drilling fluids design and optimization for different …

DRILLING FLUIDS DESIGN AND OPTIMIZATION FOR DIFFERENT WELLS

Home based Internship Report

Of

Department of Petroleum Engineering

Submitted By

Student Name Reg. No.

JOSHIBA APE18002

Signature of HOD

BONAFIDE CERTIFICATE

This is to certify that the home based Internship entitled “Drilling Fluids Design

and Optimization for Different Wells” submitted by Ms. JOSHIBA to the

department of Petroleum Engineering, AMET, India for the award of the degree

of Bachelor of Engineering is a bonafide record of the technical work carried out

by them under my supervision. The contents of this internship, in full or in parts,

have not been submitted to any other institute or university for the award of

any degree or diploma.

Signature

(Mentor)

Dr. Ponmani

Asst. Prof.

Dept. of Petroleum Engineering

Signature

(HOD)

Dr. T. Nagalakshmi

Prof.


INTERNSHIP ALLOCATION REPORT 2019-2020

(In view of advisory from the AICTE, Internship for the year 2019-2020 are offered by the

department of Petroleum Engineering to facilitate the students to take up required work from

their home itself during the lockdown period due to COVID-19 outbreak)

Name of the Programme : B.E Petroleum Engineering

Year of study and batch/Group : II & 11 /G1

Name of the Mentor : Dr. Ponmani

Title of the assigned internship :

Drilling Fluids Design and Optimization for Different

Wells

Nature of Internship : Home Based Group: 1

Reg. No. of the students who are assigned with this Internship:

APE18001

APE18002

APE18003

Total No. of Hours required to complete the internship: 60

Signature of

Mentors

Signature of Internal Examiner

Signature of HOD/Programme

Head




Name of the students Amritha, Joshiba, Andre

Reg. No. APE18001, APE18002, APE18003

Programme of study B.E. Petroleum Engineering

Year & Batch/Group II & 11/G1

Semester IV

Title of Internship Drilling Fluids Design and Optimization for Different

Wells

Duration of Internship 60 Hours

Name of the Mentors Dr. Ponmani

Evaluation by the department

SI

No.

Criteria Max. Marks Marks Allotted

1 Regularity in maintenance of the diary 10 8

2 Adequacy & Quality of information

recorded

10 8

3 Drawing, Sketches and data recorded 10 8

4 Thought process and recording

techniques used

10 8

5 Organization of the information 10 8

6 Originality of the internship report 10 8

7 Adequacy and purposeful write-up of

the internship report

10 8

8 Organization, format, drawing,

sketches, style, language etc. of the

internship report

10 9

9 Practical application, relationship with

basic theory and concepts

10 9

10 Presentation skills 10 9

Total 100 84

Signature of the

mentor

Signature of the Internal Examiner

Signature of the HOD

S. NO Table of Contents Page No

1 Introduction 1

2 Literature survey 2

3 Drilling fluids functions and

composition

5

4 Choice of drilling rig, wellhead and

BOP

11

5 Material and methods 24

6 Drilling fluids types 28

7 Summary and Conclusion 36

1

Introduction:

Background of the study:

Drilling fluid has gone through major technological evolution, since the first

operations performed in the United States, using a simple mixture of water and clays,

to complex mixtures of various organic and inorganic products used in recent times.

These products improve fluid rheological properties and filtration capability,

allowing the bit to penetrate heterogeneous geological formations under the best

conditions. However, the design and production of drilling fluids in oil and gas sector

over the years has been faced with the challenges of either importing the materials

to produce and or in some cases imported, already designed and produced drilling

mud. In this case, industry in this sector adjust the properties of the drilling fluid

with the aid of the right types of additives which are also imported to suit the

formation requirements of the area to be drilled .

Drilling fluid represents around 15- 20% of the total cost of drilling a well and they

should obey three basic and important requirements:-

-They should be environment friendly and easy to use.

-Not too expensive.

-They should not harm the formation extensively.

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Literature review:

We took reference from five different papers and the literature reviews from papers

are written below from different papers:

● According to this paper by Omotioma (2015), the study of cassava starch for the

improvement of the rheological properties of water based mud. The efficiency

of drilling operation is enhanced by the application of drilling mud with suitable

additives. In this experiment, the mud samples were formulated in the absence

and presence of various concentrations of cassava starch. The production method

of the mud and the determination of its rheological and allied properties were

carried out. The cassava starch additive improves the rheological properties of

the drilling mud. The result shows that the mud weight and pH of the formulated

mud in the absence of cassava starch respectively. From the pH value, the

formulated mud is in alkaline state (API, 1993). The effect of concentration of

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the locally sourced cassava starch on the gel strength of the mud is recorded. The gel

strength measures the capability of the formulated drilling fluid to hold particles in

suspension after flow ceases in the absence of cassava starch. For all the period of gel

strength determination, increase in concentration of cassava starch increases the gel

strength of the mud. Similar trend was noticed in the dial- reading results of the drilling

mud. The graphical representation of the plastic viscosity, yield point and apparent

viscosity, as determined by substituting the dial-reading data into Equations, is

present. The graph shows that the cassava starch additive affects the rheological

properties of the drilling mud. The addition of cassava starch additive, there is

improvement in the rheological properties of the drilling mud Increase in temperature

decreases the plastic and apparent viscosities of the drilling mud. A similar trend was

noticed on the effect of temperature on the yield point of the drilling mud.

● Properties of mud formulated with variable concentrations of cellulose

processed from corn cob have been studied (Nmegbu, 2014). The results

obtained were compared with that of a standard mud formulated from

Polyanionic Cellulose (PAC). These results have shown that the pH, mud

density, specific gravity of the mud formulated from corn cob cellulose are

higher than that of the standard mud, but rheology of the prepared mud was lower

than that of the standard mud. The results show that cellulose processed from

corn cob can significantly reduce fluid loss in a water based drilling mud,

suggesting cellulose as a good fluid loss control agent. It is confirmed that

polymer can be used as fluid loss control agent in the mud system. This also

confirms that cellulose processed from corn cobs are preferred fluid loss control

agents than Polyanionic Cellulose (PAC). The result shows the following result.

The pH value of the prepared mud was comparable to that of the standard mud.

The prepared mud density was higher than that of standard mud. Specific gravity

of the prepared mud was considerably high than that of the standard mud. The

rheological properties of the prepared mud were lower than that of the standard

mud. Cellulose from corn cob can control fluid loss in a drilling mud

significantly and even better when the concentration is increased in the water

based mud.

● To prevent fluid loss into formation, an environmentally safe, non-toxic, high

biodegradability and low cost of polymer additive in drilling mud was prepared from corn starch as the fluid loss control agent (Ghazali, 2015). The purpose of

this study was to investigate the potential of utilizing natural polymer-corn starch

acting as fluid loss control agents in water-based drilling mud. The filtration and rheological properties of the water-based mud were analyzed at temperature

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range with 0 to 10 g of corn starch concentration. Experimental results showed

that the higher concentration of corn starch gave better fluid loss control

behaviour. Therefore, there is high potential of corn starch to be used as fluid

loss control agent in drilling mud. The results of the experiments that have been

carried out in the laboratory provide valuable information regarding to the

alternative method to produce more environmental friendly and cost effective

modified starches for drilling fluid design.

