Experimental investigation of cuttings transportation in deviated and horizontal wellbores using polypropylene–nanosilica composite drilling mud

Journal Pre-proof Experimental investigation of cuttings transportation in deviated and horizontal wellbores using polypropylene–nanosilica composite drilling mud Jeffrey O. Oseh, M.N.A. Mohd Norddin, Issham Ismail, Afeez O. Gbadamosi, Augustine Agi, Abdul R. Ismail PII:

S0920-4105(20)30056-5

DOI:

https://doi.org/10.1016/j.petrol.2020.106958

Reference:

PETROL 106958

To appear in:

Journal of Petroleum Science and Engineering

Received Date: 28 July 2019 Revised Date:

13 January 2020

Accepted Date: 14 January 2020

Please cite this article as: Oseh, J.O., Mohd Norddin, M.N.A., Ismail, I., Gbadamosi, A.O., Agi, A., Ismail, A.R., Experimental investigation of cuttings transportation in deviated and horizontal wellbores using polypropylene–nanosilica composite drilling mud, Journal of Petroleum Science and Engineering (2020), doi: https://doi.org/10.1016/j.petrol.2020.106958. This is a PDF file of an article that has undergone enhancements after acceptance, such as the addition of a cover page and metadata, and formatting for readability, but it is not yet the definitive version of record. This version will undergo additional copyediting, typesetting and review before it is published in its final form, but we are providing this version to give early visibility of the article. Please note that, during the production process, errors may be discovered which could affect the content, and all legal disclaimers that apply to the journal pertain. © 2020 Published by Elsevier B.V.

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Experimental investigation of cuttings transportation in deviated and horizontal wellbores using polypropylene–nanosilica composite drilling mud

2

Jeffrey O. Oseh

3

1

Department of Petroleum Engineering, School of Chemical and Energy Engineering, Universiti Teknologi Malaysia, 81310 Johor Bahru, Malaysia.

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2

Malaysia Petroleum Resources Corporation Institute for Oil and Gas (MPRC–UTM), Universiti Teknologi Malaysia, 81310 Johor Bahru, Malaysia.

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, M. N. A. Mohd Norddin 1, *, Issham Ismail 1, 2, Afeez O. Gbadamosi 1, 3, Augustine Agi 1, Abdul R. Ismail 1, 2

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1, 2, 3

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Department of Chemical and Petroleum Engineering, College of Engineering, Afe Babalola

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University, Ado–Ekiti, P.M.B. 5454, Ekiti State, Nigeria.

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* Corresponding author: [email protected]

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ABSTRACT

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The experience acquired in the field showed that poor cuttings transportation results in several

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drilling problems, such as pipe sticking, undue torque and drag, hole–pack off, or lower than

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projected drilling performance. In this study, complex water–based mud (WBM) formulated with

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polypropylene–nanosilica composite (PP–SiO2 NC) and partially hydrolyzed polyacrylamide

17

(PHPA), a drag–reducing agent were used to examine cuttings transferring efficiencies (CTEs).

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The examination focused on the impact of diameters of cuttings (between 0.50 and 4.00 mm),

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hole angles (45, 60, 75, 90 °), mud velocities (between 0.457 and 1.80 m/s) and different

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concentrations (0.4, 0.5, 0.8 and 1.2 ppb) of PP–SiO2 NC and PHPA. A field–oriented cuttings

21

transport flow loop of dimensions (69.85 mm × 26.67 mm, 6.07 m–long annulus) was

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constructed to determine the CTEs of the drilling muds. Results showed that smallest cuttings

23

were easiest to remove when mud velocities of 0.457, 0.630, 0.823 and 0.960 m/s were used, but

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when the velocity increased to 1.80 m/s, the transport of largest cuttings became the easiest.

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Results also confirmed that PP–SiO2 NC muds are more capable of transferring cuttings than

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PHPA mud samples with or without pipe rotation speed due to increased colloidal forces that

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increase the interaction between cuttings and PP–SiO
NC particles. Rotation of drill pipe and

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an increase in mud velocity will effectively increase the drag effects, which will lead to increased

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CTE. Hole angle 45 ° was the most difficult inclination in the cuttings transport process due to

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the higher settling tendency of cuttings on the low side of the hole. The application of complex

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WBM with PP–SiO2 NC showed promising attributes in a cuttings transport process. 1

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Keywords: Highly inclined; Horizontal wellbores; Cuttings transportation; Polypropylene–

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nanosilica composite, Rheological properties; Drilling fluids

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1. Introduction

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With increasing energy demand from non–renewable sources, such as oil and gas, several

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novel drilling fluid additives for water–based muds (WBMs) are explored within the petroleum

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industry. They will not only circulate a higher proportion of rock cuttings to the surface, but are

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also cost–effective and environmentally acceptable (Bizhani et al., 2016; Dhinesh and

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Annamalai, 2018; Nanthagopal et al., 2019). In a rotary drilling operation, cuttings transport is

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the ability of a drilling fluid to lift rock cuttings from the hole to the surface and to ensure that

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cuttings are suspended when drilling operation is paused (Bilgesu et al., 2007). Since the history

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of drilling operation, several studies have been performed on the transportation of cuttings in

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deviated and horizontal wellbores. Most of these studies showed that cuttings lifting

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approximately above hole angle 30 ° from vertical present more problems compared with those

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experienced in a vertical well (0 °) or near vertical wells (less than 30 °) (Sayindla et al., 2017,

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Gbadamosi et al., 2018a, b; Boyou et al., 2019).

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Inadequate cuttings transport can result in several wellbore drilling problems and it adversely

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affects drilling efficiency. It can results in lost circulation, stuck pipe, reduced drilling rate, poor

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cementing jobs, high torque and drag, hole enlargement, mud cake formation, accumulation at

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porous formation, and cuttings accumulation on the low side of the hole (Bilgesu et al., 2007;

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Bizhani et al., 2016). It can also lead to increase in downtime and operating costs. These

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phenomena are often aggravated in a deviated and horizontal wells due to the tendency of sand

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cuttings to settle on the low side of the hole caused by the resultant gravity effects (Bilgesu et al.

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2007). The axial velocity of drilling fluid will start to reduce when hole angle begins to deviate

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from vertical due to increase in drag force, which is parallel to the direction of flow of drilling

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fluid (Ismail et al., 2016; Hakim et al., 2019; Yeu et al., 2019). To solve these problems in the

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field, various expensive operating methods, such as washing and back reaming, wiper trips or

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pumping out of the hole are executed (Samsuri and Hamzah, 2016). The rheology of drilling

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fluid circulating rock cuttings from the bit towards the surface determines the effectiveness of a

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given drilling operation. Apart from drilling fluid rheology, the nature of the drilling fluid, fluid

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flow rate, fluid density, annulus inclination, drill bit rate of penetration (ROP), drill pipe rotation

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speed, pipe eccentricity (position of the pipe in the hole), cuttings size and size distribution 2

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(geometry, concentration and orientation), and axially varying flow geometry are other important

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factors that controls the cuttings transferring capacity of drilling muds (Bizhani et al., 2016;

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Boyou et al., 2019, Yeu et al., 2019). Mud viscosity is an important property of drilling fluid.

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The nature of base fluid (fresh water, oil or gas) and solids in it determines the viscosity of the

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mud. Sand cuttings will settle at the bottom of the hole if the viscosity of the circulating mud is

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too low (Sayindla et al., 2017; Yeu et al., 2019). Viscosity is usually higher for higher weighted

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muds due to the weight of the material. Drilling fluids have higher viscosity at low shear rates

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and a lower viscosity at high shear rates (Caenn et al., 2017).

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Conventional WBMs formulated with polymers are extensively used to drill petroleum

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reservoirs since they are good filtrate loss control agents and efficient wellbore stabilizers. They

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efficiently lift rock cuttings to the surface and they have unique rheological properties (Caenn et

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al., 2017; Ismail et al., 2019). They also have high operational efficiency, technical and

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economic viabilities and lower mud costs. The most widely used polymeric drilling fluids during

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oilfield application is partially hydrolyzed polyacrylamide (PHPA) (Kadaster et al., 1992; Hale

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and Mody, 1993). PHPA is a viscosity–increasing and fluid–reducing effect in WBM. It has

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good water solubility. It belongs to polymer type treatment agent and is applied to end face of

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hydrated clay adsorbed in WBM. It is also preferred in drilling field applications because it can

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hold off high mechanical stresses present during production of oil and gas wells. However,

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PHPA is very prone and sensitive to harsh downhole conditions and saline environments. Its

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rheological properties are drastically reduced when faced with deeper drilling depths (Liao and

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Siems, 1990; Lam et al., 2015).

84

More recently, applications of polymer nanocomposites (PNCs) in WBMs are found to

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increase the overall properties of drilling muds, which is due to the relatively high specific

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surface areas and the formation of micro–nanosized particles of the PNCs (Mao et al., 2015;

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Aftab et al., 2016; Abdollahi et al., 2018; Davoodi et al., 2019). Numerous laboratory works

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conducted using PNC drilling fluids are focused on the use of silica nanoparticle or nanosilica

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(SiO₂ NP) (Mao et al., 2015; Aftab et al., 2016; Boyou et al., 2019; Kök and Bal, 2019). This is

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mainly due to its exceptionally strong bond network, good thermal stability, enough small size

91

and high average specific surface area (Gbadamosi et al., 2019; Boyou et al., 2019).

92

Nevertheless, the efficiency of SiO2 NP is eroded due to its aggregation tendency, which directly

93

hinders its efficiency (Kök and Bal 2019). Thus, combination of SiO2 NP and synthetic 3

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polypropylene (PP) to form hydrophobic polypropylene–nanosilica composite (PP–SiO2 NC) can

95

help to control the degree of particle aggregation and increase particle dispersion in drilling

96

muds. In a recent study conducted by the authors, a detailed investigation of the morphology,

97

structural information and particle size distribution of PP–SiO2 NC were carried out (Oseh et al.,

98

2019). Besides, the authors carried out a critical evaluation of rheological, lubricity, filtration

99

control properties and, salt tolerance investigation and reported that the properties of WBM

100

improved with the presence of PP–SiO2 NC particles due to their effective dispersion in the

101

WBM (Oseh et al., 2019).

102

Cuttings transportation in a wellbore, especially in a deviated and horizontal wellbores are

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complex. It is being investigated by researchers using different types of drilling muds including

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complex based muds systems. This is mostly caused by the limitation of the availability of field

105

data on transport patterns of cuttings with different sizes, mud velocities and hole angles with

106

and without pipe rotation. In these studies, cuttings transport process using nanosilica drilling

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fluids is limited, and there is none conducted with PNC drilling fluids. Table 1 presents a

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summary of available laboratory studies of application of nanosilica drilling fluids for hole

109

cleaning and the main concentration of this research. Therefore, this research is focus on how

110

different concentrations (0.4, 0.5, 0.8 and 1.2 ppb) of PP–SiO2 NC compared with those of the

111

PHPA in improving the rheology and filtration properties of complex based mud. It also

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describes a study of cuttings transferring efficiency test for drilling under a fluid environment

113

where PP–SiO2 NC and PHPA exists. Thus, the PP–SiO2 NC studied in this article belong to the

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organically combined inorganic material. Its main role in the drilling mud is to disperse in the

115

drilling mud, enhance the stability of the wellbore and improve the quality of the mud cake.

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The main contribution of this article to lift cuttings towards the surface is that the PP–SiO2

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NC particles are widely distributed and stable in the mud due to their fine–dispersion and narrow

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particle size distribution. With the PP–SiO2 NC in the complex mud system, a stronger PP–SiO2

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NC particle–sand cuttings interaction occurred, which makes it easier to lift cuttings to the

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surface. Furthermore, by investigating the effect of mud rheological properties on cuttings

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transport process, this research provides more laboratory data to the discussion of the parameters

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controlling cuttings transport in wellbores compared to previous studies presented in Table 1.

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2. Materials and methods

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2.1. Materials

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Polypropylene (PP) of melt index 12.3 g/10 min, xylene, ammonium hydroxide (NH4OH),

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tetraethyl orthosilicate (TEOS) of reagent grade, 98 %, polyethylene–block–poly(ethylene

130

glycol) (PE–b–PEG) of average Mn ~1400 of PE/PEG 1/1 by weight, ethanol (EtOH) and high

131

molecular weight PHPA were acquired from Sigma–Aldrich Chemical Co. (Saint Louis, USA).

132

All the chemicals were used as acquired.

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2.2. Methods

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2.2.1. Synthesis of PP–SiO2 NC

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The PP–SiO2 NC used in the current study was synthesized by hot emulsion sol–gel process.

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This process primarily consists of two stages: hydrolysis of the precursor, TEOS and

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condensation/polymerization to form entire PP–SiO2 NC structure (Zu et al., 2013). During the

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network formation process, a large amount of solvent are also impregnated in the network, and

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thus, a gel is formed. Figure 1 presents the procedures for the synthesis of PP–SiO2 NC. As

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Figure 1 shows, 24 g of PE–b–PEG and 6 g of PP were mixed at 160 °C and 300 rpm using a

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plasti–corder Brabendar. The resulting mixture was dissolved using 20 ml of xylene and stirred

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for 2 hours with a magnetic stirrer at 140 °C and 300 rpm. 20 ml of TEOS was introduced into

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the solution and stirred untill a clear solution was observed (hydrophobic solution). The

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hydrophobic solution was added slowly into a mixed solution of 100 ml EtOH/60 ml NH4OH

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(hydrophilic solution). The mixture was magnetically stirred for another 30 minutes at 80 °C,

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and was cooled for 24 hours at ambient temperature to allow the particles to form. The cooled

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mixture was separated by centrifugation for 40 minutes at 6000 rpm and washed with EtOH once

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to remove impurities. The synthesized product was dried in an oven for 24 hours at 60 °C to

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obtain the formed PP–SiO2 NC.

