The effects of adding iron oxide NPs on the rheological and filtration properties of aqueous bentonite suspensions have been studied by several researchers. This paper presents an investigation into the effect of catalytic nanoparticles on the efficiency of recovery from continuous steam injection. A number of ongoing industry research projects are developing nanoparticles that work at the reservoir level and for fluid treatment. Though they may be a few years away from finalization, these efforts highlight nanotechnology’s increasingly sophisticated and growing application scope. 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.
A horizontal-steam-injection pilot project has been under way for the last 4 years in the Kern River heavy-oil field in the southern San Joaquin Valley of California. This paper presents an investigation into the effect of catalytic nanoparticles on the efficiency of recovery from continuous steam injection. The operator has initiated a cyclic-steam-stimulation project in the Opal A diatomite of the Sisquoc formation on the Careaga lease in the Orcutt oil field in Santa Barbara County, California.
Since the 1980s, many technical works have focused on improving the ability to detect hydrocarbons inside the riser and safely remove them from the system. This trend gained extra momentum with the advent of systems such as riser-gas handlers and managed-pressure drilling. This paper will show how stick/slip vibration distributions can be used to guide drillstring and parameter redesign to mitigate stick/slip in the next well. Organophilic clays mixed in oil-based drilling fluids (OBDFs) do not exhibit the same viscosity or suspension characteristics as they do in water-based drilling fluids. A new mineral-oil-based drilling fluid (MOBDF) was created by replacing the conventional organophilic clay with a novel polymer.
The novel nanomaterial composition described in this paper has been designed to treat moderate to severe losses. The nanomaterial composition comprises an environmentally friendly nanoparticle based dispersion and a chemical activator. The design is based on a delayed activation chemistry to gel up a nanoparticle based dispersion.
Three different types of nanoparticles were used in the study to develop the novel loss circulation material. Two different types of negatively charged nanoparticle based dispersion and one positively charged nanoparticle based dispersion were used in the study. An inorganic activator has been used for the study. The effect of this inorganic activator on the gelation properties of the nanoparticle based dispersion was investigated. The gelling times were evaluated at different temperatures up to 300°F. The effect of activator concentration on the gelling time of the new composition has also been studied. The effectiveness of the newly developed composition as a loss circulation treatment was also evaluated by performing permeability plugging tests to test the plugging capacity of this novel system.
The novel nanomaterial composition is designed so as to have a controllable gelation time under a variety of downhole conditions to allow accurate placement of the treatment fluid inside the wellbore without premature setting of the fluid. It was shown that the gelation time of the treatment composition could be controlled by adjusting the concentration of the activator. The system is designed so as to give a predictable and controllable pumping time, ranging from a few minutes to several hours at over a wide range of temperatures. This is an important advantage as it allows the loss circulation composition to remain pumpable for sufficient time for placement and develops the network structure that leads to gelation, over a predictable period of time. The set gel, which appears as a crystalline solid, could remain homogenous and stay in place thereby preventing loss circulation.
Junwen, Wu (Sinopec Research Institute of Petroleum Exploration and Development) | Wenfeng, Jia (Sinopec Research Institute of Petroleum Engineering) | Rusheng, Zhang (Sinopec Research Institute of Petroleum Exploration and Development) | Xueqi, Cen (Sinopec Research Institute of Petroleum Exploration and Development) | Haibo, Wang (Sinopec Research Institute of Petroleum Exploration and Development) | Jun, Niu (Sinopec Research Institute of Petroleum Exploration and Development)
The high efficient foam unloading agent was developed to solve the problem of unloading of liquid loading gas well with high gas temperature, salinity and high concentration of H2S gas and gas condensate. The Gemini anionic surfactant with special comb structure was synthesized as foaming agent molecule, the modified nanoparticles with certain size and degree of hydrophobicity was adopted as solid foam stabilizer, and the fluorocarbon surfactant was designed and synthesised as gas condensate resistance components. The indoor experiment results show that the foam unloading agent showed good foaming and foam stabilizing ability when the temperature is as high as 150°C, salinity is up to 250000 ppm and H2S concentration up to 2000 ppm. Besides, the foam unloading agent present good liquid carrying ability when the volume fraction of gas condensate is as high as 50%. The field test of this foam unloading agent in Longfengshan north 201-XY well shows that, the average gas production increased from 7256 m3/day to 11329 m3/day, increased by 56%, the average differential pressure between tubing and casing dropped from 2.66 MPa to 2.38 MPa, fell by 10.5%, both liquid yield and gas production are obvious, which prove that the foam unloading agent can meet the demand of drainage gas recovery for high content gas condensate gas field.
