Nanotechnology Research and Development in Upstream Oil and Gas

2.1 Wellbore Stability

When drilling through shale-producing formations, water invasion into the shale can weaken the wellbore and lead to difficulties in drilling, such as stuck pipe and hole collapse. WBM formulations that include nanosilicas have been shown to offer improved shale inhibition over some of the commercially available non-nanoparticle-based shale inhibitors. Because the extremely low permeability of shales (nano-Darcy) does not allow the fluid to permeate the formation as more permeable rock formation does, conventional filter-cake-forming technologies are not options in drilling through shales with WBMs.

Formation mineralogy is important when it comes to the design of drilling fluids for use with shales. Shale is a sedimentary rock composed of silicates and aluminosilicates such as quartz, clay minerals, carbonates, and other minerals such as pyrite. The clay content in shales makes them reactive to water-based drilling fluids. Different varieties of clays react differently to water. For example, a shale with a high smectite content will typically have a higher reactivity to water than a shale with a higher illite content.31

To address some of the issues in drilling through water-sensitive shale formations, nanosized particles can be designed to penetrate deeper into the formation and plug the shale pores to stop water invasion (Figure 3). High concentrations (from 5 to 50 wt%) of nanosilicas show plugging of shale core samples with a composition of between 17% and 20% smectite.32 These high concentrations of nanosilicas limit the economic viability of these products in the field, so a more active kind of nanosilica has been sought and applied for use in drilling operations. At concentrations below 3 wt%, nanosilicas functionalized with alkylamines show improved inhibition activity of shale (with 28% smectite/illite mixed layers) in WBMs. When allowed to interact synergistically with polymers, such as polyanionic cellulose, these nanosilicas show even greater efficacy, inhibiting clays in shales from reacting when in sea water-based drilling fluids.33 These nanoparticle systems also benefit from milder, less caustic fluid requirements over silicate muds, well known to inhibit shales. While these silicate muds require a pH in excess of 12, nanosilica drilling fluids can be adjusted below 10.18

Wellbore strengthening is a critical component sought in drilling through all formations. A strong wellbore is as important for oil or gas wells constructed through shales as it is for limestones and sandstones. Wellbore strengthening during drilling operations has also been achieved by the use of ferric hydroxide nanoparticles. A study by Nwaoji et al. utilized these nanoparticles as a loss circulation material (LCM) that resulted in a stronger wellbore and minimized fluid losses.34 The ferric hydroxide nanoparticle formulations were exposed to sandstone core samples. Cores display ultimate compressive strength values 70% higher than unexposed cores (comparing 16.5 and 27.5 MPa).

2.2 Filtration Control of Drilling Fluids with Nanoparticles

Rock formations which have higher permeability than typical shales, such as sandstones and limestones, require additives to prevent filtration of the drilling fluid into the formation. Since drilling fluids are typically weighted such that there is a positive overbalance between the drilling fluid and the formation's pore pressure, a filter cake at the rock–fluid interface is built to prevent fluid loss from the drilling mud. It is important that this filter cake (also known as the “mud cake”) is as impermeable to fluid loss from the drilling fluid as possible and that it builds this essential impermeability quickly. It is also critical for subsequent cementing operations that the mud cake be thin to ease in the removal of the mud cake after drilling operations. The well is drilled in intervals. After an interval is completed, a spacer fluid is pushed through the annulus of the well between the casing and formation. This fluid is flushed through the well to displace the drilling mud, clean the annulus of drilling mud, and remove the mud cake. A thick mud cake left on the formation after spacer treatment and after the placement of the cement can interfere with cement bonding to the rock formation. This is a potential leak pathway for formation fluids along the length of the well and a source of mechanical weakness and debonding of the cement from the formation.

Some nanomaterials have shown synergies with clays, such as bentonite, to not only reduce the filtration of fluid from the drilling mud into the formation but also enhance the rheological properties of the fluid. Ferric oxide nanoparticles in bentonite muds show promising results in this regard. Ferric oxide nanoparticles are believed to intercalate the bentonite clay platelets displacing the complexed ions (calcium and/or sodium) at high temperatures ultimately with the effect of increasing filtration control. A loading of 0.5 wt% of nano-Fe₂O₃ provides a 22% reduction in filter-cake thickness and a 17% decrease in filtrate volume where the test was performed at 120 °C.35 The performance of Fe₂O₃ nanoparticles from 3 to 30 nm has been tested to show the enhanced benefit of filtration control in drilling fluids at temperatures up to 200 °C, showing a 28% decrease in filtrate volume compared with the control without iron nanoparticles.36

WBMs including xanthan and graphene oxide (GO) have also shown value for filtration control in sandstone core samples. Comparing WBMs containing GO and commercially available drilling fluids, the filter cake formed from the standard American Petroleum Institute (API) test for fluid-loss control is approximately an order of magnitude thinner in the case of WBMs with GO. The amount of filtrate collected during the test is also slightly lower than with the commercially available additive.28