● An experimental investigation was carried out by Vikas Mahato (2015) to study

the effect of fly ash on the rheological and filtration properties of water based

drilling fluids with the objective of the development of environmentally

acceptable non-damaging and inhibitive drilling fluid system to drill sensitive

formations. Initially, different drilling fluids combinations were prepared using

Carboxy-methyl cellulose (low viscosity grade), poly-anionic cellulose, Xanthan

gum, and potassium chloride. The rheological properties as well as filtration

properties of these drilling fluids were measured by API recommended methods.

These drilling fluids show very good rheological behaviour but poor filtration

loss characteristics. The result shows that the Effect of fly ash on the rheological

properties is very negligible. Fly ash may compete with other bridging agent due

to its better efficiency, availability, better environmental effects, and low cost

factor. It should be utilized at best as it is the waste product of the industries in

huge amount.

● An experimental approach on the preparation of drilling mud using, local

materials (Dagde, 2014). Properties of mud formulated with variable

concentrations of cellulose processed from groundnut husk have been studied.

The results obtained were compared with that of a standard, mud formulated

from polyanionic cellulose (PAC). The results shows that the pH, mud density,

specific gravity of the mud formulated from groundnut husk cellulose were

higher than that of the standard mud. The result shows, the pH value of the

prepared mud is comparable to that of the standard mud. Mud density of the

prepared mud is higher than that of standard mud. Specific gravity of the

prepared mud was considerately higher than that of the standard mud. The


mud.

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● In a study by Mohammed Wajheeuddin and M. Enamul Hossain, they experimented to obtain an eco friendly drilling mud using three easily available

materials namely date seeds, powdered grass and grass ash. The sieve analysis

and laser particle size analysis were carried out to study the particle size and also the SEM analysis was carried out to determine the elemental composition. The

experimentations were carried out in room temperature to determine its applicability. The studies shows that they are very good Rheology modifier and

can be used as such. Also it shows that they act as filtration control agent to

formulate the water based mud system.

● A study was conducted using mandarin peels powder in which they studied whether it can be used in place of PAC-LV. Mandarin peel is a food waste

product and also biodegradable. The results show that there was a decrease in the alkalinity if the mud by 20% and also it modified the rheological properties

considerably. There was a decrease in the fluid loss concentration by almost 45-

65% and filter cake was increased as well in comparison with PAC-LV. Salinity, resistivity and calcium content were negligible.

● A study was conducted by Onuh. C.Y (2017) to develop a en0vironmental

friendly fluid loss control agent in which coconut shell and corncobs were used to study its effects on the water based drilling mud. The additives were studied

using varied concentrations individually as well as a mixture of both the additives using low pressure and low temperature. The results of the mixture of the

additives were compared with the ones alone. It showed that the mixture of corn cob and coconut shell gives a better yield and can be used as a pH modifier.

● In a study by Salaheldin Elkatatny, micronized starch was used to enhance the

rheological properties of water based mud. The experiments were conducted under High pressure and high temperature. The effect of the size of the starch on

the rheological properties was studied. The results showed that micronized starch

improved the yield point and the plastic viscosity by 250% with an optimum yield ratio of 1.5. When decreasing the starch size under hpht there a reduction

in the fluid loss volume by 50% and filter cake thickness decrease by 35%.

DRILLING FLUIDS :

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● In geotechnical engineering, drilling fluid, also called drilling mud,

is used to aid the drilling of boreholes into the earth. Often used

while drilling oil and natural gas wells and on exploration drilling

rigs, drilling fluids are also used for much simpler boreholes, such

as water wells. One of the functions of drilling mud is to carry

cuttings out of the hole. ●

● The three main categories of drilling fluids are: water-based muds

(WBs), which can be dispersed and non-dispersed; non-aqueous

muds, usually called oil-based muds (OBs); and gaseous drilling

fluid, in which a wide range of gases can be used. Along with their

formatives, these are used along with appropriate polymer and clay

additives for drilling various oil and gas formations. ●

● The main functions of drilling fluids include providing hydrostatic

pressure to prevent formation fluids from entering into the well bore,

keeping the drill bit cool and clean during drilling, carrying out drill

cuttings, and suspending the drill cuttings while drilling is paused

and when the drilling assembly is brought in and out of the hole. The

drilling fluid used for a particular job is selected to avoid formation

damage and to limit corrosion.

●

FUNCTIONS :

Remove cuttings from well

Mud Pit

● Drilling fluid carries the rock excavated by the drill bit up to the

surface. Its ability to do so depends on cutting size, shape, and

density, and speed of fluid traveling up the well (annular velocity).

These considerations are analogous to the ability of a stream to carry

sediment; large sand grains in a slow-moving stream settle to the

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stream bed, while small sand grains in a fast-moving stream are

carried along with the water. The mud viscosity is another important

property, as cuttings will settle to the bottom of the well if the

viscosity is too low.

Fly Ash Absorbent for Fluids in Mud Pits

Other properties include:

● Most drilling muds are thixotropic (viscosity increase during static

conditions). This characteristic keeps the cuttings suspended when

the mud is not flowing during, for example, maintenance.

● Fluids that have shear thinning and elevated viscosities are efficient for hole cleaning.

● Higher annular velocity improves cutting transport. Transport ratio

(transport velocity / lowest annular velocity) should be at least 50%.

● High density fluids may clean holes adequately even with lower

annular velocities (by increasing the buoyancy force acting on

cuttings). But may have a negative impact if mud weight is in excess

of that needed to balance the pressure of surrounding rock

(formation pressure), so mud weight is not usually increased for hole

cleaning purposes.

● Higher rotary drill-string speeds introduce a circular component to

annular flow path. This helical flow around the drill-string causes

drill cuttings near the wall, where poor hole cleaning conditions

occur, to move into higher transport regions of the annulus.

Increased rotation is the one of the best methods for increasing hole

cleaning in high angle and horizontal wells. ●

Suspend and release cuttings

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● Must suspend drill cuttings, weight materials and additives under a

wide range of conditions.

● Drill cuttings that settle can causes bridges and fill, which can cause

stuck-pipe and lost circulation.

● Weight material that settles is referred to as sag, this causes a wide

variation in the density of well fluid, this more frequently occurs in

high angle and hot wells. ● High concentrations of drill solids are detrimental to:

● Drilling efficiency (it causes increased mud weight and viscosity,

which in turn increases maintenance costs and increased dilution)

● Rate of Penetration (ROP) (increases horsepower required to

circulate)

● Mud properties that are suspended must be balanced with properties

in cutting removal by solids control equipment

● For effective solids controls, drill solids must be removed from mud

on the 1st circulation from the well. If re-circulated, cuttings break

into smaller pieces and are more difficult to remove.

● Conduct a test to compare the sand content of mud at flow line and

suction pit (to determine whether cuttings are being removed).

Control formation pressures

● If formation pressure increases, mud density should also be

increased to balance pressure and keep the wellbore stable. The most

common weighting material is barite. Unbalanced formation

pressures will cause an unexpected influx (also known as a kick) of

formation fluids in the wellbore possibly leading to a blowout from

pressured formation fluids.

● Hydrostatic pressure = density of drilling fluid * true vertical depth

* acceleration of gravity. If hydrostatic pressure is greater than or

equal to formation pressure, formation fluid will not flow into the

wellbore.

