Although the application of nanoparticles in drilling fluid has been reported under static test by our research group, understanding inhibition formation of damage by filtration volume reduction in porous media under dynamic conditions is still a crucial issue. In this research, synthesised silica nanoparticles modified with acid treatment (Si11A) evaluated in previous results in the bentonite-free water-based drilling fluid (BFWBM) in static tests were analysed in the coreflooding test under dynamic and reservoir conditions. Si11A nanoparticles were evaluated by permeability return tests under reservoir conditions overburden, pore, and overbalance pressures, and temperatures of 3000 psi, 1700 psi, 1200 psi, and 87 °C, respectively. Coreflooding test with a concentration of 0.1 wt% Si11A nanoparticles based on our previous work showed a reduction in the filtration volume by 77%, decreasing the formation damage by 51% compared to the drilling fluid without nanoparticles. Also, the oil recovery obtained with the best design fluid using the Si11A nanoparticles was 10% higher than the baseline. Additionally, the effluents of crude oil obtained from permeability return test were evaluated at reservoir temperature using a rotational rheometer at shear rates varying between 1 and 100 s −1 , obtaining a reduction of the viscosity up to 28% during nine pore volume injected using the BFWBM with S11A nanoparticles. The role of the nanoparticles in the drilling fluid is the rapid deposition in the mudcake to enhance the properties, the subsequent filtration volume reduction, and the enhancement of the petrophysics properties may be described by dynamic filtration curves, effective oil permeability and relative permeability curves.
The study aims to evaluate the effect of size and surface acidity of synthesised silica (SiO 2 ) nanoparticles in a bentonite-free water-based drilling fluid (BFWBM) to minimise its impact on formation damage by filtration volume control and mudcake thickness reduction. Nanoparticles were synthesised through the sol-gel method, and the surfaces were modified through the incipient impregnation technique using acidic and basic treatments. The nanoparticles were characterised by dynamic light scattering (DLS), Fourier transforms infrared spectroscopy (FTIR) and zeta potential measurements. Drilling fluid properties in the presence and absence of nanoparticles were evaluated through the analysis of pH, density, solid content, rheology, and static filtration tests at high pressure and temperature. Drilling fluids were described as shearthinning fluids under the rheological model of Herschel-Bulkley. The smallest nanoparticles (Si11) contributed to the highest filtration and mudcake thickness reduction. Hence, these were modified to obtain a different surface charge. Silica nanoparticles modified with the acidic treatment (Si11A) in drilling fluids showed the highest reduction of the filtration volume and mud cake thickness with values of −22% and −65%, respectively. Also, the filtration volume appeared to be a function of the zeta potential of nanoparticles that were investigated, for the highest zeta potential value, SiA −48.66 mV @ pH 10, the filtration volume is lower. SiO 2 nanoparticles in a BFWBM reduce the filtration volume due to their nanometric size occupying empty spaces in the mudcake and promoting the repulsive forces avoiding the flocculation of the drilling fluid thanks to the anionic surface charge. This study provides a wider landscape about
Most wellbore stability problems occur while drilling shale intervals. Although the drilling industry invests large amounts of time and money each year to deal with the problem, the interaction between drilling fluids and shale is complex and not well understood. Generally speaking, fewer wellbore stability problems occur when drilling with invert emulsion drilling fluids (IEF) than with water-based drilling fluids (WBF). In this paper, the theory governing the interaction between shales and invert emulsion drilling fluids is briefly reviewed. A new testing device developed by the University of Oklahoma was used to study changes in rock strength of shale cores exposed to invert emulsions. Two shale samples, one from a deepwater environment and another from an onshore environment, were exposed to invert emulsions having varying chemical activity (water phase salinity) levels. The stresses required to fail the samples were directly measured under in-situ conditions. The results showed that under some conditions the invert emulsion strengthened the samples and under other conditions the shales were weakened. These results are interpreted using current osmotic pressure and membrane efficiency theory of invert emulsions. Using a set of in-situ drilling and wellbore stress conditions, traditional elastic wellbore stability modeling is used to predict changes in pore pressure at the wellbore wall as a function of changes in invert emulsion chemical activity. Porochemoelastic modeling is also performed to predict changes in shale pore pressure as a function of time. The modeling results are compared to the shale strength data obtained in the laboratory. Lastly rock strength measurements of shales exposed to IEF are compared to those exposed to WBF having the same chemical activity (water phase salinity) levels. The differences in performance are explained in terms of osmotic pressure and membrane efficiency theory. With the laboratory and computer modeling results, the drilling engineer can better appreciate the effect of invert emulsion interaction with shales, which can enable better planning of future wells, especially those having narrow safe drilling windows. Introduction Most of the formations drilled for oil and gas are clay-bearing shales, and problems in these formations account for the bulk of wellbore instability problems. When exposed to drilling fluids, formation shales can become unstable, a process that if left unchecked can lead to wellbore failure.