2.3 Rheological Optimization with Nanoparticles

Another drilling domain that shows promise from the use of nanoparticles is the design of drilling fluids for harsh environments where temperatures above 120 °C impact drilling fluid shear response due to thermal degradation of the viscosifiers in the fluid. Oxidation-resistant materials, polymers, and nanomaterials are of substantial value when drilling fluids are used with high brine concentrations. High brine concentrations are used in drilling fluids and completion fluids to densify the fluids in place of solid particles, such as barite. Since barite particulates can irreversibly plug pore throats and reduce the permeability of rock formations, these additives are often avoided in reservoir sections/intervals of the well. The implementation of soluble high-density salts (such as calcium chloride, sodium formate, sodium bromide, and zinc bromide) is often recommended when the effect of formation damage is important. Cuttings from the drilling process need to be carried, suspended, and transported by these fluids, and so yield points in excess of 1  Pa are often sought and achieved with conventional additives such as guar gum, xanthan, and crosslinked starch. Oxidative damage to these additives, however, becomes a significant problem in temperatures in excess of 120 °C in brines.

Cellulose nanofibers (CNFs) have shown potential as rheology modifiers in brines. Heggset et al. have demonstrated that functionalization of nanocellulose through controlled oxidation with 2,2,6,6-tetramethylpiperidine-1-oxyl radical (TEMPO) increases the temperature tolerance of WBMs based in cesium formate and sodium formate brines over both standard polymers, such as guar gum and xanthan, and nanocellulose without functionalization.37 CNFs as well as cellulose nanocrystals (CNCs) have demonstrated the ability to increase yield points in WBMs containing bentonite. It is believed that the CNCs form assembled complexes with bentonite platelets to increase yield point and fluid thixotropy, which were further enhanced through synergetic interactions with polyanionic cellulose.38 When CNCs with carboxylate (cCNC) functionalities and cationic CNCs (caCNC) are used in low-solid WBMs, further enhancements are observed in filtration control and rheology. It has been found that while CNFs and CNCs show potential for rheological modification of fluids, their use in filtration control is more modest and they are often outperformed by other nanoparticles such as iron oxide nanoparticles,36 GO,28 and nanosilica.33

2.4 Enhancement of Other Properties of Drilling Fluids with Nanoparticles

Other aspects which are important in drilling include thermal conductivity and electrical conductivity. Drilling requires a thermally conductive drilling fluid to transport heat away from the drill bit. Resistivity logging is a technique often preferred for imaging the wellbore which requires an electrically conductive drilling fluid. The effect of nanoparticles on the thermal and electrical properties of drilling fluids has also been investigated. The high surface area-to-volume ratios of nanomaterials are believed to contribute strongly to high heat transfer rates along with increased electron conduction. Enhancements have been shown for nanosized tin oxide38 and 50 nm copper/zinc oxide in polyanionic cellulose WBMs where up to 53% increases in thermal conductivity are observed with concentrations of nanoparticles between 1 and 5 × 10⁻³%. Electrical conductivity increases were also observed with the 50 nm ZnO nanoparticles.8

H₂S released by some rock formations during drilling is a major safety concern for drilling operations. The primary concern with H₂S is the hazard that it brings to field personnel. Exposure to 600 ppm levels of H₂S is known to be fatal within 3–5 min. In addition to toxicity, H₂S is extremely corrosive to equipment used in well construction. The dominant commercial materials available for scavenging H₂S are zinc compounds such as zinc oxide (ZnO), zinc carbonate,39 and iron oxide (Fe₃O₄).40 Zinc oxide consumes H₂S, converting it to zinc sulfide. The surface area-to-volume ratio of nanosized zinc oxide particles allows the reaction with H₂S to occur with much more favorable kinetics than bulk zinc oxide. Nanoparticle samples can completely remove 800 ppm of H₂S from mud after 15 min at room temperature. This compares well with bulk ZnO which removes 2.5 % of H₂S in 90 min.19

Drilling fluid wastes are an environmental concern in the drilling industry, and the effects of drilling activities using nonaqueous fluids on the metal contents of marine sediments are being addressed by some groups. It is known that the drilling fluid discharged in the mud pit at the drilling rig can contain a considerable amount of toxic heavy metal. Metals of this kind are a concern when they are not contained because of their potential to contaminate soils and permeate into ground water.41 Functionalized nanomagnetic particles of Fe₃O₄ have been shown to provide an effective means of fishing out harmful pollutants such as cadmium from WBMs and OBMs.10 This nanoparticle acts as a magnetic nanoadsorbent in the removal of cadmium from drilling muds. It has at its core nano-Fe₃O₄ which is decorated with polyacrylic acid chains, which are covalently bound to the iron oxide core and functionalized with amino groups at their ends (Figure 4).42 When these nanoparticles are added to a WBM with 5 ppm cadmium, 90% of the cadmium is removed from the mud within seconds.10

Field trials of nanoparticle additives in drilling fluids are under way, meeting with some success in improving the drilling fluid performance.43 Cost drivers are key in all sectors of the business and lowering the cost of nanoparticles will be key to their use in the field as they proceed into commercialization.

