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.

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.

Full Scale Flow Loop Experiments of Hole Cleaning Performances of Drilling Fluids

2015 ◽  
Author(s):  
Jan David Ytrehus ◽  
Ali Taghipour ◽  
Sneha Sayindla ◽  
Bjørnar Lund ◽  
Benjamin Werner ◽  
...  
Keyword(s):  
Test Section ◽  
Drilling Fluid ◽  
Drilling Fluids ◽  
Flow Loop ◽  
Base Oil ◽  
Hole Cleaning ◽  
Cleaning Performance ◽  
Water Based ◽  
Fluid Properties ◽  
Drilling Cost

One important requirement for a drilling fluid is the ability to transport the cuttings out of the borehole. Improved hole cleaning is a key to solve several challenges in the drilling industry and will allow both longer wells and improved quality of well construction. It has been observed, however, that drilling fluids with similar properties according to the API standard can have significantly different behavior with respect to hole cleaning performance. The reasons for this are not fully understood. This paper presents results from flow loop laboratory tests without and with injected cuttings size particles using a base oil and a commercial oil based drilling fluid. The results demonstrate the importance of the rheological properties of the fluids for the hole cleaning performance. A thorough investigation of the viscoelastic properties of the fluids was performed with a Fann viscometer and a Paar-Physica rheometer, and was used to interpret the results from the flow loop experiments. Improved understanding of the fluid properties relevant to hole cleaning performance will help develop better models of wellbore hydraulics used in planning of well operations. Eventually this may lead to higher ROP with water based drilling fluids as obtained with oil based drilling fluids. This may ease cuttings handling in many operations and thereby significantly reduce the drilling cost using (normally) more environmentally friendly fluids. The experiments have been conducted as part of an industry-sponsored research project where understanding the hole cleaning performance of various oil and water based drilling fluids is the aim. The experiments have been performed under realistic conditions. The flow loop includes a 10 meter long test section with 2″ OD freely rotating drillstring inside a 4″ ID wellbore made of concrete. Sand particles were injected while circulating the drilling fluid through the test section in horizontal position.

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.

Development Field First - Directionally Drilling Through Challenging Muderong Shale and Highly Depleted Reservoir Sand with HPWBM

2021 ◽  
Author(s):  
Tylan John Lambert ◽  
Shiv Aanand Mj ◽  
Courtney Clark
Keyword(s):  
High Performance ◽  
Chemical Interaction ◽  
Drilling Fluid ◽  
Wellbore Stability ◽  
Drilling Fluids ◽  
Robust Solution ◽  
Fluid Analysis ◽  
Well Design ◽  
Design Selection ◽  
Fluid Design

Abstract Advancement in High Performance Water Based Mud (HPWBM) coupled with a deeper understanding of shale and chemical interaction has taken a leap in recent years enabling the drilling of challenging wells whilst replacing Synthetic Based Mud (SBM) as the preferred technical option. The exceptional inhibition properties, versatility to chemical manipulation and stability, as well as being an environmentally beneficial alternative to SBM, HPWBM has proven to be a robust solution for drilling the challenging Muderong shale and highly depleted reservoir sands in the field. Through a detailed field wide offset review focusing on wellbore stability and shale reactivity relationship observations, time dependent shale reactivity and an engineered bridging package was the basis of a successful fluid formulation and selection which then resulted in a flawless execution of the challenging well. Various testing of shale cuttings from the field paired with an offset review was key to understanding the extent of shale reactivity in relation to the type of shale being drilled and cause of shale instability in the area. These results were imperative in providing technical justification to utilise HPWBM for drilling through the Muderong shale. Applying detailed reservoir drilling fluid analysis to the overburden drilling fluids design and incorporating previous offset fluid design learnings, provided a robust and versatile drilling fluid system. This paper will review the steps undertaken to validate the selection of HPWBM over SBM through detailed analysis of wellbore stability, shale reactivity, permeability assessment, pore throat sizing and pore pressure transmission. It will present the misnomer of comingling the wellbore stability requirement, primarily mud weight, with shale reactivity in the field as well as the relation between the plateauing of shale reactivity curves to near well wellbore swelling. Extensive laboratory testing was performed to formulate and demonstrate the efficacy of the bridging package in addressing differential sticking, losses and wellbore strengthening in highly depleted sands. In addition, this paper will also present actual field results on stability of the fluid properties along with resultant torque and drag throughout drilling of a directional well with no requirement for lubricants. This paper should be of interest to all engineers and technologists who are involved in shale reactivity analysis, well design, drilling fluids design, selection and interaction as well as highly depleted reservoir sand drilling.