● Well control means no uncontrollable flow of formation fluids into

the wellbore.

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● Hydrostatic pressure also controls the stresses caused by tectonic

forces, these may make wellbores unstable even when formation

fluid pressure is balanced.

● If formation pressure is subnormal, air, gas, mist, stiff foam, or low

density mud (oil base) can be used.

● In practice, mud density should be limited to the minimum

necessary for well control and wellbore stability. If too great it may

fracture the formation.

Seal permeable formations

● Mud column pressure must exceed formation pressure, in this

condition mud filtrate invades the formation, and a filter cake of

mud is deposited on the wellbore wall.

● Mud is designed to deposit thin, low permeability filter cake to limit

the invasion.

● Problems occur if a thick filter cake is formed; tight hole conditions,

poor log quality, stuck pipe, lost circulation and formation damage.

● In highly permeable formations with large bore throats, whole mud

may invade the formation, depending on mud solids size;

● Use bridging agents to block large opening, then mud solids can

form seal.

● For effectiveness, bridging agents must be over the half size of pore spaces / fractures.

● Bridging agents (e.g. calcium carbonate, ground cellulose).

● Depending on the mud system in use, a number of additives can

improve the filter cake (e.g. bentonite, natural & synthetic polymer,

asphalt and gilsonite).

Maintain wellbore stability

● Chemical composition and mud properties must combine to provide

a stable wellbore. Weight of the mud must be within the necessary

range to balance the mechanical forces.

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● Wellbore instability = sloughing formations, which can cause tight

hole conditions, bridges and fill on trips (same symptoms indicate

hole cleaning problems). ● Wellbore stability = hole maintains size and cylindrical shape.

● If the hole is enlarged, it becomes weak and difficult to stabilize,

resulting in problems such as low annular velocities, poor hole

cleaning, solids loading and poor formation evaluation

● In sand and sandstones formations, hole enlargement can be

accomplished by mechanical actions (hydraulic forces & nozzles

velocities). Formation damage is reduced by conservative

hydraulics system. A good quality filter cake containing bentonite is

known to limit bore hole enlargement.

● In shales, mud weight is usually sufficient to balance formation

stress, as these wells are usually stable. With water base mud,

chemical differences can cause interactions between mud & shale

that lead to softening of the native rock. Highly fractured, dry, brittle

shales can be extremely unstable (leading to mechanical problems).

● Various chemical inhibitors can control mud / shale interactions

(calcium, potassium, salt, polymers, asphalt, glycols and oil – best

for water sensitive formations)

● Oil (and synthetic oil) based drilling fluids are used to drill most

water sensitive Shales in areas with difficult drilling conditions.

● To add inhibition, emulsified brine phase (calcium chloride) drilling

fluids are used to reduce water activity and creates osmotic forces to

prevent adsorption of water by Shales.

Minimizing formation damage

● Skin damage or any reduction in natural formation porosity and

permeability (washout) constitutes formation damage

● skin damage is the accumulation of residuals on the perforations and

that causes a pressure drop through them.

Most common damage;

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● Mud or drill solids invade the formation matrix, reducing porosity and causing skin effect

● Swelling of formation clays within the reservoir, reduced

permeability

● Precipitation of solids due to mixing of mud filtrate and formations

fluids resulting in the precipitation of insoluble salts

● Mud filtrate and formation fluids form an emulsion, reducing

reservoir porosity

● Specially designed drill-in fluids or workover and completion fluids,

minimize formation damage.

Cool, lubricate, and support the bit and drilling assembly

● Heat is generated from mechanical and hydraulic forces at the bit

and when the drill string rotates and rubs against casing and

wellbore.

● Cool and transfer heat away from source and lower to temperature

than bottom hole. ● If not, the bit, drill string and mud motors would fail more rapidly.

● Lubrication based on the coefficient of friction.("Coefficient of

friction" is how much friction on side of wellbore and collar size or

drill pipe size to pull stuck pipe) Oil- and synthetic-based mud

generally lubricate better than water-based mud (but the latter can

be improved by the addition of lubricants).

● Amount of lubrication provided by drilling fluid depends on type &

quantity of drill solids and weight materials + chemical composition

of system.

● Poor lubrication causes high torque and drag, heat checking of the

drill string, but these problems are also caused by key seating, poor

hole cleaning and incorrect bottom hole assemblies design.

● Drilling fluids also support portion of drill-string or casing through

buoyancy. Suspend in drilling fluid, buoyed by force equal to weight

(or density) of mud, so reducing hook load at derrick.

● Weight that derrick can support limited by mechanical capacity,

increase depth so weight of drill-string and casing increase.

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● When running long, heavy string or casing, buoyancy possible to run casing strings whose weight exceed a rig's hook load capacity.

Transmit hydraulic energy to tools and bit

● Hydraulic energy provides power to mud motor for bit rotation and

for MWD (measurement while drilling) and LWD (logging while

drilling) tools. Hydraulic programs base on bit nozzles sizing for

available mud pump horsepower to optimize jet impact at bottom

well.

● Limited to:

● Pump horsepower

● Pressure loss inside drillstring

● Maximum allowable surface pressure

● Optimum flow rate

● Drill string pressure loses higher in fluids of higher densities, plastic

viscosities and solids.

● Low solids, shear thinning drilling fluids such as polymer fluids,

more efficient in transmit hydraulic energy.

● Depth can be extended by controlling mud properties.

● Transfer information from MWD & LWD to surface by pressure

pulse.

Ensure adequate formation evaluation

● Chemical and physical mud properties as well as wellbore

conditions after drilling affect formation evaluation.

● Mud loggers examine cuttings for mineral composition, visual sign

of hydrocarbons and recorded mud logs of lithology, ROP, gas

detection or geological parameters.

● Wireline logging measure – electrical, sonic, nuclear and magnetic

resonance.

● Potential productive zone are isolated and performed formation testing and drill stem testing.

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● Mud helps not to disperse of cuttings and also improve cutting

transport for mud loggers determine the depth of the cuttings

originated.

● Oil-based mud, lubricants, asphalts will mask hydrocarbon

indications.

● So mud for drilling core selected base on type of evaluation to be

performed (many coring operations specify a bland mud with

minimum of additives).

Control corrosion (in acceptable level)

● Drill-string and casing in continuous contact with drilling fluid may

cause a form of corrosion.

● Dissolved gases (oxygen, carbon dioxide, hydrogen sulfide) cause

serious corrosion problems; ● Cause rapid, catastrophic failure

● May be deadly to humans after a short period of time

● Low pH (acidic) aggravates corrosion, so use corrosion

coupons[clarification needed] to monitor corrosion type, rates and

to tell correct chemical inhibitor is used in correct amount.

● Mud aeration, foaming and other O2 trapped conditions cause

corrosion damage in short period time.

● When drilling in high H2S, elevated the pH fluids + sulfide

scavenging chemical (zinc).

Facilitate cementing and completion

● Cementing is critical to effective zone and well completion.

● During casing run, mud must remain fluid and minimize pressure

surges so fracture induced lost circulation does not occur.

● Temperature of water used for cement must be within tolerance of

cementers performing task, usually 70 degrees, most notably in

winter conditions.