3.1 Autogenous Shrinkage and Nanomaterials

PCs shrink volumetrically (autogenous shrinkage) during setting, sometimes leading to the formation of channels in the cement, thereby allowing for fluid communication between zones in the oil and gas well.46 MgO is an additive which expands as it is converted into magesium hydroxide (Mg(OH)₂) after exposure to water in the mixed cement slurry. The expansive properties of nanoscale MgO can be controlled through heat-treatment conditions (typically between 500 and 1400 °C) due to the influence of heat on the crystal structure and surface area of MgO. Typically, the higher the temperature the particles are heated to and the longer they are heated, the slower the reaction of MgO with water. This expansion can be further controlled through the synthesis of nanosized MgO. In this case, the expansion rate and extent are determined by the MgO calcining time and temperature, as well as the particle size of the MgO.

The reactivity of MgO must be adjusted to provide maximum expansion in the late plastic phase, at the beginnning of the hardening of the cement. This is why calcium oxide (CaO) systems, which tend to provide only early-stage expansion, are less favored than MgO systems. Given the variety of well conditions, MgO when used as an additive must be tailored to the temperature and pressure conditions of the well in which it is used. About 4% of MgO calcined at 700 °C, for example, has been found to be excellent at reducing shrinkage strains in a class G PC at 40 °C. At 100 °C, the same additive may not counter the effects of autogenous shrinkage as well.6, 20 An active area of research currently aims at providing a more generic additive solution to act against the shrinkage problem under a wide range of well conditions.

3.2 Nanoparticle Cement Set Accelerators and Gas Migration Additives

Cement set accelerators are important chemical additives in oil well cements. They offer the possibility of shortening the time duration it takes for the cement to transition from liquid (slurry) into the solid phase. This period of time, known as “waiting on cement” (WOC), incurs costs with each minute, much of which can be mitigated with good precision cement design. Cement accelerators are also used to reduce the risk of a phenomenon known as gas migration which is of critical importance to zonal isolation. Inorganic salts such as calcium chloride are often used as cement accelerators for these cases. These accelerators, however, are known to have the negative side effect of increasing the cement porosity. Due to its high surface activity, nanosilica has been proposed as a good replacement material as a cement additive.2, 47 Nanosilica displays a distinct advantage to commonly used accelerators48 because it decreases the porosity and increases the mechanical strength of set cement49 by up to 35%. The surface area-to-volume ratio of nanosilica along with the C—S—H nucleation, growth, and seeding observed in cements laden with nanosilica makes nanosilica a valuable accelerator and fortifying nanomaterial in PC. The C—S—H formation is accelerated, in part, due to the acceleration of the pozzolan reaction of hydrated lime (Ca(OH)₂) and SiO₂.50 For these properties, nanosilica finds potential applications in a number of different oil and gas well cementing scenarios including the cementing of lower temperature zones within a well. Cement close to the surface of wells in deep-water oil wells can be required to be set at low temperatures from 10 to 15 °C.

Nanosilica is also known to help with gas migration issues. Gas migration can occur in cements after the cements have been placed in the well and the hydration reactions in the cements render weak gel strength. The gel strength development results in the loss of the hydrostatic head provided by the cement slurry density on the surrounding rock formation. When this occurs, the cement becomes susceptible to the pore pressures from the formation which can cause channeling in the cement before the cement builds enough mechanical strength to resist the influx of fluid/gas from the formation. Nanosilica and C—S—H nuclei have been shown to reduce the risk of gas migration by shortening the time (transition time) between when the cement is a weak gel to when it is a strong set structural material.2, 47, 48, 50, 51

There are many different sizes and shapes of nanosilica that can be synthesized or purchased commercially. The size and shape of the materials can have a major effect on the influence of the material of cement hydration. Figure 6 shows how different shapes and sizes of nanosilica can influence acceleration of cement setting. The nanosilica tested imparts different setting kinetics on the cement where smaller the silica particle, the greater the effect on hydration and hence, the shorter WOC time. About 5 nm nanosilica displays the fastest setting with cigar-shaped and string-of-pearl-shaped nanosilica close behind. The larger the size of the spherical nanosilica, the slower the setting of the cement. The hydration of cement with nanosilica is believed to follow a C—S—H seeding mechanism. The reaction of water with the anhydrous tricalcium silicate and dicalcium silicate in cement is promoted and accelerated by the presence of nanosilica seeds in the cement to grow in larger quantities per unit time due to the high surface activity of the seeding nanoparticles.