Problems with wellbore stability while drilling in shale have plagued the drilling industry for a long time. For good reason, the bulk of trouble-related problems while drilling have been in shales, and great expeditures in time and money are made each year dealing with the problem. However, shale interaction with drilling fluids in the drilling process remains a complex and often misunderstood area of study. By comparison, fewer wellbore stability problems occur while drilling with invert emulsion fluids (IEF) than when water-based drilling fluids are used. The theory of shale interaction with invert emulsions is briefly reviewed in this paper.Actual measurements of changes in shale strength of two shales have been recently made using a new test device from the University of Oklahoma. Two very different shales were studied: one from a deepwater environment and the other a more-competent shale cored in a land-drilling operation. These shales were exposed to invert emulsions having different water phase salinities, and the stresses required to cause sample failure were measured under in-situ conditions. The results showed use of invert emulsions under some conditions weakened the shales, while under other conditions, the shales were strengthened. These results were then interpreted using current osmotic pressure and membrane efficiency theory of invert emulsions.The results were compared to the elastic and porochemoelastic modeling using the rock mechanical properties determined in the laboratory testing. Using a set of drilling and wellbore in-situ stress conditions, traditional elastic wellbore stability modeling is used to predict the changes in tangential stress in the wellbore wall. Next, porochemoelastic modeling is used to predict changes in pore pressure as a function of time and of IEF water phase salinity (WPS). These results are then discussed in relation to the changes in shale strength seen in the laboratory.Knowing that there are significant differences in rock strengths of shales exposed to invert emulsions having varying water phase activity levels, the drilling engineer can more effectively plan future wells, especially those having narrow safe drilling windows.
The Serrette and Savonette gas fields offshore Trinidad will be developed through use of open hole gravel pack (OHGP) completions. This completion type was chosen as the preferred completion technique for sand control for these fields. Due to a wide range of expected fluids densities required, the fluids design considered both monovalent and divalent brine as the base fluid for water-based reservoir drill-in fluid (RDF), completion brine and gravel pack carrier fluid (GPCF). Low pore pressures in the field did not allow applying high drawdowns during backflow of the wells, therefore chemical breaker technology was recommended by the Operator to be included in the fluids package to assist with filter cake removal and wells clean-up. The large pore throats of the formation necessitated the use of a high concentration of coarse sized particles in the RDF for bridging which caused a considerable decrease in retained permeability and potentially plugging of gravel and screen from assurance laboratory testing. High overbalances used during drilling potentially would exascerbate any near wellbore damage from the use of water based fluids.Most of the commercially available filter cake breakers are compatible only with monovalent brines and the acid precursors in use could not guarantee the low corrosion requirements required, nor result in ideal rheological properties expected from the GPCF over time since Hydroxy-ethyl-cellulose (HEC) was selected as the viscosifier to transport and deposit the gravel.GPCF with incorporated breaker, composed of a novel chelant compatible with divalent brines and a buffer, was chosen as a solution for the Serrette project. The system was modified for successful use on the Savonette Field. Screening tests were performed by the supplier to obtain an optimized formulation that would satisfy GPCF requirements and logistics. The final formulations were tested and approved at the operator's fluids laboratory. Several wells have been completed using the procedure and products. All have achieved outstanding production rates. The flow initiation pressures measured during wells start-up were noted to be less than those historically seen in the field.The GPCF with incorporated breaker is believed to have assisted with filter cake removal and well clean-up and also contributed to the fact that the gas requirements from the project have been met. The paper will focus on the development of fluids package for successful implementation in the field to deliver the wells and planned gas production.
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