It is well known within the industry that conventional drilling fluids can damage the well's producing zone. Damage mechanisms occur due to leakage of drilling fluid into the formation even after the formation of a filter cake. This filtrate contains entrained particulates that can enter the pore spaces of the rock and restrict flow through the pore throats resulting in reduced permeability during production. Cleaner drill-in fluids with low solids content have been developed for use when drilling through a producing zone in an attempt to mitigate the extent of damage caused by leak-off. These fluids should not only provide excellent fluid loss prevention, but also exhibit the rheological characteristics needed to perform the traditional functions of conventional fluids. Even though these fluids reduce the amount of particulates entering the formation by containing less solids, the filtrate that is still able to flow through the filter cake can be equally as damaging. Reduction of filtrate volumes can be further achieved by introducing nanoparticles to bridge across the nano-sized gaps within the filter cake. This research focuses on the application of polyelectrolyte complex nanoparticles (PECNP) as a fluid loss additive to further enhance the filter cake filtration properties of a general drill-in fluid. A baseline fluid is formulated consisting of a sodium chloride brine, biopolymers for rheology and fluid loss purposes, and calcium carbonate as a density and bridging agent. The ratio and pH of polyelectrolytes were optimized in order to create stable PECNPs for this system. Different dilutions of PECNPs were added and tested in a static fluid loss setup, where filtrate volumes were compared to determine the best system of 1/8th diluted nanoparticles. The chosen system was then taken to be tested in the dynamic fluid loss setup "Quasimodo" where fluid loss volumes were successfully reduced and wall building coefficients lowered. Analysis of cleanup curves after testing revealed that the PECNP drill-in fluid was less damaging to the core permeability than when the baseline fluid was used.
The benefits of a nanoparticle-weighted fluid are numerous, allowing the possibility of high-density drilling fluids, a true alternative to expensive heavy brines, barite-weighted reservoir drill-in fluids and the virtual elimination of barite sag. By using a branched carboxylic acid, rather than a linear molecule as a crystal growth inhibitor during precipitation, true nano-scale dispersions have been achieved that are stable in water, with no detectable agglomeration and that are self-dispersing after drying. This paper proposes that greater steric hindrance and smaller particle sizes are achieved by utilising branched, or chair-like carboxylic acids, rather than the long-chain molecules more commonly used. The use of FTIR, XRD, DLS and SSNRM have been combined to demonstrate that inhibitor concentration is the dominant effect in preventing crystal growth but does not account for particle growth retardation alone.
Spherical nanoparticles with a dispersed ZAvg of 16nm and low contact areas have been created. They produce dispersions with a density of 2.27g/cm3. These dispersions display no detectable ‘sag’ after 428 days in suspension suggesting that colloidal stabilisation has been achieved. This paper also demonstrates that further decreases in particle diameter are possible through a combination of mechanical shear during precipitation and pH modification after precipitation has ceased. An optimum pH post-precipitation of 10.4 is close to that targeted by many water-based reservoir drill-in fluids, further highlighting the possibility of surfactant-inhibited barium sulphate nanoparticles as a density agent for drilling fluids. Using pH to modify the PSD of the nanoparticle dispersions strongly suggests that the dispersions can be tuned to one suitable for the intended operation. The growth inhibitors used during precipitation are low-cost and non-toxic and enable the dry particles to disperse to comparable PSDs after drying to their precipitated values. The technology allows the creation of a high-density brine replacement fluid, presenting a significant cost saving over an alternative such as caesium formate in some applications
Previous research on barium sulphate nanoparticles [
Zhao, Tianhong (Southwest Petroleum University) | Chen, Ying (Southwest Petroleum University) | Pu, Wanfen (Southwest Petroleum University) | Wei, Bing (Southwest Petroleum University) | He, Yi (Southwest Petroleum University) | Zhang, Yiwen (Southwest Petroleum University)
Nanofluid flooding injection technique whereby nanomaterial or nanocomposite fluids for enhanced oil recovery (EOR) have garnered attention. Although a variety of nanomaterials have been used as EOR agents, there are still some defects such as toxicity, high cost and low-efficiency displacement, which restricted the further application of these nanoparticles. Considering these problems mentioned above, it is necessary to search for another nanomaterial which is inexpensive, environmentally friendly and results in high efficiency displacement.
In this work, a natural aluminosilicate nanomaterial halloysite nanotubes (HNTs) was focused. As a new kind of nanomaterial, the effectiveness of halloysite nanotubes (HNTs) in enhancing oil recovery has not been reported yet and it is still in its infancy. The use of pristine halloysite nanotube is at risk of blocking the rock pore channel due to the intrinsic drawback of aggregation, which may be the reason. To prolong the suspension time of fluids during seeping into the small pores of low permeable reservoirs, we have proposed the HNTs/SiO2 nanocomposites. The effect of HNTs/SiO2 nanocomposites-based nanofluids on wettability alteration and oil displacement efficiency was experimentally studied. The HNTs/SiO2 nanocomposites have been prepared by sol-gel method and characterized with X-ray (XRD), Transmission Electron Microscopy (TEM) and Thermal Gravimetric Analysis (TGA). The effect of the chemical modification on the suspension stability was investigated by measuring Zeta potential and dynamic laser scattering. Results show that the HNTs/SiO2 nanofluid could significantly change the water wettability from oil-wet to water-wet condition and enhance oil production. The optimal concentration of HNTs/SiO2 was 500 ppm, which corresponded to the highest ultimate oil recovery of 39%.