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● Mud should have thin, slick filter cake, with minimal solids in filter

cake, wellbore with minimal cuttings, caving or bridges will prevent

a good casing run to bottom. Circulate well bore until clean.

● To cement and completion operation properly, mud displace by

flushes and cement. For effectiveness;

● Hole near gauges, use proper hole cleaning techniques, pumping

sweeps at TD, and perform wiper trip to shoe.

● Mud low viscosity, mud parameters should be tolerant of formations

being drilled, and drilling fluid composition, turbulent flow - low

viscosity high pump rate, laminar flow - high viscosity, high pump

rate. ● Mud non progressive gel strength[clarification needed]

Minimize impact on environment

Unlined drilling fluid sumps were commonplace before the environmental consequences were recognized.

● Mud is, in varying degrees, toxic. It is also difficult and expensive

to dispose of it in an environmentally friendly manner. A Vanity Fair

article described the conditions at Lago Agrio, a large oil field in

Ecuador where drillers were effectively unregulated.

● Water based drilling fluid has very little toxicity, made from water,

bentonite and barite, all clay from mining operations, usually found

in Wyoming and in Lunde, Telemark. There are specific chemicals

that can be used in water based drilling fluids that alone can be

corrosive and toxic, such as hydrochloric acid. However, when

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mixed into water based drilling fluids, hydrochloric acid only

decreases the pH of the water to a more manageable level. Caustic

(sodium hydroxide), anhydrous lime, soda ash, bentonite, barite and

polymers are the most common chemicals used in water based

drilling fluids. Oil Base Mud and synthetic drilling fluids can

contain high levels of benzene, and other chemicals

Most common chemicals added to OBM Muds:

● Barite

● Bentonite

● Diesel

● Emulsifiers

● Water

PROPERTIES OF DRILLING FLUIDS :

The properties of drilling fluid are:

A)DENSITY(SPECIFIC GRAVITY)

Density is defined as weight per unit volume. It is expressed either in ppg

(lbs gallons) or pound per cubic feet (lb/ft3) OR kg/M^3 or gm/cm^3 or

compared to the weight of an equal volume of water as specific gravity.

Density is measured with a mud balance. One of the main functions of

drilling fluid is to confine formation fluids to their native formations or

beds.

WEIGHTING MATERIALS COMMONLY ADDED TO MUDS

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CALIBRATION

The instrument should be calibrated frequently with fresh water. Fresh

water should give a reading of 8.33 ppg or 62.3 lb/cub.ft. or 1.00

gm/cub.cm. at 700f. (210c). If it shows wrong reading then the balancing

screw should be adjusted.

B) VISCOSITY & GEL STRENGTH

Viscosity is defined as the resistance to flow while the gel strength is the

thixotropic property of mud i.e. Mud tends to thicken up if left unagitated

for some time. Viscosity is usually measured by marsh funnel. It is the

timed rate of flow and measured in seconds per quart. However funnel

viscosity does not represent the correct value of the actual viscosity of

mud.

More meaningful information concerning viscosity and its control can be

obtained with a rotational viscometer. Viscosity and gel strength increase

during drilling penetration of the formations by the bit, contributes the

active solids, inert solids and contaminants to the system. This can cause

increased viscosity and / or gel strength to level, which may not be

acceptable. In general, when these increases occur, water or chemicals

(thinners) or both may be added to control them.

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MUD ADDITIVES COMMONLY USED

FOR IMPARTING VISCOSITY

AND REDUCING VISCOSITY

C) PLASTIC VISCOSITY (Pv) (UNIT OF MEASUREMENT

CENTIPOISE) :

Plastic viscosity is that part of flow resistance, which is caused by

mechanical friction. This friction occurs : (1) between the solids in mud

(2) between the solids and liquids that surround them

(3) with the shearing of the liquid itself.

For practical field purpose, however the pv depends upon the

concentration of mud solids.

D) YIELD POINT (Yp) : MEASURED in lb/100 sq. ft.

Yield point is the second component of resistance to flow in a drilling

fluid on account of the electro-chemical or attractive forces present in

mud. These forces are as a result of negative and positive charges located

on or near the particle surfaces. Yield point is a measure of these forces

under flow conditions and depends upon

(1) surface properties of the mud solids

(2) Volume concentration of solids

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(3) the electrical environment of these solids (concentration and types of ions in the fluid phase of the mud).

Increase in the yield point may be due to several factors such as

breakdown of clays particles by grinding action of bit, introduction of

inert solids and soluble contaminants such as salt, cement, etc.

EQUIPMENT The following instruments are used to measure the

viscosity and /or gel strength of drilling fluids.

A. Marsh funnel

B. Direct indicating viscometer

DIAGRAM DEPICTING MARSH FUNNEL

DIAGRAM DEPICTING DIRECT INDICATING VISCOMETER

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APPARENT VISCOSITY:

THE APPARENT VISCOSITY IN CENTIPOISE EQUALS THE 600

rpm READING DIVIDED BY 2 [A.V. =600/2 IN CENTIPOISE]

PLASTIC VISCOSITY (PV):

FRICTION FORCE BETWEEN TWO PARTICLES IS KNOWN AS

PLASTIC VISCOSITY READING AT 600 rpm – READING AT 300

rpm.

[P.V. = Ø600 - Ø 300 IN CENTIPOISE]

YIELD POINT:

300 rpm READING – PLASTIC VISCOSITY

[Yp = 300 – PV IN lb/100 sq. ft.]

APPLICATION OF FANN VISCOMETER

1. DETERMINATION OF APPARENT VISCOSITY, PLASTIC

VISCOSITY AND YIELD POINT.

2. DETERMINATION OF GEL STRENGTH OR THIXOTROPIC

PROPERTIES OF THE DRILLING FLUIDS.

E) GEL STRENGTH

Two values, the 10 second gel strength is known as gel-0 and the 10

minute strength is known as gel-10. These two values can be determined

as follows. Allow the mud to stand undisturbed for 10 seconds. Then

slowly and steadily rotate at 3 rpm. Allow the mud to stand static for 10

mins. Then again slowly rotate at 3 rpm. By this calculate gel0 and gel10

in lb/100 sq.Ft.

F) FILTRATION LOSS

The filtration property of a drilling fluid is indicative of the ability of the

solid components of the mud to form a filter cake and the magnitude of

cake permeability. The lower the permeability, the thinner is the filter

cake and lowers the volume of filtrate from mud. Filtration property is

dependent upon the amount and physical state of colloidal material in the

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mud. A thick filter cake is undesirable as it constricts the walls of the

borehole and allows excessive amount of filtrate to move into the

formation resulting in further problems such as caving, tight pulls, held

ups, stuck ups etc.

Therefore a satisfactory fluid loss value and deposition of a thin,

impermeable filter cake are often the determining factors for successful

performance of a drilling fluid. There are two types of filtrations namely

dynamic filtration, when the mud is circulating, and static filtration when

the fluid is at rest.

Dynamic filtration differs from static filtration in that the flow of mud by

the walls of the borehole tends to erode away the filter cake as the

filtration process deposits it. The filtration cake builds up until the rate of

deposition equals the rate of erosion. When the filter cake reaches an

equilibrium thickness the rate of filtration becomes constant.