Experimental Study of Cuttings Transport Efficiency of Water Based Drilling Fluids

2014 ◽  
Author(s):  
Jan David Ytrehus ◽  
Ali Taghipour ◽  
Bjørnar Lund ◽  
Benjamin Werner ◽  
Nils Opedal ◽  
...  
Keyword(s):  
Test Section ◽  
Drilling Fluid ◽  
Drilling Fluids ◽  
Flow Loop ◽  
Cuttings Transport ◽  
Hole Cleaning ◽  
Cleaning Performance ◽  
Water Based ◽  
Fluid Properties ◽  
Drilling Cost

One important requirement for a drilling fluid is the ability to transport the cuttings out of the borehole. Improved hole cleaning is a key to solve several challenges in the drilling industry and will allow both longer wells and improved quality of well construction. It has been observed, however, that drilling fluids with similar properties according to the API standard can have significantly different behavior with respect to hole cleaning performance. The reasons for this are not fully understood. This paper presents results from laboratory tests where water based drilling fluids with similar rheological properties according to API measurements have been tested for their hole cleaning capabilities in a full scale flow loop. Thorough investigation of the viscoelastic properties of the fluids were performed with, among other instruments, a Paar-Physica rheometer. Improved understanding of the fluid properties relevant to hole cleaning performance will help develop better models of wellbore hydraulics used in planning of well operations. Eventually this may lead to higher ROP with water based drilling fluids as obtained with oil based drilling fluids. This may ease cuttings handling in many operations and thereby significantly reduce the drilling cost using (normally) more environmentally friendly fluids. The experiments have been conducted as part of an industry-sponsored research project where understanding the hole cleaning performance of various oil and water based drilling fluids is the aim. The experiments have been performed under realistic conditions. The flow loop includes a 12 meter long test section with 2″ OD freely rotating drillstring inside a 4″ ID wellbore made of concrete. Sand particles were injected while circulating the drilling fluid through the test section in horizontal position.

The Influence of SiO2 and TiO2 Nanoparticles on the Properties of Water-Based Mud

2017 ◽  
Author(s):  
Petar Mijić ◽  
Nediljka Gaurina-Međimurec ◽  
Borivoje Pašić
Keyword(s):  
Filter Cake ◽  
Drilling Fluid ◽  
Wellbore Stability ◽  
Drilling Fluids ◽  
Drilling Mud ◽  
Shale Formations ◽  
Wellbore Instability ◽  
Water Based ◽  
Fluid Properties

About 75% of all formations drilled worldwide are shale formations and 90% of all wellbore instability problems occur in shale formations. This increases the overall cost of drilling. Therefore, drilling through shale formations, which have nanosized pores with nanodarcy permeability still need better solutions since the additives used in the conventional drilling fluids are too large to plug them. One of the solutions to drilling problems can be adjusting drilling fluid properties by adding nanoparticles. Drilling mud with nanoparticles can physically plug nanosized pores in shale formations and thus reduce the shale permeability, which results in reducing the pressure transmission and improving wellbore stability. Furthermore, the drilling fluid with nanoparticles, creates a very thin, low permeability filter cake resulting in the reduction of the filtrate penetration into the shale. This thin filter cake implies high potential for reducing the differential pressure sticking. In addition, borehole problems such as too high drag and torque can be reduced by adding nanoparticles to drilling fluids. This paper presents the results of laboratory examination of the influence of commercially available nanoparticles of SiO2 (dry SiO2 and water-based dispersion of 30 wt% of silica), and TiO2 (water-based dispersion of 40 wt% of titania) in concentrations of 0.5 wt% and 1 wt% on the properties of water-based fluids. Special emphasis is put on the determination of lubricating properties of the water-based drilling fluids. Nanoparticles added to the base mud without any lubricant do not improve its lubricity performance, regardless of their concentrations and type. However, by adding 0.5 wt% SiO2-disp to the base mud with lubricant, its lubricity coefficient is reduced by 4.6%, and by adding 1 wt% TiO2-disp to the base mud with lubricant, its lubricity coefficient is reduced by 14.3%.