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Figure 2 shows the formation mechanism of PP–SiO2 NC. The formation mechanism

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involves two processes, as presented in Figure 2. The first process is the formation of stable

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suspension, in which the TEOS was mixed with the oil (hydrophobic) phase (PP and PE–b–PEG

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dissolved by xylene) in advance. The hydrolysis of TEOS start immediately by adding

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hydrophobic phase into water, EtOH and NH4OH (hydrophilic phase), and four hydrophobic Si–

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OEt bond was partially converted to hydrophilic Si–OH bond. Thus, the TEOS could be

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considered to have played the role of a surfactant in a way, and jointly with the nonionic

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surfactant (PE–b–PEG) to form a stable suspension. The second process is the formation of the

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interpenetrating structure of PP–SiO2 NC. The hydrolysis of TEOS and polycondensation

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initially starts at the interface between the hydrophilic phase and the hydrophobic phase before

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extending to the inner of the oil drops (Zu et al., 2013). As the SiO2 particle forms, the PP

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becomes secluded by the restriction of the SiO2 layer. PP molecule chain was prevented from

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movong in the SiO2 pores, thus, the interpenetrating structure of PP–SiO2 NC formed

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correspondingly.

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2.2.2. Formulation of drilling muds

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Before the formulation of complex based mud using water as the base liquid, an unweighted

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spud mud was formulated with 320 ml fresh water, 25 ppb bentonite and 2.5 ppb caustic soda

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(NaOH) to test the effect of the synthesized PP–SiO
NC on the mud properties. 0.5, 1.0 and 1.5

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ppb of the synthesized PP–SiO
NC were added to the spud mud. Mud properties, such as pH,

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density, apparent viscosity (AV), plastic viscosity (PV), Yield point (YP), 10 seconds gel

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strength (10–s gel), 10 minutes gel strength (10–min gel) and API filtrate loss volume (API FL)

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were determined without aging the muds at at 25 °C. Thereafter, different complex based muds

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were formulated with concntrations of PP–SiO
NC and PHPA. They were used in the cuttings

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transport process. Table 2 contains the abbreviation of different complex based mud samples

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used in this study.

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Table 3 shows the summary of prepared various complex based muds used in the cuttings

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transport process. The complex WBM system was prepared with a fixed density of 9.5 ppg.

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Other complex based mud systems prepared with different concentrations of nanocomposite and

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PHPA have similar densities to that of complex WBM. Mud density range between 9.0 and 10

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ppg is the optimum drilling mud formulations for WBMs (Fattah and Lashin, 2016; Boyou et al.,

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2019). American Petroleum Institute (API) recommended practices of indoor fluid test criteria

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for water–based drilling fluids were followed to prepare the various mud systems (API RB 13B–

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1., 2017). The desired concentrations of PHPA and PP–SiO2 NC were added to the complex

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WBM and mixed thoroughly in Hamilton Beach stirrer at high speed. The mud properties were

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measured before aging at 25 °C and after aging for 16 hours at 150 °C. These two temperatures 6

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were selected because it is believed to contain the range of temperatures that can give a good

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interpretation of the behaviour of the PP–SiO2 NC. A standard of 1.0 g of additive is added to a

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350 ml laboratory barrel, to formulate the drilling mud samples, which is equivalent to adding

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1.0 pounds of additive to 1.0 barrels of mud. As shown in Table 3, the drilling muds were

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prepared in ascending order.

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2.2.3. Density and pH measurements

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The density of spud mud was measured using OFITE mud balance. The pH of spud mud was

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measured by a digital pH meter. A typical pH for a drilling mud should be between the range of

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8 and 10.

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2.2.4. Rheological and filtration properties measurements before and after hot rolling tests

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The rheology test of each sample of complex drilling mud was done by using a Brookfield 8–

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speed Viscometer, Model BF45 (Middleboro, MA, USA), following API protocols (API RP

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13B–1, 2017). Stabilized shear stress values were recorded against diferent shearing rates at

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600 rpm, 300 rpm, 200 rpm, 100 rpm, 6 rpm and 3 rpm. AV, PV, YP, 10–s and 10–min gels

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were measured at 25 °C before hot rolling tests. API FL was determined using a standard API

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Fann filter press, series 300, (Fann instrument company, Houston, Texas, USA). The test was

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conducted at ambient temperature and 100 psi differential pressure for 30 minutes, and the filter

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cake formed (API FCT) was determined. The test was conducted twice and average readings

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were taken. The thermal effects on the rheological and filtration properties of the complex based

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muds were measured after exposing them to a Fann 4–roller oven treatment for 16 hours at 150

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°C using Brookfield 8–speed Viscometer. The HPHT filtrate loss volume (HPHT FL) of the mud

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samples was measured by using a Fann HPHT filter press, series 387 (Fann instrument company,

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Houston, Texas, USA). The temperature in the heating jacket and the test pressure (differential

208

pressure) were 150 °C and 500 psi, respectively. For an accurate measurement of the HPHT FL

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and HPHT filter cake thickness (HPHT FCT), two readings were taken and the average values

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were recorded. The test procedures followed the API recommended standards (API RP 13B–1.,

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2017).

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2.2.5. Preparation of sand cuttings

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The simulated natural quartz grains (sandstones) used in the cuttings transport process are

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shown in Table 4. Cuttings were sieved into different range of diameters between 0.50 mm and

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4.00 mm following an American Standard Testing Method (ASTM D4253–00., 2006). Sand

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cuttings were washed and dried thoroughly before they were separated into different groups

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using a sieve shaker. Sand cuttings with a mass of 200 g were injected into the flow loop through

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cuttings inlet for each experiment.

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2.2.6. Simulation of drilled cuttings in a field–oriented cuttings transport flow loop

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Figure 3 shows the picture of a designed field–oriented cuttings transport flow loop used in

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the cuttings transport process. It shows the cuttings transport experiments starting from the mud

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preparation in a mud tank to the cuttings collection point. Figure 4 presents the experimental

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flow procedures used during the cuttings transport experiment. It describes how the grains of

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sand and muds were transported in a flow loop and the determination of CTE. Figure 5 presents

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the schematics of the annular test sections used to determine the performance of drilling muds in

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the cuttings transport process. These diagrams contain different test sections representing

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deviated wells (45 °, 60 °, and 75 °) and a horizontal well (90 °) from the vertical. The reason for

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selecting these hole angles is to target critical angles between the range of 45 ° and 60 °, as

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reported in previous studies (Boyou et al., 2019; Yeu et al., 2019).

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Ozbayoglu and Sorgun, (2010) used 3.66 m–long annular test sections to investigate cuttings

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transferring efficiency (CTE), and concluded that the annular test section provides reasonable

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precisions within 10% from the empirical correlations. In this study, the experimental parameters

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on CTE were evaluated in a field–oriented cuttings transport flow loop that was purpose–built to

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investigate cuttings lifting to the surface. The flow loop consists of an acrylic pipe, with an inner

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diameter of 69.85 mm and a rotatable inner drill pipe of outer diameter 26.67 mm centered inside

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the acrylic pipe to produce a concentric annulus model (0% eccentricity). These dimensions were

237

scaled–down by a factor of 0.8 from an actual drilled well, where a mud of 17.8 ppg with a flow

238

rate of 1438 L/min (litres per minute) was used to drill a 244.5 mm wellbore with an inner drill

239

pipe diameter of 139.7 mm (Ming et al., 2014).

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CTE was used to determine the ability of the complex based muds to lift drilled cuttings to

241

the surface. Different concentrations of 0.4, 0.5, 0.8 and 1.2 ppb PP–SiO
NC and PHPA were

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used to study the performance of the drilling muds in the cuttings transport process. The drilling

8

243

muds were evaluated with and without drill pipe rotation according to a previous study (Boyou et

244

al., 2019). Drill pipe rotation speed of 150 rpm was used for the cuttings transport investigations,

245

which is in agreement with the pipe rotation speed suggested for inclined wellbores (Sanchez et

246

al., 1999; Boyou et al., 2019).

247

According to Figures 3 and 4, weighted drilling muds of 9.5 ppg were prepared and mixed in

248

the mud tank, before they were circulated in the flow loop. A 2.0–HP centrifugal pump with the

249

capacity of 150 L (litres) mud tank attached to the mud pump was used to circulate the drilling

250

muds. 90 L (litres) of drilling mud, was prepared with the additives scaled–up by a factor of

251

257.1 (90,000 ml/350 ml). The pump capacity was between the range of 20 and 71 L/min. With

252

these pump capacities, the annular fluid flow regime with all the drilling muds was not fixed, but

253

was mainly annular laminar and transitional. The experiment was conducted using five different

254

mud velocities of 0.457 m/s, 0.630 m/s, 0.823 m/s, 0.960 m/s and 1.80 m/s. A 200 µm wire mesh

255

(0.2 mm) was used to separate the transported drilled cuttings from the circulating mud samples.

256

The drilled cuttings recovered were collected after every seven minutes of circulation and five

257

minutes of recirculation to flush out any remaining cuttings before performing a new experiment.

258

The experiment was conducted twice for each hole angle, mud velocity, and cuttings size. The

259

average readings of the CTEs were registered. The CTEs by the muds were evaluated using

260

Equation 1 below:

261

CTE =

262

3.

263

3.1. Properties evaluation of spud mud

      

            

       



(1)

Results and discussions

264

Spud mud is used to start the drilling of a well and continues to be used while drilling the

265

first few hundred feet of the hole. Spud mud is usually an unweighted WBM, made up of water

266

and natural solids from the formation being drilled. It may contain some commercial clay, such

267

as bentonite added to increase viscosity and improve wall-cake building properties. It is used to

268

drill a well from the surface to a shallow depth (Singh and Dutta, 2018). Table 5 presents the

269

rheological and filtrate loss control properties of unweighted spud mud measured at 25 °C. The

270

mud was prepared to examine the changes in the properties of drilling muds when different

271

concentrations of PP–SiO
NC were added.

9

272

pH analysis is fundamental to the control of drilling muds. The pH of the mud affects clay

273

dispersion, solubility, and the effectiveness of chemical additives. Additives of drilling fluids are

274

mixed with water to ensure a pH level from 8.5 to 10 for the needed chemical reaction to occur

275

and to provide a better mud yield (Singh and Dutta, 2018). Table 5 shows the pH levels of

276

unweighted spud mud with different concentrations of PP–SiO2 NC. According to Table 5, the

277

addition of PP–SiO2 NC to spud mud did not show much efect on pH and specifc gravity. The

278

pH level of the spud mud measured at 25 °C was 8.6. The pH levels of spud mud with PP–SiO2

279

NC remain unchanged up to a concentration of 1.0 ppb, but increased to 8.7 with 1.5 ppb

280

concentration of the nanocomposite. This behaviour is caused by increased –OH ions of NaOH

281

in the presence of nanocomposite, as higher concentrations can modify the pH of a liquid (Singh

282

and Dutta, 2018). Also, the dispersion stability of the nanocomposite in water may have

283

contributed to the change in the pH level at a higher concentration of 1.5 ppb (Mao et al., 2015).

284

Mud density controls the hydrostatic pressure in a well and prevents unwanted flow into the

285

well. Table 5 shows the results of the density of the spud mud with different concentrations of

286

PP–SiO2 NC. As Table 5 shows, there was no considerable variation in the density of the spud

287

mud with the addition of different concentrations of PP–SiO2 NC. The increase in density of

288

spud mud with concentrations of 1.0 ppb and 1.5 ppb of PP–SiO2 NC was caused by the higher

289

solids content in the spud mud with increasing concentration (Aftab et al., 2016).

290

AV, PV, YP, 10–s and 10–min gels, and API FL are other properties of the spud mud

291

investigated. These properties are shown in Table 5. The rheological parameters (AV, PV, YP,

292

10–s and 10–min gels) of the unweighted spud mud improved with increasing concentration of

293

PP–SiO2 NC. The addition of silica and copper oxide nanoparticles to both the drilling fuids did

294

not show much efect on pH and specifc gravity. This behaviour is due to the ability of PP–SiO2

295

NC particles to embed in dispersed pore structure on the surface of clay particles. They conferred

296

links with bentonite particles, which in turn promotes bentonite gelation and increase in particles

297

interaction (collision, vibration and movement) (Mao et al., 2015; Aftab et al., 2016). The API

298

FL of spud mud, was decreased from 12.7 ml to the range between 11.1 ml and 9.6 ml as the

299

concentration of PP–SiO2 NC increases. This behaviour is attributed to the efficient dispersion of

300

the PP–SiO2 NC particles on the surface of bentonite. Efficient dispersion of colloidal clays

301

(SiO2 NPs) gives a good overlap of particles, and hence, better control of leakage of liquid phase

10

302

of drilling fluid (Mao et al., 2015; Ismail et al., 2016; Aftab et al., 2016). From the data displayed

303

in Table 5, PP–SiO2 NC has the capacity to improve the properties of spud mud.

304

3.2. Rheological model of complex based muds

305

Drilling muds are non–Newtonian fluids, which implies the existence of a non–linear

306

relationship between shear stress and shear rate. Shear stress of drilling fluid describes the

307

pumping characteristics of the fluid. Shear stress plays an important role to distinguish between

308

Newtonian and non–Newtonian drilling fluids. Figures 6a and b show the plots of shear stress

309

versus shear rate of complex WBMs as a function of two temperatures (25 °C and 150 °C),

310

respectively. With an increase in concentration, the shear stresses of all the mud samples

311

increased with increasing shear rates from 5.11–1022 (1/s). This behaviour is caused by the

312

reduced volume of mud additives that hinders the movement of molecules of drilling muds (Mao

313

et al., 2015).