1. CARBOXY METHYL CELLULOSE also kown asCMC (L.V ; H.V) :

FUNCTIONS

SELECTIVE FLOCCULANT, VISCOSIFIER FLUID LOSS,

CONTROL IN FRESH AND BRACKISH WATER, IMPARTS

DISPERSING PROPERTIES TO SALT WATER SYSTEM.

2. PREGELATINISED STARCH

FUNCTIONS

FLUID LOSS CONTROL IN SALT WATER SYSTEM ; CALCIUM

MUD SYSTEM .

3. CARBOXY METHYL STARCH

FUNCTIONS

VISCOSITIES AND FILTRATION REDUCER.

21

4. POLYANIONIC CELLULOSE also known as (PAC) (L.V&R.G) FUNCTIONS

FLUID LOSS CONTROL IN FRESH AND SALT WATER SYSTEM

AND VISCOSIFIER.

5. HT-STABLE RESIN LIGNITE

FUNCTION

FILTRATION CONTROL UNDER HIGH TEMPERATURE

CONDITIONS.

6. SYNTHETIC POLYMERS

VISCOSITIES AND FILTRATE REDUCER.

7.X-C POLYMER

PRIMARY VISCOSIFYING POLYMER FOR ALL WATER BASE

MUDS.

PH:

pH Is the measurement of relative acidity or alkalinity of a liquid. MUD

pH Affects the dispersibility of clays, solubility of various products and

chemicals corrosion of steel materials, and mud rheological properties.

22

Typical pH Range is 9.0 to 10.5; However, high pH muds can range up to 12.5 TO 13.0.

There are several methods to measure PH some of which are as follows:

1. PAPER TEST STRIPS

DESCRIPTION:

The test paper is impregnated with dyes of such nature that the colour is

dependent upon the ph of the medium in which the paper is placed. A

standard colour chart is supplied in a wide range type, which permits

estimation of ph to 0.5 unit, and in narrow range papers with which the

pH can be estimated to 0.2 unit.

2. GLASS ELECTRODE pH METER:

DESCRIPTION:

The glass electrodes ph meter consists of a glass electrode system, an

electronic amplifier and a meter calibrated in ph units.

The electrode system is composed of:The glass electrodes, which consists

of a thin walled bulb made of special glass within which is sealed a

suitable electrolyte and electrode

3. CATION EXCHANGE CAPACITY OR METHYLELENE BLUE

TEST (MBT)

It indicates the amount of active clay in the mud. It measures the total cec

of the clay by titrating with standard methylene blue solution. Bentonite

content (active clay) can be estimated (if other adsorptive materials are

not present), based on an exchange capacity of 75 mill equivalent per100

gm of dry Bentonite.

4. METHYLENE BLUE TEST FOR CATION EXCHANGE

CAPACITY

I. Methylene blue solution (3.74 gm U.S.P. Grade methylene blue per 1000

cub.cm.) 1CM = 0.01 milli-Equivalent.

23

II. Hydrogen peroxide – 3% Solution.

III. Dilute sulfuric acid (approx. 5N)

IV. One 2.5 cc or 3 cc syringe

v. Flask, burette, graduated cylinder, hot plate, filter paper etc.

G) LUBRICITY

Requirement for lubrication is critical (especially in directional well) to

reduce torque and drag. Lubricating testers are modified to measure

lubricity coefficient and film strength (ep test). Based on which

recommendations are given for treatment of the mud with lubricating

agents.

MATERIALS AND METHODS :

Raw Materials: The equipment used in this work include; graduated measuring

cylinder, beakers, electronic weighing balance, mixer, viscometer, drilling mud

balance, water bath, pH meter, and stop watch, pipette.

TABLE 1: THE RAW MATERIALS USED IN THE FORMULATION OF THE

WATER BASED DRILLING FLUIDS ARE PRESENTED IN TABLE 1 BELOW.

S.No .

Raw Material Functions Quantity

1. Water Base Fluid 245 ml

2. Bentonite Viscosity and filtration control 5.0 gm

3. Barite Weighing agent 12 gm

4. Xanthan gum Viscosity and fluid loss in low solid

mud

0.4 gm

5. Carboxy-methyl

cellulose

Fluid loss control and viscosifier 0.5 gm

6. Potassium

hydroxide (KOH)

Potassium source in inhibitive

potassium mud

0.1gm

24

7. Sodium carbonate

(Na2CO3)

Calcium precipitant in lower pH

mud

12 gm

8. Hibiscus extract Rheological property changes 0% 4% 5% 6%

concentration by

weight

9. formaldehyde Control bacterial action 0.1 gm

Equipment description:

Mud balance: A device to measure density (weight) of mud, cement or other liquid

or slurry. A mud balance consists of a fixed-volume mud cup with a lid on one end

of a graduated beam and a counterweight on the other end. A slider weight can be

moved along the beam and a bubble indicates when the beam is level. Density is

read at the point where the slider weight sits on the beam at level. Accuracy of mud

density should be within +/-0.1 lbm/gal (+/-0.01 g/cm3). A mud balance can be

calibrated with water or other liquid of known density by adjusting the counter

weight.

pH meter: pH meter works on the principle that an interface of two liquids produce

an electric potential which can be measured. When a liquid inside an enclosure made

of glass is placed inside a solution other than that liquid, there exists an

electrochemical potential between the two liquids.

● A measuring electrode: It is a tube made up of glass and consists of a thin glass

bulb welded to it, filled up with Potassium Chloride solution of known pH of 7. It

also contains a block of silver chloride attached to a silver element. It generates

the voltage used to measure pH of the unknown solution.

● A Reference Electrode: It is a glass tube consisting of a potassium chloride

solution in intimate contact with a mercury chloride block at the end of the

potassium chloride. It is used to provide a stable zero-voltage connection to

complete the whole circuit.

● Preamplifier: It is a signal conditioning device and converts the high impedance

pH electrode signal to a low impedance signal. It strengthens and stabilizes the

signal, making it less susceptible to electrical noise.

● Transmitter or Analyzer: It is used to display the sensor’s electrical signal and

consists of a temperature sensor to compensate for the change in temperature.

The electrode is placed inside the beaker filled with the mud. The glass bulb welded

at the end of the measuring electrode consist of lithium ions doped to it which makes

25

it act as an ion-selective barrier and allows the hydrogen ions from the unknown

solution to migrate through the barrier and interacts with the glass, developing an

electrochemical potential related to the hydrogen ion concentration. The

measurement electrode potential thus changes with the hydrogen ion concentration.

On the other hand, the reference electrode potential doesn’t change with the hydrogen

ion concentration and provides a stable potential against which the measuring

electrode is compared. It consists of a neutral solution that is allowed to exchange

ions with the unknown solution through a porous separator, thus forming a low

resistance connection to complete the whole circuit. The potential difference between

the two electrodes gives a direct measurement of the hydrogen ion concentration or

pH of the system and is first pre-amplified to strengthen it and then given to the

voltmeter.

