. Multiple sensor-technologies are being developed by the AEC and investigated in several applications, including wellbore characterization, hydraulic fracturing, waterflooding, enhanced oil recovery (EOR), and interwell reservoir characterization. The vision is exciting as it explores technologies for oilfield rocks in harsh environments, including high temperatures, high pressures, small pore spaces (30 nm to 10 µm), high salinity, and varied pH conditions. Since January 2008, more than USD 45 million has been invested in AEC research projects.
CO2 foam has been used to improve the sweep efficiency for EOR as a replacement for polymers to avoid potential formation damage. Foams degrade at high temperatures (>212°F), in high-salinity environments, and in contact with crude oil. The present work evaluates nanoparticles and viscoelastic surfactants (VES) to improve foam stability when these foams are used as EOR fluid.
This study investigates the stability of alpha olefin sulfonate (AOS) foam for different foam solutions in the presence of nanoparticles and viscosifiers (VES). To achieve this objective, foam stability tests were conducted at different temperatures up to 150°F. Foam stability was studied in a high-pressure view chamber (HPVC) to find the optimal. Single and dual-coreflood experiments were conducted at 150°F to investigate the divergent ability for the foam solutions on heterogonous sandstone formations. Boise and Berea sandstone cores with permeability contrast of 10-15 were saturated initially with a dead crude oil. The CO2 foam was injected with 80% quality as tertiary recovery mode. The oil recovery and the pressure drop across the core were measured for the different foam solutions.
Adding silica nanoparticles (0.1 wt%) of size 140 nm and viscoelastic cocamidopropyl betaine surfactant (cocobetaine VES) (0.4 wt%) to the AOS (0.5 wt%) solution improves foam stability. In contact with crude oil, unstable oil-in-water microemulsion generated inside the foam lamella that decreased foam stability. A weak foam was formed for AOS solution, but the foam stability increased by adding nanoparticles and VES. From the single coreflood experiments, the oil recovery from the conventional water flooding 47% of the original oil-in-place. AOS was not able to enhance the oil recovery. No more oil was recovered by AOS foam, however, extra oil was recovered in the presence of nanoparticles (19 %) and VES (26%). The dual-coreflood experiments revealed low sweep efficiency during the water flooding as a secondary recovery. Adding nanoparticles and VES to the AOS foam system increased the sweep efficiency and increased the oil recovery from the low permeability cores.
Nanoparticles and VES were able to improve the foam stability for AOS solution. Adding nanoparticles is highly recommended for EOR applications, particularly at high temperatures.
Nanoparticle stabilized emulsions have drawn increasing attention for applications in various industries including enhanced oil recovery (EOR). Unlike surfactants, nanoparticles provide long-term stability to the emulsions and significantly higher viscoelastic response. However, the flow behavior of nanoparticle stabilized emulsions in porous media has not been explored much. Cellulose Nanocrystals (CNCs) have gained attention in the past few years since they are an abundant renewable biomass-derived material. This study investigates the flow behavior and stability of oil in water emulsions stabilized by CNCs in unconsolidated porous media and the application of these emulsions in EOR and conformance control.
Confocal Microscopy coupled with Cryo-SEM enabled us to precisely characterize the emulsion microstructure and correlate it to the rheological behavior of the emulsions. The rheological measurements revealed that a strong droplet network forms within the emulsions over time. Importantly, we show that the same network forms when the emulsions occupy pore space in a granular material. Emulsions were injected through a sandpack with a porosity of 35% and average pore diameter of 54 μm. The injected emulsions were aged inside the porous media for 24 hours. Thorough experimental assessment of the collected effluent samples revealed that the emulsion was stable. The porous medium was then subjected to a gradually increasing pressure gradient of either water or oil. Gradients greatly exceeding typical near-well values (>300 psi/ft) were required to establish flow, and the resulting flow rate exhibited a pressure gradient three orders of magnitude higher than in an untreated water saturated sandpack. Interestingly, a significantly larger gradient was needed for water to flow than for oil, raising the possibility of using this class of emulsions for selective phase blocking, and perhaps as relative permeability modifiers. Moreover, emulsions stabilized with other material allowed water to flow at very small gradients, confirming that the network formation is critical for this application.
This study revealed the potential application of a naturally occurring biodegradable nanomaterial for conformance control and for curbing excessive water production where zonal isolation is difficult to achieve.