314

The trend lines or curves of the WBMs formulated with different concentrations of PHPA are

315

considerably higher than those of the WBMs related to PP–SiO2 NC both before and after heat

316

treatments. The pronounced increase in the rheological properties of PHPA mud samples was

317

caused by the interactions between PHPA molecules. This increases the viscosity of the drilling

318

muds proportionally to the molecular weight of the PHPA product (Kadaster et al., 1992; Hale

319

and Mody, 1993). With an increase in concentration of PHPA at a dial reading of 600 rpm from

320

0 to 1.2 ppb, the shear stress significantly increases. It increases between the range of 157% and

321

260% before hot rolling experiment (Figure 6a), and between the range of 118% and 179% after

322

hot rolling experiment (Figure 6b).

323

The presence of PP–SiO2 NC in the complex based mud also leads to an increase in shear

324

stress with increasing concentration. At the same temperature conditions, complex WBMs

325

containing PP–SiO2 NC increased the shear stress between the range of 24% and 38% before

326

heat treatment (Figure 6a). After heat treatment, the shear stress increased between the range of

327

34.8% and 51.1% (Figure 6b). This behaviour is caused by efficient dispersion and even

328

distribution of PP–SiO2 NC particles in the mud. This suggests that the presence of PP–SiO2 NC

329

in complex based mud requires less pump pressure to circulate the drilling muds during drilling

330

situations. When compared with PHPA drilling muds, PHPA mud requires a higher force to

331

circulate the mud and maintain the flow of the mud.

11

332

Figures 7a and b present the plots of apparent viscosities versus shear rates of all the drilling

333

mud samples before and after hot rolling experiments, respectively. Figures 8a and b show the

334

rotor speed of complex WBMs measured at dial readings between 3 rpm and 600 rpm. The

335

curves of both plots show a reduction in viscosity with an increase in shear rate from 5.11–1022

336

(1/s) (Figure 7). This behaviour suggests non–Newtonian pseudoplastic fluid, which is a

337

characteristic of shear–thinning fluid. This behaviour also implies that the complex WBMs has

338

less viscosity with increasing shear rates (Figure 8). As shear rate approaches zero, the drilling

339

muds became more viscous, indicating the capacity to suspend sand cuttings when circulation is

340

paused (Figure 7) (Boyou et al., 2019).

341

Most polymer solutions, such as PHPA behave as pseudoplastics. PHPA bearing mud

342

samples indicate higher viscosities with shear rates compared with PP–SiO2 NC samples, as can

343

be seen in Figures 6, 7 and 8. This behaviour is caused by high molecular weight of PHPA

344

product used. This product is a high molecular weight anionic polymer which stability and

345

efficiency in a drilling mud system depend on maintaining its concentration in the appropriate

346

range and controlling the clay content and solids to be within the desired range. If concentration

347

of PHPA is not kept within the appropriate range and the concentration of clays and solids is

348

cause to increase beyond the appropriate range, PHPA viscosity will increase the more. When

349

this behaviour occurs, anionic thinners (deflocculants) are required to stabilize the properties of

350

PHPA drilling muds.

351

As Figures 6b, 7b, and 8b show, the general trends of rheological properties of complex

352

based muds with PP–SiO2 NC at a temperature of 150 °C are similar to those of complex WBM

353

with PHPA. These rheological properties become lower when shear rate increases compared to

354

the mud samples before hot rolling tests, presented in Figures 6a, 7a, and 8a. This behaviour is

355

caused by the weakening of intermolecular attractive forces binding liquid molecules together.

356

As a result, increasing distance between molecules results, which reduces the mud’s molecule

357

interaction (Aftab et al., 2016; Ismail et al., 2016).

358

3.3. Rheological and filtration properties of complex based drilling muds

359

AV, PV, YP, YP/PV ratio and 10–s and 10–min gels before and after hot rolling experiments

360

were investigated to understand the rheological characteristics of formulated complex drilling

361

muds. These rheological data are shown in Figures 9 and 10. AV is the shear stress applied to

362

a fluid divided by shear rate. The AVs of BM with PHPA under temperatures of 25 °C and 150 12

363

°C significantly increased from 0.0 to 1.2 ppb. A lower increase of AVs occurred with PP–SiO2

364

NC mud samples compared to those of PHPA. However, the AV remained almost unchanged

365

between the concentrations of 0.8 and 1.2 ppb. According to Figures 9 and 10, PHPA mud

366

samples present a significantly higher value of AVs compared with those of PP–SiO2 NC drilling

367

muds. Before aging (Figure 9a), with an increase in the concentration of PHPA up to 1.2 ppb, the

368

AV of PHPA drilling mud, was 260% and 161% more than that of BM and PP–SiO2 NC,

369

respectively. The increase in the AV of PHPA mud sample is caused by the strong repelling

370

effect between the face or planar surface of bentonite and the negative surface carried by the

371

acrylate functions of the PHPA (Kadaster et al., 1992). Thus, there is a form of PHPA molecules

372

in complex WBM containing bentonite particles producing a maximum hydrodynamic volume

373

that leads to increase in viscosity of PHPA drilling muds (Borthakur et al., 1997). Another cause

374

of high AV of PHPA is that liquids having long–chain PHPA molecules, have a much higher

375

viscosity compared to liquids make up of small molecules (Gbadamosi et al., 2019). The AV

376

data of PHPA mud samples are much higher than those of PP–SiO2 NC at all concentrations,

377

which is caused by the high degree of entanglement between the long–chain PHPA molecules

378

(Gbadamosi et al., 2019).

379

PV of drilling mud is a measure of a fluid's resistance to flow. It describes the internal

380

friction of a moving fluid. A fluid with large viscosity resists motion because its molecular

381

makeup gives it a lot of internal friction. The greater is the resistance to the shear stress, the

382

greater is the viscosity (Caenn et al., 2017). Figures 9b and 10 contain the PV data of complex

383

WBMs. The shape of the bar of PV data is similar to that of AV data before and after hot rolling

384

experiments. Before hot rolling tests, the PVs of BM with PHPA considerably increases from a

385

concentration of 0.4 ppb. It reaches a maximum value of 39 mPa.s at a concentration of 0.8 ppb,

386

and then decreases by about 7.69% when a concentration of 1.2 ppb was used. This behaviour is

387

caused by the long–chain PHPA molecules, which increases the internal friction resulting from

388

the attraction between the molecules of the liquid. The observed PV data is in accordance with a

389

previous investigation (Borthakur et al., 1997). The authors reported that the addition of PHPA

390

into a bentonite–WBM system, caused a viscosity hump, demonstrating the encapsulating effect

391

of mud. The point at which the hump breaks vary with the molecular weight of PHPA, and with

392

the solids content in the mud.

13

393

The PVs of PP–SiO2 NC increases with an increase in concentration from 0.0 to 0.8 ppb, but

394

remained unchanged at 16 mPa.s for the concentration of 1.2 ppb at 25 °C. The unchanged PV

395

value of PP–SiO2 NC drilling muds can be attributed to the absence of particle agglomeration

396

caused by fine–dispersion of particles in complex WBM (Aftab et al., 2016). In addition, this

397

behaviour may have resulted due to defocculation of clay platelets. The increase in AVs and PVs

398

of BM with PP–SiO2 NC is caused by increase in linking of clay layers between the interparticle

399

interactions of PP–SiO2 NC. It is also caused by the linking of clay layers between PP–SiO2 NC

400

particles and bentonite particles (Mao et al., 2015; Aftab et al., 2016). The PV trend shown in

401

Figure 9b is comparable to that displayed in Figure 10.

402

After thermal aging experiments, the PV values of the mud samples decreased (Figure 9b).

403

With the increase in temperature up to 150 °C, the Brownian movement of fluid becomes

404

stronger, and consequently, the contact time and the time of interaction of the particles decreases,

405

resulting in less attraction between molecules. In addition, the adhesive forces between particles

406

and molecules as well as the interaction between NPs–molecules and molecules–molecules

407

decrease with an increase in temperature (Gbadamosi et al., 2019). According to Figure 9b, PV

408

values of BM with PP–SiO2 NC displays a lower thermal effect between the range of 13 and 15

409

mPa.s after aging, than those of PHPA mud samples, which reduces between the range of 19 and

410

30 mPa.s. This behaviour is because the high specific surface area of the micro‒nanosized

411

particles leads to more contributions to the specific heat given by the entropy of nanocomposite

412

than that of complex WBM and PHPA drilling muds systems (Mao et al., 2015). In drilling

413

environments, when drilling muds are circulated with the nanocomposite into the bottom of a

414

hole, more heat will be adsorbed than drilling with complex WBM and PHPA drilling muds.

415

This phenomenon will enhance the performance of drilling mud system of other additives to a

416

certain extent (Mao et al., 2015; Fattah and Lashin, 2016). From the preceding data, it can be

417

inferred that for the case of BM with PP–SiO2 NC, the impact of PP–SiO2 NC with the increase

418

in concentration on the viscosities (AV and PV) of BM was thickening. This observation can

419

again be explained due to the fact that PP–SiO2 NC tend to unite on the clay plates of bentonite

420

and increase the control of attractive forces between the clay plates.

421

YP is the resistance to the initial flow of fluid or the stress required to move the fluid. It can

422

be simply stated that YP is the attractive force between colloidal particles in drilling fluid (Luo et

423

al., 2017). Figures 9c and 10 present the data of YP of complex based muds before and after hot 14

424

rolling experiments. The BM was built to have a high YP and to achieve a YP/PV ratio greater

425

than 1.0 in order to drill the well rapidly and effectively. It is observed from these plots that there

426

is a significant variation in YP of BM containing PHPA and PP–SiO2 NC concentrations. The

427

YP values of PHPA drilling muds measured at 25 °C and 150 °C are significantly higher than

428

those of the nanocomposite mud samples. They are found between the range of 66 and 108 Pa

429

(Figure 9c) and between the range of 56 to 65 Pa (Figure 10). In both temperature conditions, YP

430

values of PHPA drilling muds are above the recommended operating limits, which is between

431

the range of 10 and 45 Pa (API RB 13B–1, 2017). This behaviour is caused by frictional pressure

432

loss, which is directly related to YP. So, a significantly higher pressure loss and increased ECD

433

were experienced in PHPA mud samples during the circulation of the drilling muds, compared

434

with that of complex WBM and those of PP–SiO2 NC drilling muds. The reason for this

435

behaviour is due to high viscous nature of PHPA drilling muds. The range of YPs of the PHPA

436

makes it difficult to pump the mud from the mud tank because more pressure was needed to

437

suppress the shear stress. In addition, the presence of NaOH, Na2CO3, xanthan gum, the

438

dissolution of the PHPA solids and perhaps some contaminants in the mud might have

439

contributed to increasing the YP of the PHPA drilling muds (Liao and Siems, 1990; Lam et al.,

440

2015).

441

As Figures 9c and 10 show, the YP data of BM with PP–SiO2 NC are found between 36 and

442

37 Pa before heat treatment. After heat treatment, YP of PP–SiO2 NC drilling muds reduced

443

between 32 and 35 Pa. In both temperature conditions, these YP values are within the

444

recommended operating limits (API RB 13B–1, 2017). The addition of PP–SiO2 NC into the

445

complex based mud increases the liquid attractive forces due to the relatively high average

446

specific surface area of the nanocomposite (Oseh et al., 2019). PP–SiO2 NC can maintain the

447

desired pump pressure by reducing ECD better than PHPA. The AV, PV, and YP data of PP–

448

SiO2 NC are consistent with previous studies (Mao et al., 2015; Aftab et al., 2016; Boyou et al.,

449

2019). The YP values of PHPA mud samples reduced after heating more than those of the PP–

450

SiO2 NC drilling muds, which is indicative of the more increased kinetic energy of liquid

451

molecules in PHPA mud samples. This is caused by weakening intermolecular attractive forces

452

(Kadaster et al., 1992; Hale and Mody, 1993).

453

Therefore, it is submitted that along with increase in the value of YP, PP–SiO2 NC showed

454

signifcant amount of temperature stability with increase in their concentration more than that of 15

455

PHPA. If this property persists for even higher values of temperature, it holds a lot of promise in

456

the HPHT environments. In most drilling operations, drilling fluids with lower PVs and higher

457

YPs are often desired to effectively circulate the mud without inducing undue frictional pressure

458

loss, provided that these parameters can drill the well as fast as possible at a low drilling cost

459

(Lashin and Fattah, 2016; Luo et al., 2017). The reason is that higher YP gives strong shear

460

thinning feature and increased transport of solid particles, and lower PV with high flow rate

461

provide turbulence at the drill bit to increase the transport of solid particles to the surface

462

(Ozbayoglu and Sorgun, 2010; Luo et al., 2017).

463

The YP/PV ratio (i.e., the slope of PV-versus-YP line) is a significant indicator of drilling

464

fluid conditions. The carrying capacity property (YP/PV ratio) can be used to determine the

465

stability of drilling fluids (Luo et al., 2017). The YP/PV ratios of complex based muds were

466

evaluated to describe the effect of PP–SiO2 NC and PHPA on mud's cuttings transport capacity

467

and suspendability. These ratios are presented in Figures 9d and 10. Typically, values of YP/PV

468

greater than 0.75 indicate a good transport capacity behaviour of drilling muds. It can provide a

469

better wellbore cleaning performance (Luo et al., 2017). The increase in YP/PV ratio will slowly

470

flatten flow profile to enhance fluid transport capacity. From these plots, the drilling muds show

471

good hole cleaning ability and cuttings suspendability. This is because they demonstrated high

472

values of YP/PV ratio greater than 0.75 both before and after hot rolling experiments.

