scholarly journals A polymer microsphere emulsion as a high-performance shale stabilizer for water-based drilling fluids

RSC Advances ◽  
2018 ◽  
Vol 8 (37) ◽  
pp. 20852-20861 ◽  
Author(s):  
Jian-gen Xu ◽  
Zhengsong Qiu ◽  
Xin Zhao ◽  
Tingbo Mou ◽  
Hanyi Zhong ◽  
...  
Keyword(s):  
High Performance ◽  
Drilling Fluids ◽  
Dual Roles ◽  
Polymer Microsphere ◽  
Water Based

A polymer microsphere emulsion (PME) was reported and it undertook the dual roles of physical plugging and shale hydration inhibition.

High performance-branched microgels as universal viscosifiers for water-based drilling fluids

2021 ◽  
Author(s):  
Sivaprakash Shanmugam ◽  
Georgesha Ross ◽  
Christelle Yimgnia Mbuncha ◽  
Ashok Santra
Keyword(s):  
High Performance ◽  
Drilling Fluids ◽  
Water Based

scholarly journals Laponite: a promising nanomaterial to formulate high-performance water-based drilling fluids

2020 ◽  
Author(s):  
Xian-Bin Huang ◽  
Jin-Sheng Sun ◽  
Yi Huang ◽  
Bang-Chuan Yan ◽  
Xiao-Dong Dong ◽  
...  
Keyword(s):  
High Performance ◽  
Drilling Fluid ◽  
Nitrogen Adsorption ◽  
Drill String ◽  
Wellbore Stability ◽  
Fluid Loss ◽  
Drilling Fluids ◽  
Mechanism Analysis ◽  
Water Based ◽  
Inhibition Performance

Abstract High-performance water-based drilling fluids (HPWBFs) are essential to wellbore stability in shale gas exploration and development. Laponite is a synthetic hectorite clay composed of disk-shaped nanoparticles. This paper analyzed the application potential of laponite in HPWBFs by evaluating its shale inhibition, plugging and lubrication performances. Shale inhibition performance was studied by linear swelling test and shale recovery test. Plugging performance was analyzed by nitrogen adsorption experiment and scanning electron microscope (SEM) observation. Extreme pressure lubricity test was used to evaluate the lubrication property. Experimental results show that laponite has good shale inhibition property, which is better than commonly used shale inhibitors, such as polyamine and KCl. Laponite can effectively plug shale pores. It considerably decreases the surface area and pore volume of shale, and SEM results show that it can reduce the porosity of shale and form a seamless nanofilm. Laponite is beneficial to increase lubricating property of drilling fluid by enhancing the drill pipes/wellbore interface smoothness and isolating the direct contact between wellbore and drill string. Besides, laponite can reduce the fluid loss volume. According to mechanism analysis, the good performance of laponite nanoparticles is mainly attributed to the disk-like nanostructure and the charged surfaces.

Four-well comparison in Papua New Guinea: high-risk, high-angle wells demonstrate extended wellbore stability and faster drilling time with inhibitive high-performance water-based fluid

2011 ◽  
Vol 51 (1) ◽  
pp. 119
Author(s):  
Angus Florence ◽  
Mike Dow ◽  
George Shieh ◽  
JV Babu
Keyword(s):  
High Risk ◽  
Papua New Guinea ◽  
High Performance ◽  
Cost Savings ◽  
New Guinea ◽  
Wellbore Stability ◽  
Drilling Fluids ◽  
Water Based ◽  
Performance Decline ◽  
Glycol Fluid

A four-well project located onshore Papua New Guinea provided an opportunity to compare the performance of two inhibitive drilling fluids in the problematic 12¼” interval. Wells A and B were drilled using a conventional KCl/glycol fluid. Wells C and D used a high-performance water-based fluid (HPWBF) containing a shale inhibitor that also provides lubricity. All four wells were drilled with the same rig. The base brine for both fluids was KCl. All hole sections were directionally drilled from vertical to near horizontal by section TD through a claystone interval. Tectonic wellbore breakout was present in all four wells, and the position of the breakout in the wellbore varied from well to well. Well A was regarded as the easiest well to drill due to the breakout being on the sides on the inclined well bore (horizontal), and Well D was regarded as being the most difficult well to drill due to the breakout being located directly on the top and bottom of the wellbore (vertical). Performance comparisons were made using on bottom rates of penetration, tripping times, casing running times, and overall hole section costs. These data have been normalised to remove non hole related NPT events. The KCl/glycol system provided sufficient wellbore stability in Wells A and B with horizontal breakouts and with non-optimal breakouts with very limited openhole exposure. For higher risk wells C and D with non-optimal breakout positions however, the HPWBF offered improved reliability and ensured there was no performance decline. Outstanding performance occurred in Well D where the HPWBF maintained good wellbore stability over a 56-day exposure. Although the KCl/glycol fluid had a lower cost/bbl, improved overall cost savings were achieved by using the HPWBF in the high-risk wells. This paper addresses all operations performed while drilling and casing the 12¼” interval. Possible causes for performance differences are evaluated, taking into account that mud systems represent only one variable. As other variables were introduced progressively, it was possible to back these out to determine mud system effectiveness.