Fann Viscometer: The OFITE Model 800 Viscometer determines the flow

characteristics of oils and drilling fluids in terms of shear rate and shear stress over

various times and temperature ranges at atmospheric pressure. Speeds are easily

changed with a control knob, and shear stress values are displayed on a lighted

magnified dial for ease of reading. The viscometer’s motor RPM is continuously

monitored and automatically adjusted by the OFITE Pulse-Power electronic speed

regulator to maintain a constant shear rate under varying input power and drilling

fluid shear conditions. The eight precisely regulated test speeds (shear rates in RPM)

are as follows: 3 (Gel), 6, 30, 60, 100, 200, 300, and 600. A higher stirring speed is

also provided. Speeds may be changed with a control knob selection, without

stopping the motor. The Model 800 is suitable for both field and laboratory use and

uses a motor-driven electronic package to provide drilling fluid engineers with an

extremely accurate and versatile tool. The Model 800 operates from a 13–16 VDC

power source. The electronic regulator continuously monitors and automatically

adjusts the rotational speed to maintain a constant shear rate under varying fluid

shear conditions and input power variations that are commonly found on-site.

DRILLING FLUID TYPES :

There are several different types of drilling fluids, based on both their composition

and use. The three key factors that drive decisions about the type of drilling fluid

selected for a specific well are:

https://www.elprocus.com/ultrasonic-object-detection-circuit-8051-microcontroller/

26

● Cost

● Technical performance

● Environmental impact.

Selecting the correct type of fluid for the specific conditions is an important part of

successful drilling operations.

Classification of drilling fluids

World Oil’s annual classification of fluid systems[1] lists nine distinct categories of

drilling fluids, including:

● Freshwater systems

● Saltwater systems

● Oil- or synthetic-based systems

● Pneumatic (air, mist, foam, gas) “fluid” systems

Three key factors usually determine the type of fluid selected for a specific well:

● Cost


● Environmental impact

Water-based fluids (WBFs) are the most widely used systems, and are considered

less expensive than oil-based fluids (OBFs) or synthetic-based fluids (SBFs). The

OBFs and SBFs—also known as invert-emulsion systems—have an oil or synthetic

base fluid as the continuous(or external) phase, and brine as the internal phase.

Invert-emulsion systems have a higher cost per unit than most water-based fluids, so

they often are selected when well conditions call for reliable shale inhibition and/or

excellent lubricity. Water-based systems and invert-emulsion systems can be

formulated to tolerate relatively high downhole temperatures. Pneumatic systems

most commonly are implemented in areas where formation pressures are relatively

low and the risk of lost circulation or formation damage is relatively high. The use

of these systems requires specialized pressure-management equipment to help

27

prevent the development of hazardous conditions when hydrocarbons are

encountered.

Water-based fluids

Water-based fluids (WBFs) are used to drill approximately 80% of all wells. The

base fluid may be fresh water, seawater, brine, saturated brine, or a formate brine.

The type of fluid selected depends on anticipated well conditions or on the specific

interval of the well being drilled. For example, the surface interval typically is drilled

with a low-density water- or seawater-based mud that contains few commercial

additives. These systems incorporate natural clays in the course of the drilling

operation. Some commercial bentonite or attapulgite also may be added to aid in

fluid-loss control and to enhance hole-cleaning effectiveness. After surface casing is

set and cemented, the operator often continues drilling with a WBF unless well

conditions require displacing to an oil- or synthetic-based system.

WBFs fall into two broad categories: nondispersed and dispersed.

Nondispersed sytems

Simple gel-and-water systems used for tophole drilling are nondispersed, as are

many of the advanced polymer systems that contain little or no bentonite. The natural

clays that are incorporated into nondispersed systems are managed through dilution,

encapsulation, and/or flocculation. A properly designed solids-control system can be

used to remove fine solids from the mud system and help maintain drilling

efficiency. The low-solids, nondispersed (LSND) polymer systems rely on high- and

low-molecular-weight long-chain polymers to provide viscosity and fluid-loss

control. Low-colloidal solids are encapsulated and flocculated for more efficient

removal at the surface, which in turn decreases dilution requirements. Specially

developed high-temperature polymers are available to help overcome gelation issues

that might occur on high-pressure, high-temperature (HP/HT) wells.[3] With proper

28

treatment, some LSND systems can be weighted to 17.0 to 18.0 ppg and run at 350°F

and higher.

Dispersed systems

Dispersed systems are treated with chemical dispersants that are designed to

deflocculate clay particles to allow improved rheology control in higher-density

muds. Widely used dispersants include lignosulfonates, lignitic additives, and

tannins. Dispersed systems typically require additions of caustic soda (NaOH) to

maintain a pH level of 10.0 to 11.0. Dispersing a system can increase its tolerance

for solids, making it possible to weight up to 20.0 ppg. The commonly used

lignosulfonate system relies on relatively inexpensive additives and is familiar to

most operator and rig personnel. Additional commonly used dispersed muds include

lime and other cationic systems. A solids-laden dispersed system also can decrease

the rate of penetration significantly and contribute to hole erosion.

Saltwater drilling fluids

Saltwater drilling fluids often are used for shale inhibition and for drilling salt

formations. They also are known to inhibit the formation of ice-like hydrates that

can accumulate around subsea wellheads and well-control equipment, blocking lines

and impeding critical operations. Solids-free and low-solids systems can be

formulated with high-density brines, such as:

● Calcium chloride

● Calcium bromide

● Zinc bromide

● Potassium and cesium formate

Polymer drilling fluids

Polymer drilling fluids are used to drill reactive formations where the requirement

for shale inihbition is significant. Shale inhibitors frequently used are salts, glycols

29

and amines, all of which are incompatible with the use of bentonite. These systems

typically derive their viscosity profile from polymers such as xanthan gum and fluid

loss control from starch or cellulose derivatives. Potassium chloride is an

inexpensive and highly effective shale inhibitor which is widely used as the base

brine for polymer drilling fluids in many parts of the world. Glycol and amine-based

inhibitors can be added to further enhance the inhibitive properties of these fluids.

Drill-in fluids

Drilling into a pay zone with a conventional fluid can introduce a host of previously

undefined risks, all of which diminish reservoir connectivity with the wellbore or

reduce formation permeability. This is particularly true in horizontal wells, where

the pay zone can be exposed to the drilling fluid over a long interval. Selecting the

most suitable fluid system for drilling into the pay zone requires a thorough

understanding of the reservoir. Using data generated by lab testing on core plugs

from carefully selected pay zone cores, a reservoir-fluid-sensitivity study should be

conducted to determine the morphological and mineralogical composition of the

reservoir rock. Natural reservoir fluids should be analyzed to establish their chemical

makeup. The degree of damage that could be caused by anticipated problems can be

modeled, as can the effectiveness of possible solutions for mitigating the risks.

A drill-in fluid (DIF) is a clean fluid that is designed to cause little or no loss of the

natural permeability of the pay zone, and to provide superior hole cleaning and easy

cleanup. DIFs can be:

● Water-based

● Brine-based

● Oil-based

● Synthetic-based

In addition to being safe and economical for the application, a DIF should be

compatible with the reservoir’s native fluids to avoid causing precipitation of salts

or production of emulsions. A suitable nondamaging fluid should establish a filter

cake on the face of the formation, but should not penetrate too far into the formation

30

pore pattern. The fluid filtrate should inhibit or prevent swelling of reactive clay

particles within the pore throats.