Other promising new materials which display the ability to accelerate the hydration of cement and porosity/permeability reduction52 of set cement are the so-called C—S—H nanofoils. These promising new materials are made as stabilized complexes with polycarboxylated ethers (PCEs) (Figure 7). PCEs are known as superplasticizers in the concrete industry and have remarkable properties on their own for their ability to dramatically reduce the viscosity (disperse) of cement slurries. Nanofoil-PCE nanocomposites are prepared by the coprecipitation of sodium silicate and calcium nitrate in the presence of a PCE. Larger PCE concentrations are associated with smaller sizes of amorphous/semicrystalline C—S—H nanofoils.53

C—S—H nanofoils of 50–60 nm serve as effective nuclei for the hydration acceleration in cement.54 Examination of the time dependence on the compressive strength of PCs blended with fly ash indicates rapid early strength as measured through isothermal calorimetry of different concentrations of C—S—H nanofoils, showing excellent cement acceleration characteristics (Figure 8). It has been shown that the nanofoils not only accelerate the hydration of tricalcium and dicalcium silicates in cement but also accelerate the pozzolanic reaction between fly ash and Portlandite.53

3.3 Mechanical Strength and Nanomaterials

Mechanical shocks such as those taking place during perforations and hydraulic fracturing can impart undesired damage to cements in wells.55 The thermal environment of the cement will often be variable during production cycles, leading to the differential thermal expansion and compression of the casing onto the cement. This is a well-known problem in the industry and also leads to the development of fractures in the cement sheath. Breaches in the cement used in well construction can lead to the migration of hydrocarbons and water to annular spaces where they can mix and build up pressure. As hot reservoir fluids are produced, these trapped annular fluids will expand and often burst or crush the casing, leading to catastrophic damage. Consequently, when these kinds of pressure buildups occur and are detected, the well is often shut in if remedial treatments of the well fail. At best, failures of these kinds lead to losses in unrealized revenue. However, loss of life is also a consequence of operational failures of this kind, as encountered in the Deepwater Horizon incident.56 For these and other operational reasons, the mechanical properties of the set cement are targeted to have the highest possible tensile strength and the lowest possible Young's modulus. Nanoparticles have been shown to provide tensile strength enhancement ranging from 15%21 to 40%.7

In addition to the enhancements observed with nanosilicas, carbon nanotubes, due to their high aspect ratios, show some propensity for mechanical reinforcement of cement. However, almost all of the research reported to date with carbon nanotubes in cements has a requirement in the procedure to sonicate the nanomaterials for an extended period prior to mixing with the cement. If nanotubes are added to cement-mixed water without sonication, the resultant set cement material can actually suffer from reduced strength.47 This imposes a clear limitation of the procedure and use of the material due to scale-up issues encountered when handling the quantities of materials required for field deployments. The low concentrations of nanotubes required to show enhancement, however, are encouraging on economic grounds. Recently, carbon nanotubes have been grown from the surface of the cement clinker through a chemical vapor deposition (CVD) process. This method precludes the need for sonication as the nanotubes are already prepositioned on the cement grains prior to adding water. The resulting set cements utilizing this modified clinker have shown enhancements of 15% in tensile strength.21

Nanosilica is believed to contribute to increased strength and permeability reduction through the chemical reaction between SiO₂ and Ca(OH)₂ dissolved in water from the cement phases as well as the packing factor improvement due to the small size of the silicas.57 Nanosilica has been observed to produce a more dense and compact cement matrix than other silicas. The capillary porosity, which is defined as the total pore space occupied by water, has been observed to be reduced over time by over 200% in cements containing nanosilica compared with plain cements and cements containing fumed silica.58 Nanoindentation studies of PCs cured under simulated wellbore conditions (80 °C, 10 MPa) have revealed stiffer, higher-density C—S—H pastes, determined by ²⁹Si NMR to have a greater degree of silicate polymerization compared with samples without nanosilica.59 Long-term (28 days) NMR studies of ordinary PC pastes inclusive of nanosilica cured under ambient conditions exhibit longer silicate polymer chains than samples in the absence of nanosilica.60 Nanosilica has the effect of increasing the bulk compressive strength of the set cements.2

At temperatures above 150 °C, the strength of cement can decrease dramatically (strength retrogression), due to the dynamic conversion of the amorphous C—S—H into the higher-density crystalline product which is α-dicalcium silicate hydrate.61 This problem with strength retrogression is, in part, overcome through the addition of crystalline silica. Usually, sand is added to cement at a concentration of 35 % by weight of cement (bwoc) to improve its strength.62 Research has shown that nanosilica can be added to further strengthen the cement at high temperatures. For example, upon the addition of 4% bwoc of nanosilica to a standard 35% bwoc sand-containing cement, the compressive strength of the set cement has been found to increase by 25% compared with cement without the nanosilica.22