473

The BM shows the best hole cleaning and suspension ability than the PP–SiO2 NC drilling

474

muds and the PHPA mud samples at 25 °C, except with that of 1.2 g PHPA concentration. This

475

illustrates that cuttings recovery at the surface will occur with or without nanocomposite and

476

PHPA in the mud. At the concentrations of 0.8 and 1.2 ppb, PHPA displayed better cuttings

477

transport capacity and suspendability than PP–SiO2 NC. Nevertheless, at concentrations of 0.4

478

ppb (Figure 9d) and 0.5 ppb (Figure 10), the wellbore cleaning ability and cuttings

479

suspendability of PP–SiO2 NC is better than that of PHPA. After hot rolling experiment, YP/PV

480

values of PP–SiO2 NC decreases with increasing concentration between 0.4 to 1.2 ppb, from 2.46

481

to 2.33, while that of BM reduced to 2.0, and those of PHPA drilling muds showed a higher

482

decrease from 2.94 to 2.0. This behaviour is caused by the higher effect of temperature on PHPA

483

molecules compared with the PP–SiO2 NC particles.

484

The gel strength (10–s and 10–min gels in the standard API procedure) is the shear stress

485

measured at a low shear rate after a mud has set quiescently for a while. It is one of the 16

486

important drilling fluid properties because it demonstrates the ability of the drilling mud to

487

suspend drilled solid and weighting material when circulation is paused. The more the mud

488

gels during shutdown periods, the more pump pressure will be required to initiate circulation

489

again (Luo et al., 2017). Figures 9e and 10 show the 10–s and 10–min gels of mud samples

490

before and after hot rolling experiments. The plots show that 10–s and 10–min gels of BM

491

increases with addition of PHPA and PP–SiO2 NC concentrations. 10–s and 10–min gels data

492

related to PHPA mud samples are significantly higher than those of PP–SiO2 NC before and after

493

hot rolling tests. This behaviour is caused by the anionic character of PHPA product used (Lam

494

et al., 2015). This suggests that attractive intermolecular forces (gelation phenomenon) are

495

higher in PHPA bearing mud samples compared to complex BM and PP–SiO2 NC drilling muds,

496

as AV, PV, and YP data show.

497

Before thermal aging tests, the PHPA mud sample at 0.4 ppb (Figure 9e) and 0.5 ppb (Figure

498

10) present a large difference in 10–s and 10–min gels compared to other mud samples. This

499

shows the potentials of high flat gel or progressive gel at PHPA concentrations of 0.4 and 0.5

500

ppb in the complex WBM. High flat gel or progressive gel is undesirable and can result in a pipe

501

sticking problems during drilling operations. It requires greater pumping to break the gels and

502

resume mud circulation (Luo et al., 2017). It can also make the mud to become static and block

503

drilled cuttings from flowing out of the wellbore. These types of gel occur when there is a high

504

gel strength development with time (Bizhani et al., 2016; Lashin and Fattah, 2016). A low gel

505

will lead to the cuttings dropping to the bottom of the annulus when the pump is switched off.

506

Therefore, low flat gels are desired for drilling operation than low gels or high flat gels or

507

progressive gels. Gel strength should not be much higher than required, but high enough to

508

suspend and keep drilled cuttings in suspension, especially at critical hole angles. According to

509

the data presented in Figures 9e and 10, BM with PP–SiO2 NC before and after hot rolling tests

510

are more capable of suspending cuttings in deviated and horizontal wells. This is because the

511

variation in the 10–s and 10–min gels are not too high compared with those of PHPA drilling

512

muds. Apart from noticing a low flat gel with concentration of PP–SiO2 NC, it also induced the

513

property of heat resistance, which helped to preserve the gels at bottom–hole conditions. This

514

characteristic will guarantee proper suspension of rock/sand cuttings and barite, thereby

515

preventing sagging issues (Lashin and Fattah, 2016).

17

516

Filtrate volume and filter cake thickness at both API and HPHT conditions are other

517

rheological properties measured. Figures 9f and 10 present the data of these properties.

518

According to the plots, there is no much variation in the API FL of PHPA and PP–SiO2 NC over

519

that of BM. The API FL of BM was 11.8 ml, and with PHPA concentrations in BM, it reduces to

520

the range of 8.5–6.5 ml with increasing concentration. The API FL of BM with PHPA was best

521

controlled by 1.2 ppb PHPA concentration, which allows 6.5 ml loss of drilling fluids. PHPA–

522

bentonite clay drilling muds tend to form a relatively thin filter cake on the wall of the wellbore,

523

a characteristic often cited as an advantage for using PHPA in bentonite–based drilling mud

524

system (Liao and Siems, 1990). The sealing behaviour of long–chain PHPA molecules is caused

525

by the degree of hydrolysis and the hydration group in the molecular chain of PHPA, which are

526

typical characteristics of its molecules. These characteristics make PHPA hydration better, which

527

change PHPA as a flocculant into filtrate loss reducing agent (Liao and Siems, 1990; Hale and

528

Mody, 1993). In general, adding different concentrations of PP–SiO2 NC into complex based

529

mud showed least degradation in rheological properties compared to other fuids (BM and PHPA

530

muds).

531

The API FL of PP–SiO2 NC in BM ranges between 8.0 and 6.4 ml. It is more capable to

532

control loss of drilling fluids than the PHPA drilling muds. This behaviour is caused by the

533

enhancement in viscosity of BM containing PP–SiO2 NC, which has a consistent rheological

534

trend. Furthermore, the rapid creation of low filter cake caused by low permeability of PP–SiO2

535

NC is another reason for the efficient sealing behaviour of the PP–SiO2 NC (Mao et al., 2015;

536

Boyou et al., 2019). Also, PP–SiO2 NC was well–dispersed in the drilling mud, which provides a

537

wider distribution and stability of particles in the mud. Efficient dispersion and stability of

538

colloidal clays in the mud gives a good overlap of particles; thus, providing good filtration

539

control property (Aftab et al., 2016). The BM with PHPA shows higher loss of drilling fluids

540

than PP–SiO2 NC mud samples, due to the high viscous nature (gelation phenomenon) of the

541

PHPA mud samples that leads to mud’s flocculation. A flocculated mud, such as PHPA which

542

has aggregates of particles, will allow fluid to pass through easily (Hale and Mody, 1993).

543

Overall, the filtrate loss is best controlled for A–1.2 by adding 1.2 ppb PP–SiO2 NC that reduced

544

it by 45.8%. This phenomenon takes place as the nanocomposite sealed the pore spaces and

545

prevents a clear passage for the mud to seep.

18

546

An increase in temperature has the effect of minimizing the viscosity of liquid phase, thereby

547

causing an increase in filtrate loss volume. As Figures 9f and 10 show, the HPHT FL of the

548

complex drilling mud samples increases after thermal aging experiments. Just like the trend of

549

API FL under API conditions, HPHT FL of BM with PP–SiO2 NC were lower than those of

550

PHPA drilling muds. This behaviour is because PP–SiO2 NC particles formed a tighter packing

551

structure through the filter cake, which effectively sealed the openings between the micron–sized

552

particles that would otherwise allow the fluid to flow (Mao et al., 2016). Furthermore, this

553

behaviour can be due to the fact that PP–SiO2 NC particles did not agglomerate with increasing

554

concentrations and due to overall less–viscosity reduction of the mud, as compared to PHPA

555

mud samples. The more filtrate loss into the formation, the more the filter cake thickness.

556

Figures 9f and 10 present the API and HPHT FCT of complex based muds. Based on these

557

figures, no significant variation exists in the API and HPHT FCT of both PHPA and PP–SiO2 NC

558

mud samples. These data inferred that BM when blended with PP–SiO2 NC presented a significantly

559

reducing trend of filtrate loss of drilling mud with increase in concentration of the nanocomposite

560

additive.

561

3.4. Flow dynamics of complex based muds without drill pipe rotation speed

562

3.4.1. Effect of different concentrations of PP–SiO2 NC and PHPA on CTEs

563

In terms of drilling muds performance in cuttings lifting process of different cuttings

564

diameters, 0.4, 0.8 and 1.2 ppb concentrations of PP–SiO2 NC and PHPA without pipe rotation

565

speed was used. 0.5 ppb concentration of both PP–SiO2 NC and PHPA in BM was used when the

566

rotation speed of drill pipe was set to 150 rpm. These data are represented in Figures 11, 12, 13,

567

and 14. According to these plots, when the PP‒SiO
NC concentrations were added into the

568

BM, the lifting of cuttings increases with increasing concentration. On the other hand, adding

569

PHPA into the BM decreases the percent cuttings recovery of the BM with increasing

570

concentration. The PHPA drilling mud at 0.4 ppb concentration demonstrates higher CTEs than

571

other PHPA concentrations (0.8 and 1.2 ppb). The PHPA drilling muds with compositions of B–

572

1.2 performed the least, while A–0.8 and A–1.2 of nanocomposite showed higher CTEs than

573

PHPA concentrations. This is because the presence of nanocomposite in BM was able to increase

574

the colloidal forces, which increases the interaction between drilled cuttings and nanocomposite

575

particles to keep upward movement of cuttings towards the surface (Samsuri and Hamzah, 2016;

19

576

Boyou et al., 2019). The plots confirmed 1.2 ppb concentration (A–1.2) of PP–SiO2 NC to

577

produce the largest CTE due to more decrease in the distance between the particles, linking of

578

clay layers and increase in Van der Waal forces with increasing concentration (Kök and Bal,

579

2019).

580

With 0.4 g PHPA concentration, the muds were effectively circulated with the mud velocity

581

between the range of 0.457 and 0.960 m/s; hence, better cuttings lifting than 0.4 ppb PP–SiO2

582

NC concentration and larger PHPA concentrations of 0.8 and 1.2 ppb. This suggests that 0.4 ppb

583

is the optimum concentration of PHPA drilling muds. The better CTEs of BM with 0.4 ppb

584

PHPA concentration is due to the ability of PHPA to improve the fluid drag by flocculating the

585

cuttings, and subsequently, causing a decrease in the resultant drag effects on cuttings (Hale and

586

Mody, 1993; Ercan and Ozbayoglu, 2009; Lam et al., 2015). Besides, several findings have

587

shown that PHPA as a drag–reducing agent is more effective at low concentration (Ercan and

588

Ozbayoglu, 2009; Lam et al., 2015). This is because of the low content of high molecular weight,

589

drag reducing polymers with enough flow rate, which reduces the turbulent spurts in the buffer

590

layer of pipes (Ercan and Ozbayoglu, 2009).

591

The nature of BM with 0.8 and 1.2 ppb PHPA concentrations during the experiments showed

592

a highly thick–jelly mud, which was very difficult to stir and circulate with mud velocities

593

between the range of 0.457 and 0.960 m/s. This phenomenon is due to the ability of long–chain

594

molecules of the polymer to increase entanglement according to its hydrodynamic size (Hale and

595

Mody, 1993). The pump was not able to effectively circulate and distribute muds in the flow

596

loop to cause turbidity of flow stream. Turbidity of flow stream promotes uniform distribution of

597

cuttings in wellbore because it minimizes cuttings concentration to one side of the hole (Yeu et

598

al., 2019). This behaviour drastically reduced the lifting capacity of PHPA mud samples at

599

higher concentrations of 0.8 and 1.2 ppb. The high viscosities of PHPA drilling muds will need

600

enough flow rate to circulate, in order to minimize frictional pressure loss, reduce ECD and

601

subsequently, prevent a pipe sticking incident. Furthermore, care should be taken in selecting the

602

additives that will be used together with PHPA in a complex WBM system. The addition of

603

anionic thinners (deflocculants) to complex WBM containing PHPA under the prevailing

604

conditions can contribute to controlling the mud flocculation, and subsequently, decrease the

605

rheological parameters of the PHPA drilling muds (Ismail et al., 2019).

20

606

Other important findings shown in Figures 11, 12, 13 and 14 is that the CTEs of 0.4 ppb

607

concentration of PP–SiO2 NC (i.e. between the range of 44.7 and 68.2%), at the lowest mud

608

velocity of 0.457 m/s are more than those of BM that lies within the range of 41.2 and 53.8%.

609

This shows the ability of the nanocomposite to enhance the lifting capacity of complex drilling

610

mud system. This enhancement can contribute to minimizing cuttings settling out of the mud

611

when the circulation velocity is not high enough to overcome gravitational force acting on sand

612

cuttings (Ramsey, 2019). Overall, increase in concentration of nanocomposite display better

613

enhancement in the properties of BM to lift cuttings, compared with BM and PHPA

614

concentrations. The reason for this behaviour is that PP–SiO2 NC particles are well–dispersed in

615

BM, which makes water to absorb into it and becomes agglomerated. These phenomena will

616

increase the viscosity of drilling muds (Samsuri and Hamzah, 2016). Furthermore, as reported in

617

a previous recent study by the authors, the designed PP–SiO2 NC particles are in a micro–

618

nanosized. The size of these particles are distributed between 80 and 390 nm. They have a

619

relatively high specific surface area of 13.7 m2/g. These characteristics enable the PP–SiO2 NC

620

particles to increase the drag and lift forces on the rock cuttings to overcome the effect of

621

gravitational and cohesive forces, that further increased cuttings lifting to surface (Oseh et al.,

622

2019).