Formation damage commonly is caused by:

● Pay zone invasion and plugging by fine particles

● Formation clay swelling

● Commingling of incompatible fluids

● Movement of dislodged formation pore-filling particles

● Changes in reservoir-rock wettability

● Formation of emulsions or water blocks

Once a damage mechanism has diminished the permeability of a reservoir, it seldom

is possible to restore the reservoir to its original condition.

Oil-based fluids

Oil-based systems were developed and introduced in the 1960s to help address

several drilling problems:

● Formation clays that react, swell, or slough after exposure to WBFs

● Increasing downhole temperatures

● Contaminants

● Stuck pipe and torque and drag

Oil-based fluids (OBFs) in use today are formulated with diesel, mineral oil, or low-

toxicity linear olefins and paraffins. The olefins and paraffins are often referred to

as "synthetics" although some are derived from distillation of crude oil and some are

chemically synthesised from smaller molecules. The electrical stability of the

internal brine or water phase is monitored to help ensure that the strength of the

emulsion is maintained at or near a predetermined value. The emulsion should be

31

stable enough to incorporate additional water volume if a downhole water flow is

encountered.

Barite is used to increase system density, and specially-treated organophilic

bentonite is the primary viscosifier in most oil-based systems. The emulsified water

phase also contributes to fluid viscosity. Organophilic lignitic, asphaltic and

polymeric materials are added to help control HP/HT(High pressure/High

temperature) fluid loss. Oil-wetting is essential for ensuring that particulate materials

remain in suspension. The surfactants used for oil-wetting also can work as thinners.

Oil-based systems usually contain lime to maintain an elevated pH, resist adverse

effects of hydrogen sulfide (H2S) and carbon dioxide (CO2) gases, and enhance

emulsion stability.

Shale inhibition is one of the key benefits of using an oil-based system. The high-

salinity water phase helps to prevent shales from hydrating, swelling, and sloughing

into the wellbore. Most conventional oil-based mud (OBM) systems are formulated

with calcium chloride brine, which appears to offer the best inhibition properties for

most shales.

The ratio of the oil percentage to the water percentage in the liquid phase of an oil-

based system is called its oil/water ratio. Oil-based systems generally function well

with an oil/water ratio in the range from 65/35 to 95/5, but the most commonly

observed range is from 70/30 to 90/10.

The discharge of whole fluid or cuttings generated with OBFs is not permitted in

most offshore-drilling areas. All such drilled cuttings and waste fluids are processed,

and shipped to shore for disposal. Whereas many land wells continue to be drilled

with diesel-based fluids, the development of synthetic-based fluids (SBFs) in the late

1980s provided new options to offshore operators who depend on the drilling

performance of oil-based systems to help hold down overall drilling costs but require

32

more environmentally-friendly fluids. In some areas of the world such as the North

Sea, even these fluids are prohibited for offshore discharge.

Synthetic-based drilling fluids

Synthetic-based fluids were developed out of an increasing desire to reduce the

environmental impact of offshore drilling operations, but without sacrificing the

cost-effectiveness of oil-based systems.

Like traditional OBFs, SBFs can be used to:

● Maximize rate of penetrations (ROPs)

● Increase lubricity in directional and horizontal wells

● Minimize wellbore-stability problems, such as those caused by reactive shales

Field data gathered since the early 1990s confirm that SBFs provide exceptional

drilling performance, easily equaling that of diesel- and mineral-oil-based fluids.

In many offshore areas, regulations that prohibit the discharge of cuttings drilled

with OBFs do not apply to some of the synthetic-based systems. SBFs’ cost per

barrel can be higher, but they have proved economical in many offshore applications

for the same reasons that traditional OBFs have: fast penetration rates and less mud-

related nonproductive time (NPT). SBFs that are formulated with linear alphaolefins

(LAO) and isomerized olefins (IO) exhibit the lower kinematic viscosities that are

required in response to the increasing importance of viscosity issues as operators

move into deeper waters. Early ester-based systems exhibited high kinematic

viscosity, a condition that is magnified in the cold temperatures encountered in

deepwater risers. However, a shorter-chain-length (C8), low-viscosity ester that was

developed in 2000 exhibits viscosity similar to or lower than that of the other base

fluids, specifically the heavily used IO systems. Because of their high

33

biodegradability and low toxicity, esters are universally recognized as the best base

fluid for environmental performance.

By the end of 2001, deepwater wells were providing 59%; of the oil being produced

in the Gulf of Mexico. Until operators began drilling in these deepwater locations,

where the pore pressure/fracture gradient (PP/FG) margin is very narrow and mile-

long risers are not uncommon, the standard synthetic formulations provided

satisfactory performance. However, the issues that arose because of deepwater

drilling and changing environmental regulations prompted a closer examination of

several seemingly essential additives.

When cold temperatures are encountered, conventional SBFs might develop

undesirably high viscosities as a result of the organophilic clay and lignitic additives

in the system. The introduction of SBFs formulated with zero or minimal additions

of organophilic clay and lignitic products allowed rheological and fluid-loss

properties to be controlled through the fluid-emulsion characteristics. The

performance advantages of these systems include:

● High, flat gel strengths that break with minimal initiation pressure

● Significantly lower equivalent circulating densities (ECDs)

● Reduced mud losses while drilling, running casing, and cementing

All-oil fluids

Normally, the high-salinity water phase of an invert-emulsion fluid helps to stabilize

reactive shale and prevent swelling. However, drilling fluids that are formulated with

diesel- or synthetic-based oil and no water phase are used to drill long shale intervals

where the salinity of the formation water is highly variable. By eliminating the water

phase, the all-oil drilling fluid can preserve shale stability throughout the interval.

Pneumatic-drilling fluids

34

Compressed air or gas can be used in place of drilling fluid to circulate cuttings out

of the wellbore. Pneumatic fluids fall into one of three categories:

● Air or gas only

● Aerated fluid

● Foam

Pneumatic-drilling operations require specialized equipment to help ensure safe

management of the cuttings and formation fluids that return to surface, as well as

tanks, compressors, lines, and valves associated with the gas used for drilling or

aerating the drilling fluid or foam.

Except when drilling through high-pressure hydrocarbon- or fluid-laden formations

that demand a high-density fluid to prevent well-control issues, using pneumatic

fluids offers several advantages[6]:

● Little or no formation damage

● Rapid evaluation of cuttings for the presence of hydrocarbons

● Prevention of lost circulation

● Significantly higher penetration rates in hard-rock formations

Specialty products

Drilling-fluid service companies provide a wide range of additives that are designed

to prevent or mitigate costly well-construction delays. Examples of these products

include:

● Lost-circulation materials (LCM) that help to prevent or stop downhole mud

losses into weak or depleted formations.

● Spotting fluids that help to free stuck pipe.

● Lubricants for WBFs that ease torque and drag and facilitate drilling in high-

angle environments.

35

● Protective chemicals (e.g., scale and corrosion inhibitors, biocides, and H2S

scavengers) that prevent damage to tubulars and personnel.

Lost-circulation materials

Many types of LCM are available to address loss situations:

The development of deformable graphitic materials that can continuously seal off

fractures under changing pressure conditions has allowed operators to cure some

types of losses more consistently. The application of these and similar materials to

prevent or slow down the physical destabilisation of the wellbore has proved

successful. Hydratable and rapid-set lost-circulation pills also are effective for curing

severe and total losses. Some of these fast-acting pills can be mixed and pumped

with standard rig equipment, while others require special mixing and pumping

equipment.

