In the present day oil and gas industry, the chemicals used as pH controller are usually imported at an exorbitant price - which take a large part of the drilling cost and have ripple effect on the economy of the Nation. It is however necessary to source for an alternative by the use of local materials so as to enhance cost effectiveness. This study nonetheless focus on investigating the suitability of locally sourced materials as pH enhancer in a drilling mud program.A high pH is desirable to suppress corrosion rate, hydrogen embrittlement and the solubility of Ca2+ and Mg2+ which makes up clay. In addition, the high pH is a favorable environment for many of the organic viscosity control additives. For years this additives use to help maintain this property are imported and this contribute to high cost of drilling and which adversely affect the economy. In order to minimize this cost and maximize profit ,the locally made additives is been investigated to supplement the imported .Burnt coconut fiber is used as a pH enhancer because it is environmentally friendly in that it is degradable and has no adverse effect on the formation properties. Nevertheless, the result from the experiment conducted in this study revealed that; the local additives imparted significant pH unit of 13.0 in the drilling mud when compared to the foreign addictive such as sodium hydroxide which gave 13.8


Title page          i

Certification         ii

Dedication         iii

Acknowledgement         iv

Abstract         v

Table of contents         vi

List of Tables       viii

List of figures         ix


1.0 Introduction           1

1.1       Drilling Fluid Classifications           3

1.1.1 Pneumatic Fluids           4

1.1.2 Oil – Based Fluids           4

1.1.3 Water Based Fluids           5

1.2 Drilling Fluid Functions and Performance           6

1.3 Mud Circulating System           8

1.4 Statement of Problem           8

1.5 Aims            9 

1.6       Objectives           9

1.7 Scope and Limitation           9

1.8 Significance of the study           9

CHAPTER TWO: LITERATURE REVIEW         10                   

2.1 Viscosity 10

 2.1.1 Herschel-Burkley Model         13

2.1.2 Review on Viscosity Field Measurements         15

2.1.3 Viscosity Control Additives 16

2.2 Yield Point 162.3Drilling Mud Density (Weight) 16

2.3.1Mud Weight Control Additives 18

2.3.2 Drilling Fluid PH and Alkalinity 18

2.3.3 Factors Affecting Mud Properties 20

2.4 Review on Coconut Fibre 21 


3.0  Experimental Procedure 22

3.1 Methodology 22

3.2 Materials 22

3.3 Equipment and Apparatus used 24

3.4 Preparation of Mud Sample         25

3.5      Preparation of Molar concentration Solution from Burnt Coconut Fibre                25

3.6 Formulation of Standard Drilling Mud                     25   

3.7. Experimental Setup         27

3.7. 1 Measuring PH of drilling fluids         27

3.7.2 Determination of mud properties         27

3.7.3 Determination of Rheological properties         27 Viscosity 28 Plastic Viscosity         29 Yield Point         30 Viscosity         30 Gel Strength         30


4.1 Results         31

4.2. Result Analysis         36

4.2.1 Economic Justification         36

4.3 Discussion         38


5.1 Conclusion                    39

5.2 Recommendation        39

References        40


Table 4.0: Results of the pH of Molar Concentration of Burnt Coconut Fiber in water              31

Table 4.1:Results of the pH of Molar Concentration of NaOH + Drilling Mud and Molar Solution of Burnt Coconut Fiber in Drilling Mud32

Table 4.3:  Readings of the Rheological properties of Mud containing Burnt Coconut Fiber33

Table 4.4:Results of the mud parameters obtained at the experiment         35

Table 4.5:Fresh Water Dispersed Drilling Fluid         37

Table 4.6: Fresh Water Dispersed Drilling Fluid using Burnt Coconut fibre         37


Fig. 1.1: Drilling Fluids Classification 3

Fig. 1.2:Classification of Water-Based Fluids 5

Fig. 1.3: Drilling Mud Circulating System 8

Fig. 2.1:Shear rate- Shear stress relationship of Newtonian fluids 11

Fig. 2.2:Flow Curve for a Power Law Fluid   13

Fig. 2.3: Bingham fluid Model 14

Fig. 2.4: Basic shear diagram typical fluid behavior for real fluids 14

Fig. 2.5: A mud balance 17

Fig. 3.1: A workflow diagram of experimental procedures and analysis. 23

Fig. 3.2: Burnt Coconut Fiber used for enhancing Mud pH   24

Fig 3.3: Molar solution Prepared for the analysis      25

Fig. 3.4: Setting up of the mud in multi – beach mixer 26

Fig 3.6: Calibration processes of marsh funnel using distilled water 28

Fig. 3.7: Preparing the mud sample for Marsh funnel viscosity   28

Fig. 4.1: A chart showing the pH of Burnt Coconut Fibre filtrates in water   34

Fig. 4.2: A chart showing the comparison of pH of Sodium hydroxide (NaOH) with Burnt Coconut Fibre filtrates in drilling mud     35

Fig. 4.3: A chart showing comparison between plastic viscosities of Burnt Coconut Fiber Mud35