Research teams have also looked at using nanosilica to counter corrosion, which is a major issue for cements. Cements can suffer from exposure to formations which produce carbon dioxide, H₂S, or other corrosive gases. Carbon dioxide can corrode cement by converting portlandite into calcium carbonate. If the cement is exposed to water, the calcium carbonate can dissolve and diffuse out of the cement to render increased porosity into the cement and reduced mechanical strength. The calcium leaching rate by carbon dioxide invasion can be dramatically reduced with nanosilica. This is because the nanosilica reduces the porosity of the cement, transforms portlandite into the C—S—H gel through a pozzolanic reaction, and modifies the internal structure of the C—S—H gel, increasing the average chain length of the silicate chains.63

3.4 Sensors in Cement

In addition to the use of nanomaterials to overcome durability and sustainability issues pertaining to oil well cementing, nanomaterials are also being sought for use as sensors. Conductive nanofibers have been shown to not only enhance the durability and downhole suitability of aluminosilicate cements, but they also increase the piezoresistive response of cement.64 Additive materials in cements, which enhance the piezoresponsivities in cements, offer the possibility of enhanced downhole sensing capabilities. The structural health of the cement inside an oil well could potentially be monitored remotely and in real time through this technology. Figure 9 illustrates how permanent sensors may be located on the outside of casing within an oil or gas well.

While there remain obstacles to the realization of this vision, there is much research and development effort in producing sensors that can report in real time the conditions throughout the well. Downhole energy-storage devices, such as supercapacitors, are also being investigated to be integrated to produce autonomous sensing capabilities.4 Cements can be made intrinsically sensing capable of external load through the addition of Fe₂O₃, carbon fibers, carbon black, carbon nanotubes, and carbon nanofibers to the cement prior to setting.65 Recent work66 suggests the feasibility of predicting the tensile stress on a cement containing 0.5% CNTs with separate algorithms for elastic response in cement as compared with strain-hardening and strain-softening responses observed after the material undergoes plastic deformation. Much of the research in this field has been devoted to construction cements and concrete but oil well cements have also gained some attention.67

4.1 Reservoir Sensing

Today, the industry relies on many well-monitoring methods to bring an understanding about how the reservoir is going to behave while producing petroleum fluids in both short and long terms. These methods include gathering of production data, near well-bore logging, and sampling of reservoir rock while drilling and reservoir simulation.68 To produce hydrocarbons from reservoirs most effectively, it is highly beneficial to increase the understanding of the reservoir architecture including reservoir flow paths, heterogeneities, and unswept areas of the reservoir. Surveys from these tests can lead to greater yields from extracting the amount of oil in place where a change in a few percentage points can correspond to enormous revenues. They are a powerful way of maximizing the yields from improved oil recovery (IOR) and EOR techniques.

The use of interwell reservoir tracers involves setting up a flow field in the subsurface between injection and extraction wells where the reservoir is to be mapped in the interwell zone. Tracers are introduced in the injection wells, with subsequent measurements of the tracer concentrations in the extraction wells. Existing tracer techniques include solvents (i.e., ethyl acetate),69 perfluorocarbon gases, and flourescent tracers (i.e., fluorobenzoic acids).70 Toxicity and environmental concerns limit the application of many of these chemicals. Furthermore, existing fluorescent chemical tracers display low sensitivities (often measuring to a sensitivity limit of hundreds of ppms), often due to fluorescence quenching and a fluorescence background from organic residues in crude oil.71

Figure 10 shows the use of tracers in an interwell scenario. In this illustration, two tracers are injected into two separate injector wells at two different locations within a reservoir. The tracers are collected at the production wells where the concentrations and time of travel through the reservoir can be determined. Tracer A and Tracer B can represent two different barcodes. As described in the following section, barcoded nanoparticle tracers can be differentiated as a difference in fluorescence signature,71 Raman signal,72 mass spectrum,73 or other chemical or physical characteristics of the tracer.

4.1.1 Nanoparticle Sensors for Reservoir Mapping

One of the ultimate goals of using these nanoparticles as reservoir tracers is to provide in-depth data about petroleum reservoirs. A long-term goal for nanoparticle reservoir tracers is that during their journey from the water injection well to an oil producer, the particles could provide reservoir sensing whereby they may record temperature, pressure, salinity, or any other important reservoir rock/fluid properties. One way to retrieve the measured data from the particles is the recovery of the particles at the producing wells. In addition, the nanoparticles can be used as vehicles for transporting specific chemicals to the reservoir such as wettability alteration chemicals, scale inhibitors, and water control agents. Despite the fact that this vision is ambitious, the literature has reported various applications toward making it possible.