Sodium Silicate Based Drilling Fluid Application in Gulf of Thailand to Stabilise Wellbore: A Case Study

2021 ◽  
Author(s):  
Waleepon Sukarasep ◽  
Rahul Sukanta Dey ◽  
Visarut Phonpuntin
Keyword(s):  
Sodium Silicate ◽  
High Performance ◽  
Drilling Fluid ◽  
Wellbore Stability ◽  
Drilling Fluids ◽  
Gulf Of Thailand ◽  
Hole Cleaning ◽  
Water Based ◽  
Wellbore Strengthening ◽  
Effective Seal

Abstract Sodium Silicate were first used in water-based drilling fluids to stabilize claystone formations in the 1930's, but found favour in the 1990's in high performance, non dispersed water based systems for drilling problematic claystone formations as an alternative to oil-based drilling fluids. In Bongkot South field, Gulf of Thailand, sodium silicate-based drilling fluid (SSBDF) were used with mixed success in shallow gas drilling. Typically, platform WP-33, the claystone formation of the 12¼" section were drilled with 5% v/v Sodium Silicate in the water based drilling fluid together with excessive circulation as intention to improve hole cleaning frequently result in a wellbore that was overgauge by upto 18.9% in some case. This led to further hole cleaning problem that also compromised cement job quality. A further 6 well campaign on WPS-16 required a re-evaulation of the SSBDF coupled to an understanding of the wellbore instability mechanisms that leads to hole enlargement. To overcome better wellbore stability, sodium silicate has been designed by increased concentration to 8% v/v sodium silicate treated drilling fluid showed optimal design for application base on application of SSBDF has been used on platform WP-11 in 2002. Rheology, hydraulic and flow regime was adjusted for laminar flow that reduced the erosion of fragile claystone formation in the wellbore. The revised SSBDF formulation at WPS-16 result in a significant reduction of hole enlargement to 3.2% in the claystone section through a combination of chemicals and mechanical inhibition that contribute improved hole cleaning. The addition of wellbore strengthening material also provide an effective seal to minimize gas invasion. This paper describes the field trials in the Gulf of Thailand drilled with revised sodium sodium silicate based drilling fluid, the use of wellbore strengthening materials to manage gas influxes, better drilling practice and hydraclic simulation concluded that high performance water based drilling fluid of this nature have wider application where oil-base drilling fluid have traditionally been used.

Laponite Nanoparticle as a High Performance Rheological Modifier in Water-Based Drilling Fluids

2018 ◽  
Vol 917 ◽  
pp. 134-139
Author(s):  
Fan Liu ◽  
Guang Cheng Jiang ◽  
Kai Wang ◽  
Jin Xi Wang
Keyword(s):  
Shear Rate ◽  
Rheological Properties ◽  
Yield Point ◽  
High Performance ◽  
Shear Thinning ◽  
Drilling Fluids ◽  
Star Network ◽  
Water Based ◽  
Rate Test ◽  
Rheological Modifier

In this paper, we demonstrated an artificial nanoparticles, Laponite, as a high performance rheological modifier in water-based drilling fluids. We made a comparison between Laponite nanoparticle and bentonite as rheological modifier in polyanionic cellulose (PAC) solution and weitghted water-based drilling fluids. In viscosity-shear rate test, both Laponite and bentonite could translate 0.5 wt.% PAC solution from Newton fluids to yield-pseudoplastic fluid. However, 1 wt.% Laponite was better in improving the shear-thinning behavior compared with 4 wt.% bentonite. In the stress-shear rate test, the results were fit with Bingham model with a high R2, and 1 wt.% Laponite/0.5 wt.% PAC suspension had a yield point of 5.19 Pa, which was higher than that of 4 wt.% bentonite/0.5 wt.% PAC suspension (3.13 Pa). Similarly, 1 wt.% Laponite/0.5 wt.% PAC suspension maintained a G’ of 12 Pa in the oscillation frequency sweep test, whereas G’ of 4%bentonite/0.5%PAC suspension was nearly 5 Pa. Particularly, 0.5 wt.% PAC /Laponite suspensions could maintain higher gel structure, yield point and better shear-thinning behaviors after 120°C hot rolling. The TEM image revealed that nanoscaled Laponite could form a “star network” with PAC in water, which explained the good rheological properties of PAC/LAP mixed suspensions. Besides, in the weighted drilling fluids, 1 wt.% Laponite could maintained a much higher gel strength compared with 4 wt.% bentonite.As the unique rheological properties, Laponite nanoparticles can greatly enhance abilities of water-based drilling fluids in circulating cuttings and making the borehole clean.

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