1.0 Introduction

A drilling fluid, or mud is any fluid that is used in a drilling operation in which that fluid is circulated or pumped from the surface, down the drill string, through the bit, and back to the surface via the annulus.(Growcock et al., 2005).The successful and cost of a drilling process is known to depend extensively on the asset of the drilling fluid used (Gray et al., 1980). Drilling mud circulates in a loop, from the platform, where it is forced down into the formation by entering the drill string, and pushed up to the surface again via the drill bit. The fluid characteristics such as density and temperature are variables that need to be regularly monitored for perfect drilling conditions of the well (Issham et al. 1985). They provide primary well control of subsurface pressures by a combination of density and any additional pressure acting on the fluid column (annular or surface imposed). They are most often circulated down the drill string, out the bit and back up the annulus to the surface so that drill cuttings are removed from the wellbore. Drilling fluids have a number of alternative names, acronyms and slang terms used within the industry. The most widely used name is “mud” or “drilling mud” and both these terms will be used interchangeably throughout this chapter. Other drilling fluid names and acronyms are: water-based mud (WBM), oil-based mud (OBM), synthetic-based mud (SBM), non-aqueous fluid (NAF), invert emulsion fluid (IEF), high performance water-based mud (HPWBM), drill-in fluid (DIF) and reservoir drilling fluid (RDF). Similar to drilling fluids are so-called completion fluids that are used to finish the well after drilling is completed. The fluids used during completions are often referred to as work over and completion (WOC) fluids, clear brines and/or packer fluids. Drilling fluid is a major factor in the success of the drilling program and deserves careful study. 

Figure 1.0: Drilling fluids stored in the mud tank under agitation.

The performance of the drilling fluid is critical to everyone involved with the operation and to all aspects of the drilling operation. The drilling fluid is the primary means to keep the well from blowing out and it is responsible for keeping the hole in good condition such that drilling operations can continue to the desired depth. Drilling and completion fluids are one of the most important parts of the well construction process and ultimately the performance of the fluid will determine the success or failure of the operation. The responsibility of the proper selection and application of fluid is held jointly between the fluids supplier, the drilling contractor and the operator. 

The research work focused on the use of Nigeria local materials in enhancing the drilling mud pH, its performance and contribution as drilling fluid properties and ensuring quality in hole making. Drilling fluid pH measurements and pH adjustments are fundamental to drilling fluid control because clay interactions, solubility of additives, and contaminant removal are all pH-dependent.

PH is a value representing the hydrogen ion concentration in liquid and it is used to indicate acidity or alkalinity of drilling mud. The pH is presented in a numerical value (0 – 14), which means an inverse measurement of hydrogen concentration in the fluid.

The pH formula is listed below;

pH = - log 10 [H] 

Where: H is the hydrogen ion concentration in mol.

According to the pH formula, the more hydrogen atoms present, the more acidity of substance is but the pH value decreases. Generally speaking, a pH of 7 means neutral. Fluids with a pH above 7 are considered as being alkaline. On the other hand, the fluids with pH below 7 are defined as being acidic.

In the drilling mud, there are three main chemical components involved in Alkalinity of drilling fluid, which are bicarbonate ions (HCO3--), hydroxyl ions (OH --), and carbonate ions (CO3-2). The Alkalinity means ions that will reduce the acidity.

In order to get accurate measurements for the pH, using a pH meter instead of using a pH a paper is recommended because it will give more accurate pH figures. Additionally, pH meters must be calibrated frequently.

1.1 Drilling Fluid Classifications

             Drilling fluids are separated into three major classifications (Figure 1):

1. Pneumatic

2. Oil-Based

3. Water-Based







Non – Petroleum                   Hydrocarbon

            Non - Inhibitive



             Dry Gas



          Gasified Mud

Figure 1.1: Drilling Fluids Classification (Source:Drilling Mud Rheology and the API Recommended Measurements)

1.1.1  Pneumatic Fluids

Pneumatic (air/gas based) fluids are used for drilling depleted zones or areas where abnormally low formation pressures may be encountered. An advantage of pneumatic fluids over liquid mud systems can be seen in increased penetration rates. Cuttings are literally blown off the cutting surface ahead of the bit as a result of the considerable pressure differential. The high pressure differential also allows formation fluids from permeable zones to flow into the wellbore. Air/gas based fluids are ineffective in areas where large volumes of formation fluids are encountered. A large influx of formation fluids requires converting the pneumatic fluid to a liquid-based system. As a result, the chances of losing circulation or damaging a productive zone are greatly increased. Another consideration when selecting pneumatic fluids is well depth. They are not recommended for wells below about 10,000 ft because the volume of air required to lift cuttings from the bottom of the hole can become greater than the surface equipment can deliver.

1.1.2 Oil-Based Fluids

A primary use of oil-based fluids is to drill troublesome shales and to improve hole stability. They are also applicable in drilling highly deviated holes because of their high degree of lubricity and ability to prevent hydration of clays. They may also be selected for special applications such as high temperature / high pressure wells, minimizing formation damage, and native-state coring. Another reason for choosing oil-based fluids is that they are resistant to contaminants such as anhydrite, salt, and CO2 and H2S acid gases.