scholarly journals An Investigation on the Function of Mud Cakes on the Inhibition of Low Molecular Inhibitor for Water-Based Drilling Fluids

Energies ◽  
2019 ◽  
Vol 12 (19) ◽  
pp. 3726 ◽  
Author(s):  
Wenxin Dong ◽  
Xiaolin Pu ◽  
Biao Ma
Keyword(s):  
High Performance ◽  
Drilling Fluid ◽  
Environmental Scanning Electron Microscopy ◽  
Homogeneous Layer ◽  
Environmental Scanning ◽  
Drilling Fluids ◽  
Mud Cake ◽  
Water Based ◽  
Oil And Natural Gas ◽  
Pass Through

The major low molecular inhibitors showed inhibition in the hydration of clay in the laboratory for water-based drilling fluids, according to the principle of intercalation adsorption. However, inhibitors have failed and caused serious engineering accidents in drilling oil and natural gas. This paper investigated the transmission of several of drilling fluids to indicate whether low molecular inhibitor for drilling can effectively inhibit the wellbore hydration. The inhibition of drilling fluid with the plugging of mud cakes, was significantly weakened based on the hydration expansion of cores and cutting recoveries. The residual contents of inhibitors were determined with the precolumn derivation of high-performance liquid chromatography (HPLC) analysis and were chartered with Fourier transform infrared spectroscopy (FTIR) and nuclear magnetic resonance (NMR) analysis in the structure of the derivative. The clogging behavior of the mud cake was described by environmental scanning electron microscopy (ESEM). Experiments show that 40 wt% to 90 wt% by weight of the corrosion inhibitor cannot pass through the mud cake in the dynamic filtration of the drilling fluid. The mud cake can be further divided into a nanostructure layer, a homogeneous layer and an anisotropic layer with different permeability. Most inhibitors should be limited to the nanostructure layer and the homogeneous layer.

Performance Evaluation of a Highly Inhibitive Water-Based Drilling Fluid for Ultralow Temperature Wells

2017 ◽  
Vol 140 (1) ◽  
Author(s):  
Xin Zhao ◽  
Zhengsong Qiu ◽  
Mingliang Wang ◽  
Weian Huang ◽  
Shifeng Zhang
Keyword(s):  
Drilling Fluid ◽  
Hydrate Formation ◽  
Wellbore Stability ◽  
Drilling Fluids ◽  
Offshore Drilling ◽  
Ultralow Temperature ◽  
Water Based ◽  
Drilling Operations ◽  
Inhibition Performance ◽  
Static Conditions

Drilling fluid with proper rheology, strong shale, and hydrate inhibition performance is essential for drilling ultralow temperature (as low as −5 °C) wells in deepwater and permafrost. In this study, the performance of drilling fluids together with additives for ultralow temperature wells has been evaluated by conducting the hydrate inhibition tests, shale inhibition tests, ultralow temperature rheology, and filtration tests. Thereafter, the formulation for a highly inhibitive water-based drilling fluid has been developed. The results show that 20 wt % NaCl can give at least a 16-h safe period for drilling operations at −5 °C and 15 MPa. Polyalcohol can effectively retard pore pressure transmission and filtrate invasion by sealing the wellbore above the cloud point, while polyetheramine can strongly inhibit shale hydration. Therefore, a combination of polyalcohol and polyetheramine can be used as an excellent shale stabilizer. The drilling fluid can prevent hydrate formation under both stirring and static conditions. Further, it can inhibit the swelling, dispersion, and collapse of shale samples, thereby enhancing wellbore stability. It has better rheological properties than the typical water-based drilling fluids used in onshore and offshore drilling at −5 °C to 75 °C. In addition, it can maintain stable rheology after being contaminated by 10 wt % NaCl, 1 wt % CaCl2, and 5 wt % shale cuttings. The drilling fluid developed in this study is therefore expected to perform well in drilling ultralow temperature wells.

scholarly journals Chemical and Thermal Investigation on Stability of Tanuma Formation Using Different Additives with Drilling Fluids