623

3.4.2. Effect of hole angles on CTEs using complex based muds

624

The effect of hole angles on CTEs of the designed complex based muds is presented in

625

Figures 15, 16, 17 and 18. According to these figures, the shapes or trend lines of CTEs for all

626

the hole angles are almost similar. The CTEs increases with increasing hole angles. The plots

627

also demonstrate that the CTE decreases with increasing cuttings diameter, and increases with

628

increasing mud velocity. The highest CTEs occurred in a horizontal annulus (90 °). This is

629

attributed to the dominant force (the axial drag force) related to the flow of the mud, which was

630

not affected by the hole deviation. As a result, the cuttings were stable and does not avalanche

631

(slip downward) (Yeu et al., 2019). Next, the CTEs at 75 ° is the second–highest because of less

632

decreased in the resultant axial drag force against gravitational force (Ernesto et al., 2016;

633

Heshamudin et al., 2019). The second–lowest hole angle in the cuttings transport process was 60

634

° inclinations, while the lowest observed CTEs occurred at 45 ° inclinations, and is the most

635

problematic inclination in the cuttings transport process. This hole angle (45 ° inclination) needs

21

636

attention while preparing drilling mud. Hole inclinations 45 ° and 60 ° are often referred to as

637

critical hole angles and they experienced the lowest CTEs. The reason for this behaviour is

638

because the lift forces which dominate cuttings lifting in a vertical annulus are significantly

639

decreased when hole angle increases. Thus, the resultant drag forces against gravitational forces

640

are lower; the cuttings then become unstable, and therefore, tend to avalanche (slip downward)

641

(Ernesto et al., 2016; Yeu et al., 2019). Furthermore, at these critical hole inclinations, cuttings

642

only have a few metres to cover before hitting the wall of wellbore compared to vertical portion

643

of the annulus, where cuttings have enough space to travel. This results in a reduction in the

644

vertical component of the fluid velocity, and consequently, increased cuttings slip velocity

645

(Ozbayoglu et al., 2008; Yeu et al., 2019).

646

About different diameters of cuttings, the trend lines demonstrated in Figures 15, 16, 17 and

647

18 showed that the CTEs decreases with an increasing cuttings diameter. This behaviour is

648

caused by the differences in the densities of these cuttings (Hakim et al., 2019). According to the

649

plots, transport of smallest cuttings is more simplified compared with largest cuttings. Smallest

650

cuttings of 0.50–0.99 mm (Sand A) were easier to clean out compared with intermediate‒size

651

cuttings. Intermediate‒size cuttings (Sand B and Sand C) were easier to lift than the largest

652

cuttings (Sand D). The transport of largest cuttings is dependent on its settling velocity (Wei et

653

al., 2013; Bizhani et al., 2016). The settling velocity of large cuttings is substantially high,

654

compared to those of small and intermediate–size cuttings (Wei et al., 2013). Consequently, it

655

has the greatest tendency to drop to the bottom of the hole. However, from the drag force

656

formula given in Equation 2, a larger particle suggests a higher drag force, and a larger particle

657

should have a larger weight effect compared to a smaller particle. Thus, a larger particle should

658

experience a higher drag force to balance the gravitational force. This effect helps to promote the

659

transport of larger cuttings (Wei et al., 2013). The transport of larger cuttings will increase with

660

an increasing flow rate (Heshamudin et al., 2019). These findings are similar to those reported by

661

Heshamudin et al., (2019) and Yeu et al., (2019). These authors concluded that in rock cuttings

662

transport, cuttings diameter has a very small effect on transport performance and cuttings build‒

663

up on the low side of the hole.

664

F = 6π uR

665

F is drag force,  is the viscosity, u is average velocity and R is the particle diameter

666

3.4.3. Effect of mud velocities on CTEs of PP–SiO2 NC and PHPA drilling muds

(2)

22

667

Before determining the effect of pipe rotation on CTE conducted with complex WBM and

668

drilling muds compositions of A–0.5 and B–0.5, mud velocity was increased to 1.80 m/s, which

669

is about 87.5% higher than the optimum mud velocity of 0.960 m/s applied in the cuttings

670

transport process presented in Figures 11, 12, 13, 14, 15, 16, 17, and 18. The mud velocity of

671

1.80 m/s was applied to only the complex WBM and compared with other mud velocities

672

between the range of 0.457 and 0.960 m/s. The reason is to select the mud velocity that can

673

effectively circulate the drilling muds, in particular, the compositions of PHPA drilling muds.

674

The CTEs of complex WBM with different mud velocities with no pipe rotation are shown in

675

Figures 19a and b for Sand A and Sand D, respectively. At the highest mud velocity of 1.80 m/s,

676

the CTEs of both Sand A and Sand D gives the best transportation of drilled cuttings compared

677

with other mud velocities between the range of 0.457 and 0.960 m/s. The CTEs of drilling muds

678

increases as the mud velocity increases to 1.80 m/s. This behaviour is attributed to the formation

679

of turbulent eddies (Ramsey, 2019; Yeu et al., 2019). The CTEs of Sand D (Figure 19b) are

680

between the range of 31.5% and 60.1% when mud velocities in the range between 0.457 and

681

0.960 m/s were used. On the other hand, the CTEs of drilling muds improved to the range

682

between 68.8% and 81.2% when the mud velocity was maximum at 1.80 m/s.

683

According to both plots shown in Figures 19a and b, Sand D have better CTEs than Sand A.

684

This further confirmed the cuttings transport of larger cuttings size to largely depend on

685

increasing mud velocity, which is consistent with a previous study that indicated the transport

686

capacity of WBM of larger cuttings to mainly depend on mud velocity and density (Wei et al.,

687

2013). From the trend lines, the CTEs increases with increasing mud velocity at all hole angles.

688

The effect of mud velocity of 1.80 m/s is higher in the largest cuttings size (Sand D) compared

689

with the smallest cuttings (Sand A). However, Sand A showed better recovery of cuttings with

690

mud velocities between 0.457 and 0.960 m/s. At horizontal portion of the hole, the CTE of Sand

691

A with mud velocity of 1.80 m/s is 4.31% higher than that of mud velocity of 0.960 m/s, while

692

the CTE of Sand D with a mud velocity of 1.80 m/s shows 35.1% more than that calculated with

693

0.960 m/s at the horizontal annulus.

694

3.4.4. Effect of drill pipe rotation on CTE using complex based muds

695

Drill pipe rotation is one of the optimization tools for a higher CTE (Sanchez et al., 1999;

696

Ozbayoglu and Sorgun, 2010). With drill pipe movement, either in rotation/reciprocation or

697

centralization, cutting beds on the low side of the hole are mechanically disturbed and exposed to 23

698

the top portion of the annulus where the fluid circulation rate is higher (Boyou et al., 2019). The

699

drilling muds with the compositions of A–0.5 and B–0.5 and mud velocity of 1.80 m/s were used

700

to determine the effect of drill pipe rotation on CTE. The complex based mud with 0.5 ppb

701

concentration of PP–SiO
NC and PHPA was designed owing to the gelation of the PHPA (B‒

702

0.8 and B‒1.2) mud samples. The performance of 0.5 ppb concentration of PP–SiO
NC and

703

PHPA without pipe rotation was compared with that of drill pipe rotation speed of 150 rpm.

704

Sand A and Sand D were chosen because Sand A (0.50–0.99 mm) happens to be more easier in

705

the transport process, while Sand D (2.80–4.00 mm) is the most difficult in the cuttings transport

706

process. The data of these drilling parameters with and without drill pipe rotation are shown in

707

Figures 20 and 21, respectively.

708

According to Figure 20, BM with 0.5 ppb concentration of PP–SiO2 NC lifted the highest

709

cuttings to the surface with and without inner pipe rotation than those of BM and PHPA mud

710

samples. The CTEs of BM with 0.5 ppb concentration of PP–SiO
NC at critical hole angles 45

711

° and 60 ° increased by 14.3% and 12.4%, respectively, while those of BM with 0.5 ppb

712

concentration of PHPA improved by 15.9% and 16.4%, respectively, with no pipe rotation. This

713

behaviour is because higher mud velocity was used to circulate the less–viscous PHPA mud

714

compared to those of B–0.8 and B–1.2. PHPA can enhance the transport of sand cuttings by

715

flocculating the sand cuttings and reducing the drag force acting on the sand cuttings if its

716

concentration and clay content are kept within the proper range (Hale and Mody, 1993). The

717

mud samples circulated with a drill pipe rotation speed were more capable of circulating drilled

718

cuttings than those circulated without pipe rotation. This is because drill pipe rotation induces

719

centrifugal force in the annulus that mechanically exposed sand cuttings to where there are

720

higher flow rates (Ozbayoglu and Sorgun, 2010).

721

In terms of cuttings diameter, complex WBM shows the lowest CTEs for the two diameters

722

of cuttings investigated. The larger cuttings diameter (2.80–4.00 mm) produced the highest CTEs

723

at all hole angles. This finding is contrary to the earlier data presented in Figures 11 to 18, where

724

CTEs of drilling muds reduces with increasing cuttings diameter. This indicates that the transport

725

of smallest cuttings (0.50–0.99 mm) are more dominated by mud viscosity than mud velocity, as

726

reported by Duan et al., (2008). About drill pipe rotation, this finding is contrary to the report by

727

Duan et al., (2008). They pointed out that the recovery of small cuttings with pipe rotation is up

728

to twice as large as those of recovered large cuttings. Nevertheless, the result obtained in this 24

729

section is in accordance with those reported by other previous authors (Sanchez et al., 1999;

730

Boyou et al., 2019). These authors reported that fluid flow rate with drill pipe rotation speed is a

731

key factor that controls the transport of large cuttings, unlike the transport of small cuttings that

732

are mainly dominated by fluid rheology. The diameters of cuttings used in this study are within

733

the range of cuttings used in these previous studies.

734

Figure 21 illustrates that drill pipe rotation speed will be more effective at deviated

735

wellbores. Nevertheless, it is more efficient in the horizontal portion of the annulus. Largest

736

cuttings (2.80–4.00 mm) shows higher cuttings recovery than smallest cuttings (0.50–0.99 mm).

737

This behaviour is caused by enough mud velocity that reduced the gravitational forces acting on

738

the largest cuttings (Boyou et al., 2019). At the most critical hole angle of 45 ° (as shown in this

739

study), drill pipe rotation speed increased the CTE of the BM by 2.7% (Sand A) and by 9.3%

740

(Sand D), confirming the higher effect of pipe rotation speed on largest cuttings size. According

741

to Figures 20 and 21, drill pipe rotation speed of 150 rpm can produce a CTE range between

742

68.4% and 79.4% (Sand A), and between the CTE range of 70.4% and 96.2% (Sand D). On the

743

other hand, CTEs conducted without pipe rotation speed are between the range of 66.4% and

744

77.4% (Sand A) and between the range of 68.8% and 86.3% (Sand D) circulated with a mud

745

velocity of 1.80 m/s. Therefore, in the design of cuttings transport process, drill pipe rotation

746

speed and enough mud velocity need to be considered for a higher CTE.

747

From the overall results obtained, mud velocity, rheological properties, and diameter of

748

cuttings have an impact on cuttings transport. The performance of these parameters depends on

749

the concentration at which pump circulation is more effective without inducing frictional

750

pressure losses. The concentrations of PP–SiO2 NC in complex WBMs were able to increase the

751

viscosity that enhanced the mud’s carrying capacity of drilled cuttings. It enhanced the heat

752

transfer and increased the stability of the complex WBM, which led to increased lift and drag

753

forces on the drilled cuttings. With these phenomena, surface forces can overcome gravitational

754

forces acting on drilled cuttings, which can easily move cuttings upward towards surface

755

(Samsuri and Hamzah, 2016).

756

3.5. Sand cuttings interaction with polypropylene–nanosilica drilling muds

757

In general, the mechanism that contributed to improving the cuttings lifting of PP–SiO
NC

758

drilling muds is elucidated further by using a simplified description of the mud–cuttings

759

interactions presented in Figure 22. The presence of PP–SiO
NC in complex WBM offers a 25

760

wider distribution of particles in the mud. Since the particles were well‒dispersed, they are

761

spaced evenly and scattered all through the mud. As the mud moves upward in the annulus either

762

by annular laminar, transitional or turbulent, the nanocomposite provides increased colloidal

763

forces and a stronger particle–sand cuttings interaction due to the adsorption between bentonite

764

particles and the nanocomposite (Omurlu et al., 2016; Al–Yasiri et al., 2019). The upward

765

movement of nanocomposite particles in the mud follows the flow stream of complex based

766

mud. As the flow of mud moves the cuttings and nanocomposite particles, the interparticle

767

interaction between the PP–SiO
NC and sand cuttings increased (Figure 22). This occurrence

768

was possible because nanocomposite particles have a characteristic of a relatively high average

769

specific surface area of 13.7 m²/g, and are small enough, as indicated by their size distributed

770

between 80 and 390 nm (Oseh et al., 2019). These factors contribute to increasing the drag and

771

lift forces on cuttings to overcome gravity and cohesive forces. This behaviour, promote an

772

increase in the cuttings transport process of nanocomposite drilling muds (Boyou et al., 2019).

773

4. Cost feasibility of drilling muds

774

Cost feasibility is an important factor in decision making for the oil and gas industry. Cost

775

feasibility is the simplest way of comparing options to ascertain whether to go ahead with a

776

project. The notion is to weigh up project costs against benefits, and identify the action that will

777

give the most benefit for a project (Sawsan et al., 2019). Table 6 shows the actual cost of

778

chemicals used in synthesizing PP–SiO2 NC product, while Table 7 represents the formulation

779

costs of the complex based mud (BM), BM + PHPA and BM + PP–SiO2 NC. The chemicals

780

acquired were scaled to the actual cost used in designing the drilling muds. According to Table 7,

781

the cost of designing the BM was 21.00 USD. When the concentrations of PHPA and PP–SiO2

782

NC were scaled to 2.9 ppb (sum of 0.4, 0.5, 0.8, 1.2 ppb) and added to the cost of preparing the

783

BM, the cost of preparation increased to 21.823 USD and 22.969 USD for PHPA and PP–SiO2

784

NC drilling muds, respectively. The increment in the cost of designing the BM with the PHPA

785

product was 3.92%, while that of the BM with the PP–SiO2 NC showed 9.38%. Based on this

786

data, cost comparison shows the more beneficial cost of designing the BM with PHPA than the

787

BM with PP–SiO2 NC with a cost difference of 1.146 USD.