The first oilfield-scale demonstration of the use of nanoparticles as sensors for oilfield reservoirs was reported in 2011.17 The particles were luminescent carbon dots with a size ranging from 5 to 10 nm.74 To measure the particles concentration, their response to light was utilized as they are fluorescent. Thus, their concentration was detected with an accuracy of 0.1 ppm using a fluorometer. Several experimental tests were used to assess the performance of the particles. These included visual tests to investigate the stability of the particles in oilfield brines, zeta potential measurements, and injection through porous reservoir cores (rocks) to investigate the mobility of the particles and their recovery potential. The authors reported that 96% of the particles were recovered after injection through a carbonate reservoir rock. After these promising lab tests, a field test was reported. The particles were injected into an oil-producing well at a concentration of 130 ppm. After the injection, the well was shut in for 24 h and afterward, the well was put on production where samples were collected and transported to the lab. The field results gave a recovery factor of 82%.17

Many fluorescent tracers that were tested thus far suffer from the drawback that the fluorescent signal can be obscured in the presence of polyaromatic hydrocarbon fluorescence in crude oil.75 For this reason, nanoparticle tracers have been in development which display a persistent luminescent signature that outlives the fluorescence of species from the reservoir. About 50–100 nm LGO:Cr nanoparticles show some promise as tracers of this type. They emit strong photoluminescence at 716 nm under ultraviolet (UV) excitation (254 nm). The fluorescence signal from the excitation lasts for an extensive time (of the order of minutes) and can be used to detect 1 ppb concentration of the nanoparticles.71 These materials are particularly interesting for the ability to detect the persistent luminescent signal with a portable device equipped with a charge-coupled device (CCD) camera.

Plasmonic nanostructures have been shown to display strong surface-enhanced Raman scattering (SERS) intensities,76 which make them excellent candidates in many different sensor applications.72 Silica-encapsulated silver nanoparticles have been shown to exhibit 10 ppb-level sensitivities to the adsorption of fluorescein and rhodamine dyes with Raman spectroscopy.72 This allows one to “bar tag” or label nanoparticles with dyes so that nanoparticles injected into the reservoir either at different times or at different locations can have a distinct spectroscopic signature, which assists reservoir engineers in detailing reservoir maps. Figure 11 shows the synthesis of Fe₃O₄/Ag@SiO₂/Ag and Fe₃O₄/Ag@SiO₂ nanoparticles. The nanocomposite samples are multifunctional and designed for low-concentration detectability. The silver nanoparticle component in these nanocomposites gives the SERS signal for detection of the particle, whereas the iron oxide nanoparticle component is superparamagnetic and allows the particles to be concentrated with magnetic fields for higher detectability.77

The use of nanoparticles as reservoir tracers is an exciting area of development toward the eventual possibility of bringing recordable stimulus–responsive nanoparticles into use for reservoir mapping. An appealing aspect of these technologies is that due to the potential for high revenue in oil recovery from reservoir mapping, there are fewer cost constraints in the design of nanoparticles as tracers than in many other applications of nanomaterials in upstream oil and gas. But there are many challenges that lie ahead in the development of these technologies. One such challenge is maintaining colloidal stability of the particles under the high saline environments that the particles are required to endure as well as the challenging temperature and pressure environments of the reservoir.78 Other challenges remain in transport through porous media at a high temperature and pressure.

4.2 Enhanced Oil Recovery

It has been estimated that only about one-third of the original oil in place (OOIP) in reservoirs is actually recovered. In heavy oil reservoirs, primary and secondary production methods at their economic limit leave behind 80–95% of OOIP.79 EOR methods offer the possibility of improving the production yield of wells through a variety of techniques including chemical injection, gas injection, thermal oil recovery (such as steam flooding),80 and microbial EOR.81 In all of these methods, the injected fluid travels from one or more injection wells through the reservoir to displace hydrocarbons toward an oil production well. Figure 12 shows a conceptual depiction of flooding as well as the nanotechnology applications for EOR purposes.

Various fluids, in chemical EOR, can be used for injection and include water alone, viscous polymer/water solutions,82 polymer/surfactant,83 alkali–surfactant–polymer (ASP) flooding solutions,84 and CO₂ in water foams.85 In the following paragraphs, we shed light on the use of nanoparticles to help improve the existing chemical EOR technologies. After discussion of chemical EOR, emerging technologies utilizing nanocatalysts26 for use in thermal EOR, in steam-assisted gravity drainage (SAGD), are discussed. These nanocatalysts are used to enhance recovery by upgrading heavy oils and bitumens to lighter oils.