Heavy oil and bitumen comprise nearly 70% of remaining oil reserves. Producing such oil is very challenging and critical, as its viscosity should be reduced to a level which can be mobile in the reservoir that can be made by different thermal recovery methods. Aquathermolysis reaction is the main objective used to analysis and explain the effect of nanoparticles addition on heavy oil for viscosity reduction. Several thermal recovery techniques have been implemented using different nanometals for recovery improvement of heavy oil reservoirs and viscosity reduction.
These published trials focused on nanometals but none of them addressed usage of Graphene oxide nanoparticles for such improvement of heavy oil recovery, and therefore this paper represents an experimental investigation of graphene oxide effect on heavy oil production. The present work examines graphene oxide nanoparticle effect on heavy oil viscosity since graphene is a superlative material that has an extraordinary thermal conductivity up to ten times value of any nanometal. In order to check its efficiency for Heavy oil recovery.
In our work, the concentration used for these nanoparticles is ranging from 0.01: 0.5 wt. %. The viscosity of these nanoparticles with heavy oil sample has been measured to explain the expected improvement in recovery factor. The Experimental work showed a large change in the viscosity after using nano Graphene oxide reached to 40:60% reduction in its original values. In addition to the viscosity, the effect of reservoir temperature is investigated. The range of temperature used in this study varies between 40° to 100° C. These results reflect strong indications for better viscosity reduction. Therefore, better recovery factor for this heavy oil. Also, Therotical and experimental explanation have been conducted for that viscosity reduction behavior.
Thus, this present research provides an investigation of aquathermolysis reaction for such materials which is the main reason for that heavy oil viscosity reduction behavior, also it represents Graphene Oxide as new nanoparticles for improving Heavy Oil Recovery that will create a new era in thermal recovery for heavy oil. Also, an economic study is investigated.
The increasing world energy demand has derived in the consumption of conventional sources of energy, leading to a rise in non-conventional resources such as heavy oils (HO). Nevertheless, the HO physicochemical properties such as high viscosity, are related to significant operational issues in production and transport processes. Thus, the main objective of this study is the HO viscosity reduction through a novel cracking reactions method prompted by an ultrasound cavitation technique assisted with nickel oxide nanoparticles functionalized over nanoparticulated silica (SiNi) as catalysts, and water as a hydrogen donor for enhancing the cracking reactions, fomenting the conversion of the crude oil heavy compounds (asphaltenes) into lighter sub-components. An HO with 17.02% of asphaltenes content was used for carrying out the tests. Along the study, there were identified several viscosity reduction mechanisms related with asphaltenes adsorption onto SiNi nanoparticles surface affecting the fluid internal structure, as well as the reduction of the crude oil asphaltenes content due to its conversion into lighter components. These mechanisms were widely explained by a phenomenological approach through rheological behavior measurements and modeling, which also provide a better understanding of the treatment effect in the HO mobility and an increased transport capacity. The viscosity measurements were realized upon nanoparticles and gasoline addition, and ultrasound cavitation separately. The ultrasound cavitation submission time was evaluated, with better results as the exposure time increased. The effect of nanoparticles concentration was also assessed, obtaining high degrees of viscosity reduction with nanoparticles dosages 2000 mg/L.
Murugesan, Sankaran (Baker Hughes, a GE Company) | Agrawal, Devesh (Baker Hughes, a GE Company) | Suresh, Radhika (Baker Hughes, a GE Company) | Khabashesku, Valery (Baker Hughes, a GE Company) | Darugar, Qusai (Baker Hughes, a GE Company)
Luminescent upconversion nanoparticles are used as alternate fluorescence tracers to overcome the interference of organic molecules in the analysis of flowback waters. Upconversion nanoparticles use low-energy excitation at approximately 980 nm with high-energy emissions in the region of 200 to 950 nm. Emission properties of the nanoparticles are tuned by selective doping, and their dispersiblity in water and oil are altered through appropriate functionalization. The flow experiments used stable crude oil emulsions in API brine with the mixture of two different emission upconversion tracer nanoparticles. Data from these experiments suggest that the nanoparticle tracers can flow through the porous media and distinguish between each other, even in the presence of organics in an emulsion. This capability can open new avenues in in-situ reservoir communication and understanding.