788

The designed nanocomposite is under laboratory studies. If introduced into the market, it

789

might attract interest from industries, operators, and researchers, due to its sterling rheological

26

790

and filtration characteristics. These characteristics can usher in new and cost–saving methods of

791

its synthesis. For example, from the data that were shown in Table 6, about 230 g of chemicals

792

used in synthesizing the nanocomposite yielded 41.8 g of PP–SiO2 NC product and the synthesis

793

cost 20.091 USD, whereas procured 250 g commercial PHPA cost as much as 71.10 USD (Table

794

7). This implies that a more cost–saving and efficient method of synthesis can recover more yield

795

of PP–SiO2 NC at a reduced cost. In addition, under large scale productions, cost of chemicals

796

that might be needed to design the PP–SiO2 NC will be more cost–effective than the cost of

797

production under laboratory scale. The designed nanocomposite shows better performance in the

798

control of filtrate loss and modifying the rheological properties of complex drilling mud than the

799

PHPA. Based on these characteristics demonstrated by the designed nanocomposite, its

800

application for drilling operations might not erode drilling economics when used in a complex

801

based mud.

802 803 804

5. Conclusions

805

The article focuses on the improvement of the rheology and filtration properties of complex

806

based mud by PP–SiO2 NC and PHPA. It also describes a study of cuttings transferring

807

efficiency test for drilling under a fluid environment where PP–SiO2 NC and PHPA exists. Its

808

main focus was on how different concentrations (0.4, 0.5, 0.8 and 1.2 ppb) of PP–SiO2 NC and

809

PHPA performed in a field–oriented cuttings transport flow loop under different drilling

810

parameters, such as hole angles (45, 60, 75 and 90 °), mud velocities (0.457, 0.630, 0.823, 0.960

811

m/s and 1.80 m/s) and cuttings size range between 0.50 and 4.00 mm. A concentration of 0.5 ppb

812

at a maximum mud velocity of 1.80 m/s was used to determine the transport of Sand A (0.50–

813

0.99 mm) and Sand D (2.80–4.00 mm). The cuttings carrying capacity of PP–SiO
NC and

814

PHPA with and without pipe rotation speed of 150 rpm were evaluated and compared.

815

Before the complex drilling muds were prepared, a spud mud was formulated using fresh

816

water, bentonite, and NaOH. Different concentrations (0.5, 1.0 and 1.5 ppb) of PP–SiO
NC

817

were added to the spud mud to determine the changes of spud mud properties with the designed

818

nanocomposite. The presence of PP–SiO
NC was able to enhance the AV, PV, YP, 10–s and

819

10–min gels and API FL of the spud mud due to its fine–dispersion in the mud. Thereafter, 27

820

complex drilling muds with nanocomposite were prepared. They improved the rheological and

821

filtration properties, which enhanced the transport capacity of BM to lift sand cuttings easily to

822

surface than PHPA drilling muds. The rheological properties of complex based mud with PHPA

823

under the investigated conditions needs attention, in order to avert stuck pipe incident, increase

824

frictional pressure loss and ECD, and high pump pressure requirement. This scenario will be

825

more serious when high concentration (up to 0.8 ppb) of PHPA is used.

826

The PP–SiO2 NC drilling muds are more capable of transferring cuttings to the surface with

827

or without pipe rotation speed than the PHPA. This behaviour is caused by increase in colloidal

828

interaction between particles of nanocomposite in the mud and sand particles. At a maximum

829

velocity of 1.80 m/s, the effects of PHPA muds on CTE were more pronounced, and CTEs were

830

higher than CTEs obtained with mud velocities between 0.457 and 0.960 m/s. This is because,

831

drilled cuttings and PHPA muds were uniformly distributed, which induced a higher fluid drag

832

and lift forces. The transport capacity of designed complex WBM will increase when mud

833

velocity increases with or without the presence of nanocomposite or PHPA due to the formation

834

of turbulent eddies.

835

The mud’s carrying capacity was most difficult at hole inclinations of 45 °, due to decreased

836

in axial annular velocity with increasing hole deviation. The CTEs were at the peak in the

837

horizontal portion of the wellbore because of enough axial mud velocity. The CTE significantly

838

depends on pump rate. The more the pump rate, the more the mud velocity, and the more the

839

CTE. This is because, higher mud velocity produces a larger axial force to lift cuttings. The

840

transport of small and intermediate–size cuttings is relatively simplified and requires less mud

841

velocity compared to largest cuttings with or without pipe rotation.

842

6. Recommendations

843

1. Highly weighted mud should be formulated with the designed nanocomposite to determine

844

its effect on ROP because the heavier mud weight will cause the weight of the drilling mud

845

to go higher above the pressure gradient of the formation, this, in turn, impacts penetration

846

rate.

847

2. Partially or fully eccentric drill pipe should be investigated with the designed PP–SiO
NC

848

drilling mud in order to determine their effect on the average fluid velocity in the annulus,

849

especially on the low side.

28

850

3. The shape factor has effects on the sagging of cuttings, and different shapes of cuttings have

851

different force distributions, resulting in different motion trajectories. Therefore, it is

852

suggested that the shape of cuttings with the designed nanocomposite should be studied.

853 Nomenclature 854

10–min gel

10 minutes of gel strength

855

10–s gel

10 seconds of gel strength

856

A–0.4

Base mud + 0.4 ppb PP–SiO
NC

857

A–0.5

Base mud + 0.5 ppb PP–SiO
NC

858

A–0.8

Base mud + 0.8 ppb PP–SiO
NC

859

A–1.2

Base mud + 1.2 ppb PP–SiO
NC

860

API

American petroleum institute

861

ASTM

American Standard Testing Method

862

AV

Apparent viscosity

863

B–0.4

Base mud + 0.4 ppb PHPA

864

B–0.5

Base mud + 0.5 ppb PHPA

865

B–0.8

Base mud + 0.8 ppb PHPA

866

B–1.2

Base mud + 1.2 ppb PHPA

867

BM

Base mud

868

CTE

Cuttings transferring efficiency

869

ECD

Equivalent circulating density

870

FCT

Filter cake thickness

871

FL

Filtrate loss volume

872

GS

Gel strength

873

HPHT

High pressure high temperature

874

ID

Outer diameter of the inner drill pipe

875

NaOH

Sodium hydroxides

876

OD

Internal diameter of the outer pipe

877

PAC HV

High viscosity polyanionic cellulose 29

878

PE–b–PEG

Polyethylene–block poly(ethylene glycol)

879

PHPA

Partially hydrolyzed polyacrylamide

880

PNCs

Polymer nanocomposites

881

PP

Polypropylene

882

PP–SiO
NC Polypropylene–nanosilica composite

883

PV

Plastic viscosity

884

ROP

Rate of penetration

885

Sand A

0.50–0.99 mm

886

Sand B

1.00–1.99 mm

887

Sand C

2.00–2.79 mm

888

Sand D

2.80–4.00 mm

889

SiO
NP

Silica nanoparticle or nanosilica

890

SiO


Silica/silicon dioxide

891

TEOS

Tetraethyl orthosilicate

892

WBMs

Water-based muds

893

YP

Yield point

894

YP/PV ratio

Transport capacity ratio

895 Conflicts of interest 896 On behalf of all the authors, the corresponding author states that there is no conflict of interest. 897 Acknowledgments 898

The authors wish to thank the Ministry of Higher Education Malaysia (MOHE) and Universiti

899 Teknologi Malaysia Research Management Centre for funding this project under the Fundamental 900 Research Grant Scheme (FRGS) with reference number FRGS/1/2019/TK05/UTM/02/20. 901 References 902 Abdollahi, M., Pourmahdi, M., Nasiri, A.R., 2018. Synthesis and characterization of 903

lignosulfonate/acrylamide graft copolymers and their application in environmentally friendly

904

water-based drilling fluid. J. Pet. Sci. Eng. 171, 484-494. 10.1016/j.petrol.2018.07.065. 30

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acrylamide composite used for enhancing the performance of water-based drilling fluids at

907

elevated

908

10.1016/j.petrol.2016.08.014.

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909 Al-Yasiri, M., Awad, A., Pervaiz, S., Wen, D., 2019. Influence of silica nanoparticles on the 910

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911

179, 2019, 504-51.

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drilling fluids, fifth ed. pp. 1–121.

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916

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919

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920

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923

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926

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940

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1040

2018.11.012.

1041 Zu, L., Li, R., Jin, L., Lian, H., Liu, Y., Cui, X., 2013. Preparation and characterization of 1042

polypropylene/silica composite particle with interpenetrating network via hot emulsion sol-gel

1043

approach. Progress in Natural Science: Materials International. 24, 42–49.

1044 Appendix A 1045 The physicochemical properties of some chemicals used in this study are shown in Table A.1. 1046 Determining the density of PP–SiO2 NC 1047

The density of the synthesized PP–SiO2 NC was determined in order to have an understanding

1048

of the range of densities of the synthesized nanocomposite particles. About 10 g, which is

1049

equivalent to 10 ml of the nanocomposite was used using water displacement method, as shown

1050

in Table A.2.

1051 The density of sands cuttings 1052

The sand replacement method was used to determine the density of sandstone (natural quartz,

1053 grains) according to a previous study (Yeu et al., 2019). Quartz grains were obtained from Desaru 1054 Beach, Johor Bahru, Malaysia and it has a water absorption capacity < 1.0%. The masses of both 1055 dry and wet grains of sand were measured in a container to calculate the density of the natural 1056 quartz grains, which was 20.43 ppg, as shown in Table A.3. 1057 1058

35

1059

List of Figures

1060 Figure 1. Synthesis process of PP–SiO2 NC particles using hot emulsion sol–gel method 1061 Figure 2. Formation mechanism of synthesized PP–SiO2 NC with PE–b–PEG acting as a surfactant 1062 Figure 3. Representation of field scale–down cuttings transport flow loop showing the various 1063 gadgets of the flow loop 1064 Figure 4. Representation of flow process used to simulate sand cuttings in a field scale–down 1065 cuttings transport flow loop from mud mixing to the determination of CTE 1066 Figure 5. Cuttings transport flow loop at different test settings (a) test setting 45 °, (b) test setting 60 1067 °, (c) test setting 75 ° and (d) test setting 90 ° (horizontal). 1068 Figure 6. Shear stress versus shear rate profile of complex based muds measured (a) before (25 °C) 1069 and (b) after (150 °C) hot rolling tests 1070 Figure 7. Viscosity versus shear rate of drilling muds measured (a) before (25 °C) and (b) after (150 1071 °C) hot rolling tests 1072 Figure 8. The consistency curves of drilling muds measured (a) before (25 °C) and (b) after (150 1073 °C) hot rolling tests 1074 Figure 9. Rheological properties measured before (25 °C) and after (150 °C) hot rolling 1075 experiments: (a) AV, (b) PV, (c), YP, (d) YP/PV ratio, (e) 10–s and 10–min gels, and (f) FL and 1076 FCT of drilling muds used to investigate the CTEs of mud samples at mud velocities between 0.457 1077 and 0.960 m/s without drill pipe rotation speed 1078 Figure 10. Mud properties of complex WBM with A–0.5 and B–0.5 used to investigate CTEs with 1079 or without pipe rotation speed of 150 rpm at a mud velocity of 1.80 m/s 1080 Figure 11. CTEs of complex drilling muds at hole angle 45 ° and different mud velocities for 1081 different cuttings size (Sand A: 0.50–0.99 mm; Sand B: 1.00–1.99 mm; Sand C: 2.00–2.79 mm; 1082 Sand D: 2.80–4.00 mm) 1083 Figure 12. CTEs of complex drilling muds at hole angle 60 ° and different mud velocities for 1084 different cuttings size (Sand A: 0.50–0.99 mm; Sand B: 1.00–1.99 mm; Sand C: 2.00–2.79 mm; 1085 Sand D: 2.80–4.00 mm) 1086 Figure 13. CTEs of complex drilling muds at hole angle 75 ° and different mud velocities for 1087 different cuttings size (Sand A: 0.50–0.99 mm; Sand B: 1.00–1.99 mm; Sand C: 2.00–2.79 mm; 1088 Sand D: 2.80–4.00 mm) 1089 Figure 14. CTEs of complex drilling muds at hole angle 90 ° and different mud velocities for 36

1090 different cuttings size (Sand A: 0.50–0.99 mm; Sand B: 1.00–1.99 mm; Sand C: 2.00–2.79 mm; 1091 Sand D: 2.80–4.00 mm) 1092 Figure 15. CTEs of different drilling muds at different hole angles and different mud velocities for 1093 cuttings diameter range of 0.50–0.99 mm (Sand A) 1094 Figure 16. CTEs of different drilling muds at different hole angles and different mud velocities for 1095 the cuttings diameter range of 1.00–1.99 mm (Sand B) 1096 Figure 17. CTEs of different drilling muds at different hole angles and different mud velocities for 1097 the cuttings diameter range of 2.00–2.79 mm (Sand C) 1098 Figure 18. CTEs of different drilling muds at different hole angles and different mud velocities for 1099 the cuttings diameter range of 2.80–4.00 mm (Sand D) 1100 Figure 19. CTEs of complex based mud at different mud velocities and cuttings diameter (Sand A: 1101 0.50–0.99 mm; Sand D: 2.80–4.00 mm) without drill pipe rotation 1102 Figure 20. CTEs of different drilling mud compositions at different hole angles with and without 1103 pipe rotation speed of 150 rpm for a mud velocity of 1.80 m/s (Sand A: 0.50–0.99 mm; Sand D: 1104 2.80–4.00 mm) 1105 Figure 21. CTEs of different diameters of cuttings conducted with different drilling muds with and 1106 without pipe rotation speed of 150 rpm for a mud velocity of 1.80 m/s (Sand A: 0.50–0.99 mm; 1107 Sand D: 2.80–4.00 mm) 1108 Figure 22. Distribution of particles in flowing mud (a) complex BM particles, and (b) PP–SiO2 NC 1109 particles 1110 1111

List of Tables

1112 Table 1. Comparison between nanosilica for cuttings transport and the current study 1113 Table 2. Reprentation of complex based mud samples with abbreviations 1114 Table 3. Representation of prepared complex based mud samples 1115 Table 4. Simulated sandstone cuttings 1116 Table 5. Unweighted spud mud properties measured at 25 °C 1117 Table 6. Total cost of products used to produce PP–SiO2 NC additive of 1 laboratory barrel, 1118 equivalent to 350 ml of WBM 1119 Table 7. Cost analysis of 1 laboratory barrel, equivalent to 350 ml of WBM used to formulate the 1120 drilling muds 37

1121 Table A.1. Physicochemical properties of PP, PE–b–PEG, TEOS, and PHPA 1122 Table A.2. The density calculation of PP–SiO2 NC 1123 Table A.3. The density calculations for sandstone cuttings

38

Table 1.