4.2.3 Stabilization of Foams

Gas injection is a widely used method for enhancing oil recovery. Gases used for injection can vary from nitrogen, air, methane, natural gas, or CO₂.95 CO₂ injection accounts for about 38 % of EOR in the United States.81 CO₂ flooding is often the preferred method for oil recovery for light oil with viscosities less than 10  cP and at reservoir depths greater than 900 m. The depth must be high so that the reservoir pressure exceeds the minimum CO₂/oil miscibility pressure. When heavier oils are being pursued, the use of CO₂ alone as an EOR fluid, the low viscosity, and the resulting high mobility of the gas compared with oil (heavy oil can present viscosities as high as 10 000 cP) result in a phenomenon known as viscous fingering, leading to poor sweep efficiencies.96 The mobility of water is directly related to the viscosity of the fluids, and this must be equal to or lower than the oil to afford recovery/displacement of oil. To improve the viscosity of CO₂, it can be foamed with water. The longer the viscosity stays high, the better the sweep efficiency. Thus, it is important to maintain foam viscosity for the longest period of time possible. As is determined to be the case in surfactant EOR, nanosilicas aid in reducing surfactant adsorption in foam EOR applications. Results of a study of nanosilica in sodium dodecyl sulfate (SDS) revealed a 75% reduction in surfactant adsorption onto kaolinite.97

The stability of foams is dramatically impacted by the presence of oil, salinity, temperature, and pressure. About 15% additional OOIP was recovered with the use of methyl-functionalized 12 nm nanosilica to stabilize the water–CO₂ foam.98 CO₂–surfactant foams that are surface modified with nanoparticles (such as nanosilica) display enhanced stability over surfactant-stabilized foams. Similar to the nonfoamed surfactant EOR, nanoparticles in CO₂-foamed EOR display a lower propensity for adsorption onto the formation and have been shown to increase CO₂ foam stability when compared with cases where just surfactants are used. Figure 13 shows the foam half life of SDS as compared with SDS–nanosilica. The nanosilica used in these tests was of 20 nm diameter with a partially hydrophobic surface (contact angle with water was 122.2°). From the oil recovery efficiencies from sandpack recovery testing (Figure 13a), the optimal synergetic effect between nanosilica occurs when the SDS/SiO₂ ratio is at 0.17 at 1.5 wt% nanosilica. The nanosilica surfactant outperforms SDS foam under high temperatures and pressures. Visual flooding experiments (Figure 13b) show that the nanosilica-stabilized foams have a superior stability at elevated temperatures, whereas the SDS surfactant-stabilized foam shows coarsening/coalescing of the foam.99

Similar surfactant-nanoparticle synergies in foam stabilization for EOR have been observed with hydrophilic nanosilica (40 nm diameter, contact angle with water = 39°) with the cationic surfactant cetyltrimethylammonium bromide (CTAB). It was found that increasing the ratio of CTAB/nanosilica (with an optimum ratio of 0.033) would increase foam stability, whereas CTAB produced a monolayer on the nanosilica rendering it more hydrophobic. Optimum contact angles for foam stability are between 60° and 90°. As the CTAB concentration was increased further relative to nanosilica, the foam stabilization effect diminished.100

4.3 Application of Nanotechnology in the Production Domain

4.3.1 Nanoparticles and Hydraulic Fracturing

Several domains in the production sector have benefited from the use of nanotechnology. These include the design of hydraulic fracturing fluids, water control chemicals, fine migration prevention, and acidizing. The use of nanoparticles has been highlighted in the development of fracturing fluids where a great deal of literature exists on this topic.3, 103 Figure 14 shows nanoparticles which have been used and show a promise in these upstream applications. In a typical fracturing operation, a fracturing fluid is used to transmit hydraulic power in the form of dynamic stress on the rock downhole to break it down and create fractures. Once the fracture is created, proppants/sand particles are used to keep it open. To transport the particles into the fracture, the viscosity of the fracturing fluid is increased by adding crosslinkers. For hydraulic fracturing, ZnO nanoparticles have been proven for use with viscoelastic surfactant (VES)-based fluids to improve their leak-off properties. Without the addition of ZnO, these fluids were limited in applications of a 200 mD maximum permeability.23 Performance enhancements through the use of polymer-based fracturing fluids can be achieved with nanosilica. Guar-based polymers,104 polyacrylamide-based polymers,105 and guar polymers under high salinity conditions show better performance when nanosilica was incorporated in these fluids. Recent works23, 106 report the use of nanoparticles in packs during hydraulic fracturing treatments. Through van der Waals forces, the particles attach themselves to the proppant surfaces. When the reservoir-generated fines come into contact with the proppant-treated surface, they will be attracted and therefore, their propagation into the wellbore and perforations will be prevented.