Drilling fluid design for shale plays aims to prevent wellbore instability problems associated with fluid invasion, shale swelling, and cuttings dispersion. Although oil-based mud (OBM) can be used to achieve these goals, environmental and economic concerns limit its application. This research evaluates the potential of using silica nanoparticles (SiO2-NPs) and graphene nanoplatelets (GNPs) as drilling fluid additives in a single formulation to improve shale inhibition and long-term stability of water-based mud (WBM) against temperature effects. The design of the nanoparticle water-based mud (NP-WBM) followed a customized approach that selects the additives according to the characteristics of the reservoir. Characterization of Woodford shale was completed with X-ray diffraction (XRD), cation exchange capacity (CEC), and scanning electron microscopy (SEM). The aqueous stability test and zeta-potential measurements were used to assess the stability of the NPs. NP-WBM characterization included the analysis of the rheological properties measured with a rotational viscometer and the evaluation of the filtration trends at low-temperature/low-pressure (LTLP) and high-temperature/high-pressure (HTHP) conditions. Additionally, dynamic aging was performed at temperatures up to 250°F for thermal stability evaluation. Finally, chemical-interaction tests such as cutting dispersion and bulk swelling helped to analyze the effect of introducing NPs on the inhibition capabilities of the WBM. Conventional KCl/PHPA fluid was used for comparison purposes. The results of this investigation revealed that SiO2-NPs and GNPs acted synergistically with other additives to improve the filtration characteristics of the WBM with only minor effects on the rheological properties. NPs exhibited a high colloidal stability with ζ-potential values below-30 mV, which warrants their dispersion within the WBM at an optimal concentration of 0.75 wt.%. The high thermal conductivity of NPs played a key role in promoting an almost flat trend in the cumulative filtrate for the NP-WBM at aged conditions, whereas KCl/PHPA suffered a drastic increase. Also, NP-WBM preserved 43.97% of its initial cutting carrying capacity, while KCl/PHPA experienced a severe reduction of 95.24% at extreme conditions (250°F). Despite the high illite content of the Woodford shale, the NP-WBM exhibited superior inhibition properties that reduced cutting erosion and swelling effect by 24.48% and 35.24%, respectively, compared to the KCl/PHPA fluid. Overall, this investigation supports the potential use of nanomaterials to enhance the inhibition capabilities and the long-term stability of WBM for unconventional shales, presenting an eco-friendly alternative for harsher environments.
Polymeric scale inhibitors used for scale squeeze treatments to control downhole inorganic scale don't perform well when pumped into the reservoir due to the poor adsorption properties on the rock surface. However polymeric inhibitors are more temperature stable than phosphonates and have higher tolerance to elevated cation compositions in the water. Therefore, a new chemistry composed of metal nanoparticles coupled with a polymeric scale inhibitor was developed to improve the squeeze life.
The use of nanoparticles in the oilfield has increased in recent years; this development shows how nanoparticles can be used to increased surface area and retention of scale inhibitor in the reservoir. Metal nanoparticles were selected because of their low environmental toxicity and low formation damage potential during injection and flowback.
A fast and efficient synthesis method was developed to create a novel chemistry that couples nanoparticles with polymeric inhibitors to produce a product that it was hoped would have excellent squeeze properties in multiple rock permeabilities and compositions.
Core flood experiments were conducted on intact core under onshore Permian conditions of temperature pressure and brine composition as well as conditions simulating an offshore conventional field (results will be reported separately). The experimental results will be presented to show the extended squeeze lifetime of the new product in comparison to a traditional polymeric scale inhibitor retained by adsorption and also will give insight into the mechanisms by which the nanoparticle/scale inhibitor enhances squeeze life, both by increased adsorption as well as prolonging release of scale inhibitor.
The product developed is able to significantly increase the squeeze life of polymeric scale inhibitors by up to 10x depending on the minimum inhibitor concentration required. The retention of the inhibitor into the rock is significantly increased, while the release is controlled at above minimum effective concentration for extended periods. The theoretic explanation for this is a metal-inhibitor bond, proprietary to the product that allows for continuous release of inhibitor into the solution, without release from the rock. Traditional squeeze returns have a Freundlich isotherm, this product also follows a similar return curve, however does not suffer from the high concentration release at the beginning of the treatment flowback.
These results show that nanoparticles can be used in the oilfield to enhance existing scale inhibitors as well as create new combination products that can improve performance. Use on nanoparticles in the oilfield is an evolving topic that has significant room to grow and expand into multiple areas of oilfield chemistry. This study showcases the application of nanoparticles to enhance performance of polymeric scale inhibitors for squeeze application while maintaining a cost effective product that is environmental responsible.