Study items

Gbadamosi et al., (2018)

Boyou et al., (2019)

The focus of The transport of drilled The the study

Current study

performance

of The

effect

of

drilling

mud

cuttings from the wellbore nanosilica in WBM for hole rheology using PP–SiO
NC and to

the

surface

using cleaning

in

directional PHPA in a drilling environment.

different weight percent of wellbores.

Compared

the

properties

nanosilica in WBM.

performance of PP–SiO
NC and PHPA. Used different mud velocities on sandstone cuttings. Specifically, target the critical angles between 45 ° and 60 °.

Scope of the Investigated

only

the Investigated

a

complete Investigated

annulus

a

deviated

and

study

vertical (0 °) annulus

horizontal annulus

Rheological

Rheological

and

properties at 25 °C and rheological

filtration

API and HPHT filtration properties measured at 25 properties measured at both 25 °C

tests

properties.

model and Rheological

model, Rheological model, rheological and

filtration properties

°C only.

and

filtration

and 150 °C.

Four different mud samples Unweighted

spud

mud

was

of 9.0 ppg and 12.0 ppg evaluated. Nine different mud densities were evaluated.

samples of only 9.5 ppg density were also evaluated.

Cuttings

Three cuttings size range 0, 30, 60 and 90 ° annulus 45, 60, 75 and 90 ° annulus were

transport

used are 1.0–1.4mm, 1.7– were examined.

experiments

2.0 mm and 2.4–2.8mm.

examined.

Used four cuttings diameter Used

four

cuttings

diameter

Flow rates used are 0.4, between the range of 1.40 between the range of 0.50 and 0.6 and 1.0 L/s. Ten

concentrations

nanosilica between

used 0.001

and 4.0 mm.

4.00 mm.

of Used three concentrations of Used four concentrations of PP– are nanosilica (0.5, 1.0 and 1.5 SiO
NC and PHPA (0.4, 0.5, and ppb).

0.8 and 1.2 ppb).

1.5%v/v.

Investigated

with

and Investigated with and without

There was no pipe rotation without pipe rotation. Pipe pipe rotation. A constant pipe rotation speeds of 0 and 150 rotation speed of 150 rpm was rpm were used. Used

a

used.

constant

flow Used different mud velocities

velocity of 4.71 ft/s.

(0.457, 0.630, 0.823, 0.960 m/s

Used a constant cuttings and 1.80 m/s). Used also a type

constant mud velocity of 1.80 m/s for comparison between PP– SiO
NC and PHPA with and without pipe rotation. Used a constant type of cuttings (sandstone cuttings).

Main

The presence of nanosilica The addition of nanosilica The addition of PP–SiO2 NC in

conclusions

enhanced the viscosity of in

WBM

reduced

the WBM increased the rheological

WBM, which increases viscosities, especially for and filtration control properties the cuttings lifting with the increasing concentration.

higher

density

mud and

provides

better

cuttings

nanosilica samples and provides a transport than the WBM with The better cuttings recovery than PHPA. The enhanced cuttings

performance enhancement the lower density samples. lifting performance of WBM with of the mud results from This is because nanosilica PP–SiO
NC is due to the the increased drag force increased

the

range

of increased colloidal

interactions

because the surface force distribution of the particles between the hybrid dispersions overcomes

the in the mud and increased the (PP–SiO
NC) and cuttings,

gravitational force acting colloidal interactions with which increased their distribution on cuttings.

cuttings when the mud was and circulated.

stability

solution.

in

the

WBM

Table 2.

Sample No.

Sample concentration

Sample abbreviation

1

Base mud

BM

2

Base mud + 0.4 g PP–SiO
NC

A–0.4

3

Base mud + 0.5 g PP–SiO
NC

A–0.5

4

Base mud + 0.8 g PP–SiO
NC

A–0.8

5

Base mud + 1.2 g PP–SiO
NC

A–1.2

6

Base mud + 0.4 g PHPA

B–0.4

7

Base mud + 0.5 g PHPA

B–0.5

8

Base mud + 0.8 g PHPA

B–0.8

9

Base mud + 1.2 g PHPA

B–1.2

Table 3.

Components

WBM

Concentration

of

PP–SiO2

NC Concentration of PHPA (ppb)

(ppb) BM

A–0.4

A–0.5

A–0.8

A–1.2

B–0.4

B–0.5

B–0.8

B–1.2

Fresh water (ml)

320.34

320.21

320.13

320.11

320.01

320.21

320.13

320.11

320.01

Bentonite (ppb)

15

15

15

15

15

15

15

15

15

Caustic soda (ppb)

0.25

0.25

0.25

0.25

0.25

0.25

0.25

0.25

0.25

Soda ash (ppb)

0.25

0.25

0.25

0.25

0.25

0.25

0.25

0.25

0.25

Xanthan gum (ppb)

0.20

0.20

0.20

0.20

0.20

0.20

0.20

0.20

0.20

PAC HV (ppb)

2.0

2.0

2.0

2.0

2.0

2.0

2.0

2.0

2.0

Barite (ppb)

34.22

33.95

33.93

33.65

33.35

33.95

33.93

33.65

33.35

PP–SiO2 NC (ppb)

0.0

0.4

0.5

0.8

1.2

―

―

―

―

PHPA (ppb)

0.0

―

―

―

―

0.4

0.5

0.8

1.2

Density (ppg)

9.5

9.5

9.5

9.5

9.5

9.5

9.5

9.5

9.5

Table 4.

Sand No.

Sand A

Sand B

Sand C

Sand D

Diameter (mm)

0.50–0.99

1.00–1.99

2.00–2.79

2.80–4.00

Table 5.

Properties

Units

Spud mud

Observed values of spud mud with PP–SiO
NC 0.5 ppb PP–SiO


1.0 PP–SiO
NC

1.5 PP–SiO


NC + Spud mud

+ Spud mud

NC + Spud mud

pH

–

8.6

8.6

8.6

8.7

Density

ppg

8.9

8.9

9.0

9.0

AV

mPa.s

14

14.6

15.5

17.5

PV

mPa.s

9.0

9.3

10

11.5

YP

Pa

10

10.6

11

12.0

10–s gel

Pa

3.0

3.5

3.8

4.5

10–min gel

Pa

4.0

4.2

4.5

5.0

API FL

ml

12.7

11.1

10.2

9.6

Table 6.

No. Products

Unit size Qty Cost/unit

Cost/unit

Content of Cost

bought

size

products

products

(USD)

used

used (USD)

size (MYR)

1

PP

1000 g

1

280.0

67.32

6g

0.404

2

PE–b–PEG

250 g

1

600.0

144.27

24 g

13.85

3

TEOS

1L

1

580.0

139.46

20 ml

2.789

4

NH4OH

2.5 L

1

60.0

14.43

60 ml

0.346

5

Xylene

1L

1

381.7

91.78

20 ml

1.836

6

EtOH

2.5 L

1

90.0

21.64

100 ml

0.866

7

APTES

100 ml

1

620.0

148.25

1.6 ml

2.372

41.8 g

—

The Total yield of PP–SiO2 NC produced

of

The Total cost of products (USD) used in producing 41.8 g of PP–SiO2 NC 20.091 from about 230 g of materials MYR–Malaysian Ringgit; USD–United States Dollar; 1 MYR = 0.42 USD (20th May, 2019)

Table 7.

Products

Unit size Qty

Cost/unit

Cost/unit

Content of Actual

bought

size

size (USD)

products

products

used

(USD/bbl)

(MYR) Bentonite

500 g

1

201.60

48.47

15.0 ppb

1.4541

NaOH

500 g

1

528.70

127.12

0.25 ppb

0.0636

Na2CO3

500 g

1

402.20

96.17

0.25 ppb

0.0481

XG

100 g

1

359.65

86.0

0.20 ppb

0.0478

PAC HV

1000 g

1

7.53

1.80

2.0 ppb

0.0036

Barite

100 g

1

235.70

56.67

34.22 ppb

19.39

The Total cost of formulating 1 lab bbl of basic BM —

cost

of used

21.00

(USD/bbl) PHPA

250 g

1

295.70

71.10

The Total cost of formulating BM + PHPA (USD/bbl)

2.9 ppb

0.823

—

21.823

(3.92%

increase over BM) Cost of PP–SiO2 NC concentration used

2.9 ppb

1.969

The Total cost of formulating BM + PP–SiO2 NC from 2.9 ppb

22.969

USD 22.463 (USD/bbl)

increase over BM)

(9.38%

MYR–Malaysian Ringgit; USD–United States Dollar; 1 MYR = 0.42 USD (20th May, 2019)

Table A.1.

Properties

PP

PE–b–PEG

TEOS

PHPA

CAS number

9003–07–0

251553–5–6

78–10–4

17194–82–0

Formula

(C3H6)n

C4H10O2

C8H20O4Si

C8H9NO2

Appearance (form)

Beads

Beads

Liquid

Powder

Appearance (colour)

White (crystal)

Yellow

Colourless

Faint brown

Molecular weight (g/mol)

42.08

90.12

208.34

151.163

Density (g/cm3)

0.855

―

0.933

1.244

Melting point °C

161.9

63.7

―

175–178

―

168

403.9

Boiling point °C at 760 ― mmHg Vapour pressure at 25 °C

4.22 × 107

―

―

―

Shape

Spherical

Spherical

―

―

Flash point °C

―

―

―

198.1

Hydrophile–Lipophile

―

10

―

―

Solubility in water

Insoluble

Insoluble

Soluble

Soluble

Surface charge

None

Neutral

Negative

Ionic character

None

Nonionic

―

(mg ―

33

―

―

―

1.542

Balance (HLB) value

Hydroxyl

value

Anionic

KOH/g) Refractive index

1.594

Table A.2.

Mass of cylinder + 350 ml water

154.6 g

Mass of cylinder + 350 ml water +10 ml PP–SiO2 NC 166.7 g Mass of PP–SiO2 NC

12.1 g

Volume of PP–SiO2 NC

10 ml

Density of PP–SiO2 NC

1.21 g/ml

Density of PP–SiO2 NC

10.1 ppg

Table A.3.

Mass of beaker (g)

3.53

Volume of beaker (cm³)

95.00

Mass of beaker + dry sand (g)

167.43

Mass of beaker + wet sand (g)

195.46

Mass of dry sand (g) = (167.43–3.53)

163.90

Porosity of sand =


. . 

0.2951

.

Volume of dry sand (cm³) = 95.00 × (1–0.2951) 66.97

Density of sandstone
=

 .

2.45

.

Density of sandstone (ppg) = 2.45 × 8.34

20.43

Figure 1.

Figure 2.

Figure 3.

Figure 4.

Figure 5.

(a) 200

140 120 100 80 60

Rheological model after hot rolling BM A–0.4 A–0.8 A–1.2 B–0.4 B–0.8 B–1.2

120

Shear stress (Pa)

160

(b) 140

BM A–0.4 A–0.8 A–1.2 B–0.4 B–0.8 B–1.2

180

Shear stress (Pa)

Rheological model before hot rolling

100 80 60 40

40 20

20 0

0 0

200

400 600 800 Shear rate (1/s)

1000

0

200

400

600

Shear rate (1/s)

Figure 6.

800

1000

(a)

Viscosity after hot rolling

10000 BM A–0.4 A–0.8 A–1.2 B–0.4 B–0.8 B–1.2

1000

100

10

Apparent viscosity (mPa.s)

Apparent viscosity (mPa.s)

(b)

Viscosity before hot rolling

10000

1

BM A–0.4 A–0.8 A–1.2 B–0.4 B–0.8 B–1.2

1000

100

10

1 0

200

400

600

800

1000

0

Shear rate (1/s)

200

400

600

Shear rate (1/s)

Figure 7.

800

1000

(a)

Before hot rolling 140 BM

Dial readings (Pa)

120

A–0.5

B–0.5

100 80 60 40 20 0 0

200

400

600

Rotor speed (rpm) (b)

After hot rolling

120 BM

A–0.5

B–0.5

Dial readings (Pa)

100 80 60 40 20 0 0

200

400

Rotor speed (rpm)

600

Figure 8.