4.3.3 Nanoparticles and Acidizing

After hydraulic fracturing or in place of hydraulic fracturing, acids are sometimes used as stimulation fluids for well production enhancement. In these acidizing processes, the permeability of the production zone is increased through the etching of rock formation and boring of wormholes through the rocks using acids. On the acidizing application for well-stimulation purposes, hydrochloric acid (HCl) is used as a stimulation fluid to dissolve carbonate (CaCO₃) rocks. One of the challenges of acidizing is that the acids may be too reactive with rock (especially carbonate rock formations) such that they dissolve the face of the rock without fracturing or unevenly etch wormholes into the rock. To overcome these issues, the industry has developed different retarder technologies to slow the acid's reactivity. One way to retard the dissolution reaction, between HCl and the reservoir rock, is to emulsify the acid in diesel. With time and temperature, the emulsion breaks down releasing the acid, allowing it to come in contact with the rock. The emulsion is formed by the use of a surfactant that acts as a stabilizer at the interface between the aqueous phase and the hydrocarbon phase. Standard surfactant-stabilized emulsions have limited temperature stability and therefore, are of value to enhance the thermal tolerance of stable emulsions. In this way, the acids can take more time to break and stimulate the reservoir to greater depths. The Pickering emulsion concept has been recently introduced for oil and gas stimulation applications. In this method, the nanoparticles can be used as a physical barrier between the acid and the diesel. Extensive lab evaluation has revealed that use of nanoparticle additives greatly enhances the stability of emulsified acids. Bulk thermal stability tests indicate that emulsion stability can be improved upon with the use of nanoparticles. Samples of acids emulsified with hydrophobic silica nanoparticles show enhanced retardation for emulsion breakage at temperatures up to 150 °C.5, 112

Microencapsulation of HCl with Pickering emulsions of 14 nm size hydrophobic nanosilica (from surface modification with polydimethylsiloxane) has been shown to render stable dry (acid-in-air) powders of HCl with excellent thermal stabilities (Figure 15). These acid-in-air emulsions are preferred for water-sensitive shales where water-reactive clays can limit the efficacy of water-based fluids. The release of acid from these powders is triggered by surfactants so the timing of the acid release can be modified to a desired rate. Testing of this technology has demonstrated that enhanced fracturing and uneven etching are achieved with this chemistry.

4.3.4 Scale Inhibition with Nanoparticles

The formation of scale deposits in well production tubing is a long-standing issue that the oil and gas industry faces. Scale inhibitors are used to prevent scale formation. Adsorption of the inhibitor on the reservoir rock is used as a strategy of scale inhibition. This is achieved by squeezing the scale inhibitor inside the reservoir rocks in the near wellbore area where adsorption of the inhibitor takes place. When the well is switched back to production, the inhibitor (phosphonate) is slowly released with the produced fluid. There are concerns with this approach such as lifespan of the treatment. To address these concerns and enable a slower release, inhibitor-precipitation methods have been put into application, a method where an inhibitor may be precipitated inside the rock as a metal salt. The precipitating phosphonate/calcium complex is a result of adjusting the salt concentration and pH of the injected solution. Limitations with the precipitation approach include formation damage and blockage of pores in the rock by the precipitation of solid materials.

To further increase the lifespan of scale inhibitor treatments and address concerns related to the blockage of pores with precipitates, a new nanotechnology-based concept was lab tested recently.113 Zinc and calcium metals were used to formulate metal-phosphonate nanoparticles that are synthesized with a size from 50 to 200 nm. Carbonate and sandstone porous media were treated with these metal-phosphonate nanoparticles to investigate their propagation in porous media and test their retention/release behavior. Several experimental techniques were used to investigate the performance difference between the nanoparticles of calcium/methylene phosphate (diethylenetriamine-pentamethylene phosphonic acid [DTPMP]) under different conditions. The authors compared the pore volume (PV) to breakthrough which is a measure of how long it took the inhibitor to be released from the porous media. In such an experiment, the concentration of the metal is monitored as a function of PV produced. Once the concentration drops below a minimum threshold value (around 1 mg L⁻¹), the corresponding PV is recorded as the breakthrough PV (Figure 16). Clearly, better control over the inhibitor release is achieved by use of nanoparticles in carbonate rocks when compared with sandstone cores.113

In summary, the production technology domain has made use of nanotechnology in several applications that showed promising results. Nanoparticle-based fracturing fluids were found to outperform other non-nanoparticle-based fluids, and this was verified in field applications of VES-based fluids combined with nanoparticles.23 Pickering emulsions represent another example where nanotechnology provided an opportunity to design better acidizing fluids. Some of the limitations in the field deployment and commercialization of these nanomaterials in production are based in cost. As the nanoparticles demonstrating performance advantages over conventional additive technologies are brought into larger-scale production, driving down costs, it is anticipated that commercialization of many of these technologies will follow.