Cost is a major concern when selecting oil-based mud. Initially, the cost per barrel of an oil-based mud is very high compared to a conventional water-based mud system. However, because oil mud can be reconditioned and reused, the costs on a multi-well program may be comparable to using water – based fluids. Also, buy-back policies for used oil-based mud can make them an attractive alternative in situations where the use of water-based muds prohibits the successful drilling and/or completion of a well. Today, with increasing environmental concerns, the use of oil-based muds is either prohibited or severely restricted in many areas. In some areas, drilling with oil-based fluids requires mud and cuttings to be contained and hauled to an approved disposal site. The costs of containment, hauling, and disposal can greatly increase the cost of using oil-based fluids.     

1.1.3 Water-Based Fluids

Water based fluids are the most extensively used drilling fluids. They are generally easy to build, inexpensive to maintain, and can be formulated to overcome most drilling problems. In order to better understand the broad spectrum of water-based fluids, they are divided into three major sub - classifications:

1. Inhibitive

2. Non-inhibitive

3. Polymer





Clear Water


Bentonite/ Water

Calcium Based

Salt-Water Based

Potassium Based


          High Temperature


Lignite/Ligno- Sulfonate


Figure 1.2:Classification of Water-Based Fluids (Source:Drilling Mud Rheology and the API Recommended Measurements)

1. Non-Inhibitive Fluids

Those which do not significantly suppress clay swelling, are generally comprised of native clays orcommercial bentonites with some caustic soda or lime. They may also contain deflocculants and/ordispersants such as: lignite, lignosulfonate, or phosphates. Non-inhibitive fluids are generally usedas spud muds. Native solids are allowed to disperse into the system until rheological properties can no longer be controlled by water dilution.

2. Inhibitive Fluids

Those which appreciably retard clay swelling and, achieve inhibition through the presence of cations; typically, Sodium (Na+), Calcium (Ca+2) and Potassium (K+). Generally, K+ or Ca+2, or a combination of the two, provide the greatest inhibition to clay dispersion. These systems are generally used for drilling hydratable clays and sands containing hydratable clays. Because the source of the cation is generally a salt, disposal can become a major portion of the cost of using an inhibitive fluid.

3. Polymer Fluids

Those which rely on macromolecules, either with or without clay interactions to provide mud properties, and are very diversified in their application. These fluids can be inhibitive or non-inhibitive depending upon whether an inhibitive cation is used. Polymers can be used to viscosify fluids, control filtration properties, deflocculates solids, or encapsulate solids. The thermal stability of polymer systems can range upwards to 400°F. In spite of their diversity, polymer fluids have limitations. Solids are a major threat to successfully running a cost-effective polymer mud system.

1.2 Drilling Fluid Function and Performance

Drilling fluids range from simply water or oil to compressed air and pneumatic fluids to more complex water-based or oil-based systems. Drilling fluid additives include weighting materials; viscosifiers; filtration control additives; pH / alkalinity control chemicals; dispersants/deflocculants/ thinners; surfactants and emulsifiers; shale inhibitors; corrosion inhibitors/oxygen scavengers/hydrogen sulfide (H2S) scavengers; lubricants; and bridging agents/lost circulation materials (LCMs). A brief description of these categories is included later in this section.

The principal functions of drilling fluid are to:

i. Control subsurface pressures, maintaining well control;

ii. Remove drill cuttings from beneath the bit and circulate them to the surface;

iii. Maintain wellbore stability, mechanically and chemically;

iv. Transmit hydraulic energy to the drill bit and downhole tools;

v. Cool and lubricate the drill string and bit;

vi. Allow adequate formation evaluation;

vii. Provide a completed wellbore that will produce hydrocarbons;

viii. Suspend or minimize the settling of drill cuttings or weight material when circulation is  stopped, yet allow the removal of drill cuttings in the surface fluids processing system; and

ix. Form a low permeability, thin and tough filter cake across permeable formations.

The performance of these functions depends upon the type of formation being drilled and the various properties of the drilling fluid. Often, compromises are necessary due to a variety of factors. The selection and design of a particular drilling fluid and its properties depends on the complexity of the well being drilled, subsurface pressures and temperatures, logistics, cost and local experience. Drilling fluid performance is also affected by the drilling equipment being used. The properties of the drilling fluid should be adjusted to the hydraulics available for the drilling operation and the well design. Rate of penetration (ROP) and bit life can be improved by optimizing the hydraulic horsepower at the bit, especially for roller cone bits. The ROP and bit life for polycrystalline diamond compact (PDC) cutter bits is improved when an adequate flowrate is used with minimal overbalance. Drilling fluid properties and circulation rates determine the parasitic pressure losses in the drill string and the available pressure at the bit for optimized drilling performance. The ROP is also affected by the density of the mud and nature of the suspended solids. Regular and complete tests are essential to the control of mud properties. The interpretation of the results of these tests and treatments to maintain appropriate fluid properties is vital to the success of the drilling program




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