(a)

Apparent viscosity 100 150 °C

Plastic viscosity (mPa.s)

Apparent viscosity (mPa.s)

25 °C

(b)

80 60 40 20 0 BM A–0.4 A–0.8 A–1.2 B–0.4 B–0.8 B–1.2

Mud concentration (ppb)

Plastic viscosity

40 35

25 °C

150 °C

30 25 20 15 10 5 0 BM A–0.4 A–0.8 A–1.2 B–0.4 B–0.8 B–1.2

Mud concentration

(c)

Yield point

(d)

25 °C

80 60

150 °C

3

YP/PV ratio

Yield point (Pa)

25 °C

150 °C

100

Transport capacity ratio

3.5

120

2.5 2 1.5

40

1

20

0.5 0

0 BM A–0.4 A–0.8 A–1.2 B–0.4 B–0.8 B–1.2

BM A–0.4 A–0.8 A–1.2 B–0.4 B–0.8 B–1.2

Mud concentration (ppb)

Mud concentration (ppb)

(e)

(f)

10–s and 10–min gels

Gel strength (Pa)

25

10-s (25 °C) 10-min (25 °C) 10-s (150 °C) 10-min (150 °C)

API FL API FCT HPHT FL HPHT FCT

16

Filtration properties

30

Filtrate volume and cake thickness

18

35

20 15 10

14 12 10

5

8 6 4 2 0

0 BM A–0.4 A–0.8 A–1.2 B–0.4 B–0.8 B–1.2

BM A–0.4 A–0.8 A–1.2 B–0.4 B–0.8 B–1.2

Mud concentration (ppb)

Mud concentration

Figure 9.

(a)

Mud properties before hot rolling

(b)

70 BM

A–0.5

B–0.5

BM

60

A–0.5

50

Rheological values

Rheological values

Mud properties after hot rolling

60

50 40 30 20

40 30 20

10

10

0

0

Mud properties

Mud properties

Figure 10.

B–0.5

(a)

90

(b)

Sand A (45 °)

80

70

CTE (%)

CTE (%)

70 60 50 40 30

50

30

BM A–0.4 A–0.8 A–1.2 B–0.4 B–0.8 B–1.2

BM A–0.4 A–0.8 A–1.2 B–0.4 B–0.8 B–1.2

Mud concentration (ppb)

Mud concentration (g)

Sand C (45 °)

(d)

80 70

60

60

CTE (%)

70

50 40 30 20

0.457 m/s 0.640 m/s 0.823 m/s 0.960 m/s

20

80

CTE (%)

60

40

0.457 m/s 0.640 m/s 0.823 m/s 0.960 m/s

20

(c)

Sand B (45 °)

80

0.457 m/s 0.640 m/s 0.823 m/s 0.960 m/s

Sand D (45 °) 0.457 m/s 0.640 m/s 0.823 m/s 0.960 m/s

50 40 30 20

BM A–0.4A–0.8A–1.2 B–0.4 B–0.8 B–1.2 Mud concentration (ppb)

Figure 11.

BM A–0.4 A–0.8 A–1.2 B–0.4 B–0.8 B–1.2

Mud concentration (ppb)

(a)

(b)

Sand A (60 °) 90

70

70

CTE (%)

CTE (%)

80

60 50 40

Sand B (60 °) 80

0.457 m/s 0.640 m/s 0.823 m/s 0.960 m/s

60 50 40 30

30

BM A–0.4 A–0.8 A–1.2 B–0.4 B–0.8 B–1.2

BM A–0.4 A–0.8 A–1.2 B–0.4 B–0.8 B–1.2

Mud concentration (ppb)

Mud concentration (ppb)

80

(c)

Sand D (60 °)

70

70

60

60

50 40 30

Sand C (60 °)

80

CTE (%)

CTE (%)

(d)

0.457 m/s 0.640 m/s 0.823 m/s 0.960 m/s

50 40

0.457 m/s 0.640 m/s 0.823 m/s 0.960 m/s

30

20

0.457 m/s 0.640 m/s 0.823 m/s 0.960 m/s

20 BM A–0.4 A–0.8 A–1.2 B–0.4 B–0.8 B–1.2

Mud concentration (ppb)

BM A–0.4 A–0.8 A–1.2 B–0.4 B–0.8 B–1.2

Mud concentration (ppb)

Figure 12.

(a)

Sand A (75 °)

(b)

Sand B (75 °) 90

80

80

70

70

CTE (%)

CTE (%)

90

60 50 40

0.457 m/s 0.640 m/s 0.823 m/s 0.960 m/s

60 0.457 m/s 0.640 m/s 0.823 m/s 0.960 m/s

50 40 30

30

BM

BM A–0.4 A–0.8 A–1.2 B–0.4 B–0.8 B–1.2

Mud concentration (ppb)

Mud concentration (ppb) (c)

80

(d)

Sand C (75 °)

70

CTE (%)

CTE (%)

Sand D (75 °) 80

70 60 50 40

A–0.4 A–0.8 A–1.2 B–0.4 B–0.8 B–1.2

0.457 m/s 0.640 m/s 0.823 m/s 0.960 m/s

60 50 40

30

0.457 m/s 0.640 m/s 0.823 m/s 0.960 m/s

30 BM A–0.4 A–0.8 A–1.2 B–0.4 B–0.8 B–1.2

BM A–0.4 A–0.8 A–1.2 B–0.4 B–0.8 B–1.2

Mud concentration (ppb)

Mud concentration (ppb)

Figure 13.

(a)

Sand A (90 °)

(b)

100 90

CTE (%)

70

70 60

60 50 40

(c)

0.457 m/s 0.640 m/s 0.823 m/s 0.960 m/s

50 40

BM A–0.4 A–0.8 A–1.2 B–0.4 B–0.8 B–1.2

Mud concentration (ppb)

Mud concentration (ppb) (d)

Sand C (90°)

80

CTE (%)

CTE (%)

Sand D (90 °)

90

80 70

50

0.457 m/s 0.640 m/s 0.823 m/s 0.960 m/s

BM A–0.4 A–0.8 A–1.2 B–0.4 B–0.8 B–1.2

90

60

Sand B (90 °)

80

80

CTE (%)

90

0.457 m/s 0.640 m/s 0.823 m/s 0.960 m/s

70 60 50 40

0.457 m/s 0.640 m/s 0.823 m/s 0.960 m/s

30

40 BM A–0.4 A–0.8 A–1.2 B–0.4 B–0.8 B–1.2

BM A–0.4 A–0.8 A–1.2 B–0.4 B–0.8 B–1.2

Mud concentration (ppb)

Mud concentration (ppb)

Figure 14.

(a)

Sand A (0.457 m/s) 80

BM A–1.2 B–1.2

70

A–0.4 B–0.4

(b)

Sand A (0.640 m/s)

100

A–0.8 B–0.8

BM A–1.2 B–1.2

90

A–0.4 B–0.4

A–0.8 B–0.8

CTE (%)

CTE (%)

80 60 50

70 60 50

40 40 30

30 45

60

75

90

45

60

Hole angle (°) (c)

(d)

Sand A (0.823 m/s)

100

BM A–1.2 B–1.2

90

90

A–0.4 B–0.4

Sand A (0.960 m/s)

100

A–0.8 B–0.8

BM A–1.2 B–1.2

90

CTE (%)

80

CTE (%)

75

Hole angle (°)

70 60 50

A–0.4 B–0.4

A–0.8 B–0.8

80 70 60 50

40 30

40 45

60

75

90

Hole angle (°)

Figure 15.

45

60

75

Hole angle (°)

90

(a)

BM A–1.2 B–1.2

A–0.4 B–0.4

Sand B (0.640 m/s)

80

BM A–1.2 B–1.2

A–0.8 B–0.8 70

CTE (%)

70

CTE (%)

(b)

Sand B (0.457 m/s)

80

60 50 40

A–0.8 B–0.8

60 50 40

30

30 45

60

75

90

45

60

Hole angle (°) (c)

BM A–1.2 B–1.2

80

A–0.4 B–0.4

75

90

Hole angle (°)

Sand B (0.823 m/s)

90

(d)

Sand B (0.960 m/s)

90

A–0.8 B–0.8

BM A–1.2 B–1.2

80

70

CTE (%)

CTE (%)

A–0.4 B–0.4

60 50

A–0.4 B–0.4

A–0.8 B–0.8

70 60 50

40

40

30 45

60

75

90

45

60

75

Hole angle (°)

Hole angle (°)

Figure 16.

90

(a) 70

(b)

Sand C (0.457 m/s)

60

BM A–1.2 B–1.2

70

50

CTE (%)

CTE (%)

Sand C (0.640 m/s) 80

40 30

BM A–1.2 B–1.2

20 45

A–0.4 B–0.4

50 40

A–0.8 B–0.8

30

60

75

45

90

60

BM A–1.2 B–1.2

(d)

90

Sand C (0.960 m/s)

90 A–0.8 B–0.8

BM A–1.2 B–1.2

80

70

CTE (%)

CTE (%)

80

A–0.4 B–0.4

75

Hole angle (°)

Sand C (0.823 m/s)

90

A–0.8 B–0.8

60

Hole angle (°) (c)

A–0.4 B–0.4

60

A–0.8 B–0.8

70 60

50

50

40

40

30

A–0.4 B–0.4

30 45

60

75

90

Hole angle (°)

45

60

75

Hole angle( °)

Figure 17.

90

(a)

Sand D (0.457 m/s)

70

(b)

60

BM A–1.2 B–1.2

60

50

CTE (%)

CTE (%)

Sand D (0.640 m/s)

70

40

A–0.4 B–0.4

A–0.8 B–0.8

50 40

30 BM A–1.2 B–1.2

20 10 45

(c)

A–0.4 B–0.4

30

A–0.8 B–0.8

20 60

75

90

Hole angle (°)

Sand D (0.823 m/s)

90

BM A–1.2 B–1.2

80

A–0.4 B–0.4

A–0.8 B–0.8

CTE (%)

70 60 50 40 30 20 45

60

75

90

Hole angle (°) (d)

Sand D (0.960 m/s) 90 80

CTE (%)

70 60 50 40 BM A–1.2 B–1.2

30 20 45

A–0.4 B–0.4 60

A–0.8 B–0.8 75

Hole angle (°)

90

45

60

75

Hole angle (°)

90

Figure 18.

(a)

(b)

Sand A (BM)

80

Sand D (BM)

90 80

70

CTE (%)

CTE (%)

70 60 50

0.457 m/s 0.640 m/s 0.823 m/s 0.960 m/s 1.80 m/s

40 30 45

60

75

60 50 40

0.457 m/s 0.823 m/s 1.80 m/s

30 20

90

45

Hole angle (°)

60

0.640 m/s 0.960 m/s 75

Hole angle (°)

Figure 19.

90

Sand A

(b)

Sand D

100

100

90

90

80

80 CTE (%)

CTE (%)

(a)

70 BM with no pipe rotation BM with pipe rotation A–0.5 with no pipe rotation A–0.5 with pipe rotation B–0.5 with no pipe rotation B–0.5 with pipe rotation

60 50

60

75

BM with no pipe rotation BM with pipe rotation A–0.5 with no pipe rotation A–0.5 with pipe rotation B–0.5 with no pipe rotation B–0.5 with pipe rotation

60 50

40 45

70

90

40

Hole angle (°)

Figure 20.

45

60 75 Hole angle (°)

90

(a)

BM

(b)

100

With no pipe rotation

With pipe rotation

80

80

60

60

CTE (%)

CTE (%)

With no pipe rotation

40

40

0

0 45 ° 60 ° 75 ° 90 ° 45 ° 60 ° 75 ° 90 ° Sand A

Sand D

Cuttings diameter (mm) (c) 100

With pipe rotation

20

20

B–0.5 With no pipe rotation

With pipe rotation

80

CTE (%)

A–0.5

100

60

40

20

0 45 ° 60 ° 75 ° 90 ° 45 ° 60 ° 75 ° 90 ° Sand A Sand D Cuttings diameter (mm)

45 ° 60 ° 75 ° 90 ° 45 ° 60 ° 75 ° 90 ° Sand A

Sand D

Cuttings diameter (mm)

Figure 21.

Figure 22.

Highlights •

A water–based mud (WBM) containing polypropylene–nanosilica composite (PP–SiO2 NC) was formulated.

•

The properties of WBM with PP–SiO2 NC was compared with those of partially hydrolyzed polyacrylamide (PHPA).

•

WBM with PP–SiO2 NC showed better performance in modifying rheology and controlling filtration properties than PHPA muds.

•

WBM with PP–SiO2 NC are more capable of transferring cuttings than the PHPA with or without pipe rotation.

•

The transport of smaller cuttings is relatively simplified and require less mud velocity compared to larger cuttings.

Author Contribution statement Article Title: Experimental investigation of cuttings transportation in deviated and horizontal wellbores using polypropylene–nanosilica composite drilling mud Oseh Jeffrey Onuoma and Dr. M.N.A. Noorul conceived the idea and designed the experimental works. Oseh Jeffrey Onuoma and Dr. M.N.A. Noorul collected the data used in the research. Oseh Jeffrey Onuoma, Gbadamosi O. Afeez and Agi Augustine performed the experimental works (test of rheology, filtration properties and cuttings transport) using polypropylenenanosilica composite (PP-SiO

NC) added into complex water-based mud (WBM). Dr. M.N.A

Noorul and Assoc. Prof. Issham Ismail encouraged Oseh Jeffrey Onuoma, Gbadamosi O. Afeez and Agi Augustine to investigate the effect of partially hydrolyzed polyacrylamide (PHPA) in the WBM and compare it with that of PP-SiO

NC. Spud mud was formulated by Oseh Jeffrey

Onuoma, Gbadamosi O. Afeez and Agi Augustine. Cost feasibility study was written by Oseh Jeffrey Onuoma, Dr. M.N.A. Noorul and Assoc. Prof. Issham Ismail. The Abstract was written by Assoc. Prof. Abdul R. Ismail. Dr. M.N.A. Noorul, Assoc. Prof. Issham and Assoc. Prof. Abdul R. Ismail helped supervised the findings of this work. The conclusion was written by Dr. M.N.A. Noorul. All authors discussed the results and contributed to the final manuscript.

Conflicts of interest statement On behalf of all the authors, the corresponding author states that there is no conflict of interest.