2020 ◽  
Vol 26 (5) ◽  
pp. 82-94
Author(s):  
Khalid Mohammed Abdulzahra ◽  
Asawer Abdulrasul Kuery ◽  
Mayssaa Ali Abdul aoun
Keyword(s):  
Sodium Silicate ◽  
Drilling Fluid ◽  
Immersion Test ◽  
Wellbore Stability ◽  
Drilling Fluids ◽  
High Recovery ◽  
Recovery Percentage ◽  
Dispersion Test ◽  
Fluid Interaction ◽  
Test Result

Wellbore stability is considered as one of the most challenges during drilling wells due to the reactivity of shale with drilling fluids. During drilling wells in North Rumaila, Tanuma shale is represented as one of the most abnormal formations. Sloughing, caving, and cementing problems as a result of the drilling fluid interaction with the formation are considered as the most important problem during drilling wells. In this study, an attempt to solve this problem was done, by improving the shale stability by adding additives to the drilling fluid. Water-based mud (WBM) and polymer mud were used with different additives. Three concentrations 0.5, 1, 5 and 10 wt. % for five types of additives (CaCl2, NaCl, Na2SiO3, KCl, and Flodrill PAM 1040) was used. Different periods of immersion (1, 24 and 72 hours) were applied. The results of the immersion test showed that using 10 wt. % of Na2SiO3 for WBM gives a high recovery percentage (77.99 %) after 72 hr, while the result of the dispersion test (roller oven) of 10 wt % of sodium silicate with WBM was (80.97 %) after 16 hr. Also, the immersion test result of 10 wt% of sodium silicate with polymer mud was (79.76 %) after 72 hr and the results of dispersion test (roller oven) of 10 wt. % of sodium silicate with polymer mud was (84.51 %) after 16 hr.

Effects of Oil-Based Drilling-Fluid Rheological Properties on Hole-Cleaning Performance

2016 ◽  
Author(s):  
Benjamin Werner ◽  
Velaug Myrseth ◽  
Bjørnar Lund ◽  
Arild Saasen ◽  
Zalpato Ibragimova ◽  
...  
Keyword(s):  
Rheological Properties ◽  
Drilling Fluid ◽  
Drill String ◽  
Operating Conditions ◽  
Wellbore Stability ◽  
Drilling Fluids ◽  
Fluid Viscosity ◽  
Flow Loop ◽  
Cuttings Transport ◽  
Hole Cleaning

Drilling fluids play an important role in safe and efficient drilling operations. Wellbore stability, formation integrity, drill string lubrication, and cuttings transport are among their main requirements. The removal of a cuttings bed is one of the major difficulties while trying to keep up a steady drilling progress. Deviated and long horizontal wellbore sections provide challenges not only to the drilling equipment in use, but also to the fluids. Cuttings accumulate easily on the bottom of a wellbore section due to gravity and can therefore reduce hole cleaning efficiency. Cuttings transport is highly dependent on the properties of the drilling fluid. Viscosity, density and gel strength are among the key parameters. Drilling fluids have in general a complex composition with either water or oil as a base substance. Demanding operating conditions, for example high temperature difference from topside to the deep downhole sections or varying shear rates throughout the wellbore, also influence the properties of the fluids during operation. Drilling fluids have to be adapted to all these different drilling situations. The aim of the full project is to compare different water- and oil-based drilling fluids regarding their hole cleaning abilities. As part of the experimental study where drilling fluids are circulated in a 10 m long flow-loop test section with a free-whirling rotating inner drill string, rheological characterization with an Anton Paar MCR rheometer is performed. These measurements include determination of flow properties, yield stress and viscosity-temperature dependence. The results are correlated with the industry standard procedures for the testing of drilling-fluid properties with Fann 35 viscometers (API/ ISO standards). Measurements performed on viscometers at the oil rigs are done to receive fast results in order to control the drilling operation. In contrast, rheometer measurements provide the possibility of a deeper comprehension of the rheological properties of the drilling fluids due to the advanced measurement system. This work presents rheological properties for a typical oil-based drilling fluid commonly used on the Norwegian Continental Shelf, and includes a comparison with two other oil-based drilling fluids based on previously published work. The rheometer results are analyzed in relation to the flow loop experiments and to the viscosity data measured in accordance with the API/ISO specifications. The results from the rheological comparison together with the results from the flow-loop experiments are expected to make an influencing contribution to the question of why various drilling fluids perform so differently in terms of cuttings transport.

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