Spotting fluids

Most spotting fluids are designed to penetrate and break up the wall cake around the

drillstring. A soak period usually is required to achieve results. Spotting fluids

typically are formulated with a base fluid and additives that can be incorporated into

the active mud system with no adverse effects after the pipe is freed and/or

circulation resumes.

Lubricants

Lubricants might contain hydrocarbon-based materials, or can be formulated

specifically for use in areas where environmental regulations prohibit the use of an

oil-based additive. Tiny glass or polymer beads also can be added to the drilling fluid

to increase lubricity. Lubricants are designed to reduce friction in metal-to-metal

contact, and to provide lubricity to the drillstring in the open hole, especially in

36

deviated wells, where the drillstring is likely to have continuous contact with the

wellbore.

Corrosion, inhibitors, biocides, and scavengers

Corrosion causes the majority of drillpipe loss and damages casing, mud pumps,

bits, and downhole tools. As downhole temperatures increase, corrosion also

increases at a corresponding rate, if the drillstring is not protected by chemical

treatment. Abrasive materials in the drilling fluid can accelerate corrosion by

scouring away protective films. Corrosion, typically, is caused by one or more

factors that include:

Drillstring coupons can be inserted between joints of drillpipe as the pipe is tripped

in the hole. When the pipe next is tripped out of the hole, the coupon can be examined

for signs of pitting and corrosion to determine whether the drillstring components

are undergoing similar damage.

H2S and CO2 frequently are present in the same formation. Scavenger and inhibitor

treatments should be designed to counteract both gases if an influx occurs because

of underbalanced drilling conditions. Maintaining a high pH helps control H2S and

CO2, and prevents bacteria from souring the drilling fluid. Bacteria also can be

controlled using a microbiocide additive.

Summary and Conclusion

The role of drilling fluids has been discussed along with functions and criteria. Drilling

fluids have the potential to cool the bit and drive the hydrocarbon effectively to the

surface. Maintaining a high pH helps control H2S and CO2, and prevents bacteria from

souring the drilling fluids.

COAL BED METHANE PRODUCTION REVIEW BASED ON GEOLOGICAL

STRUCTURE


Of


Submitted By


Veerachidambaranathan APE18009

Signature of HOD


This is to certify that the home based Internship entitled “Coal Bed Methane

Production Review Based On Geological Structure” submitted by Mr.

Veerachidambaranathan to the department of Petroleum Engineering, AMET,

India for the award of the degree of Bachelor of Engineering is a bonafide record

of the technical work carried out by them under my supervision. The contents

of this internship, in full or in parts, have not been submitted to any other

institute or university for the award of any degree or diploma.

Signature

(Mentor)

Dr. Rajesh Kanna

Associate. Prof.


Signature

(HOD)

Dr. T. Nagalakshmi

Prof.








Name of the Mentor : Dr. Rajesh Kanna


COAL BED METHANE PRODUCTION REVIEW BASED

ON GEOLOGICAL STRUCTURE



APE18008

APE18010

APE18009


Signature of

Mentors

Signature of Internal

Examiner


Head




Name of the students Skandha, Veerachidambaranathan, Vineeth

Reg. No. APE18008, APE18009. APE18010



Semester IV

Title of Internship Coal bed methane production review based on

geological structure




SI

No.




recorded

10 8



techniques used

10 8





10 8



internship report

10 9



10 8


Total 100 81

Signature of the

mentor




1 Abstract 2

2 Global and Indian Scenario 4

3 Materials and method 9

4 Gradation of coal under study 13

5 Estimation of methane content 14

6 Relation between total gas content

and non-coal content

15

7 Gas transportation mechanism 16

8 Enhanced oil recovery 17

9 Conclusion 18

2

Abstract

To meet the rapidly increasing demand for energy and faster depletion of conventional

energy resources, India with other countries is madly searching for alternate resources

like coal bed methane (CBM), shale gas, gas hydrate. CBM is considered to be the most

viable resource of these. The present paper discussed about the prospect of CBM as a

clean energy source, difficulty involved in production of CBM, enhanced recovery

techniques. In this regards, one Indian coal field is selected and gas content is determined

by analyzing the collected samples.

Index Terms—CBM, CO2 Sequestration, Global Warming, Methane Recovery, Gas

Content, Clean Energy, Singareni Coal Field.

3

I. INTROODUCTION

Depletion of conventional resources, and increasing demand for clean energy,

forces India to hunt for alternatives to conventional energy resources. Intense

importance has been given for finding out more and more energy resources;

specifically non-conventional ones like CBM, shale gas & gas hydrates, as gas is

less polluting compared to oil or coal. CBM is considered to be one of the most

viable alternatives to combat the situation [1]. With growing demand and rising oil

and gas prices, CBM is definitely a feasible alternative supplementary energy

source.

Coalbed methane is generated during coalification process which gets adsorbed on

coal at higher pressure. However, it is a mining hazard. Presence of CBM in

underground mine not only makes mining works difficult and risky, but also makes

it costly. Even, its ventilation to atmosphere adds green house gas causing global

warming. However, CBM is a remarkably clean fuel if utilized efficiently. CBM is

a clean gas having heating value of approximately 8500 KCal/kg compared to

9000 KCal/kg of natural gas.

4

It is of pipe line quality; hence can be fed directly to national pipeline grid without

much treatment. Production of methane gas from coalbed would lead to de-

methanation of coal beds and avoidance of methane emissions into the atmosphere,

thus turning an environmental hazard into a clean energy resource.

As the third largest coal producer in the world, India has good prospects for

commercial production of coal bed methane. Methane may be a possible

alternative to compressed natural gas (CNG) and its use as automotive fuel will

certainly help reducing pollution levels.

India is one of the select countries which have undertaken steps through a

transparent policy to harness domestic CBM resources. The Government of India

has received overwhelming responses from prospective producers with several big

players starting operations on exploration and development of CBM in India and

set to become the fourth after US, Australia and China in terms of exploration and

production of coal bed methane.

However, in order to fully develop India's CBM potential, delineation of

prospective CBM blocks is necessary. There are other measures like provision of

technical training, promotion of research and development, and transfer of CBM

development technologies that can further the growth of the sector.

India lacks in CBM related services which delayed the scheduled production.

Efficient production of CBM is becoming a real challenge to the E & P companies

due to lack in detailed reservoir characterization. So far, the most investigations

have been limited to measurement of adsorption isotherms under static conditions

and is deficient in providing information of gas pressure-driven and concentration-

driven conditions. More care should be taken on measurement of porosity and

permeability also. To produce more methane from the coal enhanced technology

like CO2 sequestration may be implemented. This process can not only reduce the

emission of this gas to atmosphere, will also help in extra production of methane

gas [2]. Though, presently, CO2 is not an implemented much because of high cost.

But the necessity to reduce greenhouse gas emissions has provided a dual role for

coalbeds - as a source of natural gas and as a repository for CO2.

5

In the present investigation, Singareni coal field has been selected as the study

area. Samples have been collected from various locations & depths. Standard

methods have been followed to characterize the collected coal samples and

evaluation gas reserve.

6

II. GLOBAL AND INDIAN SCENARIO

Global:

The largest CBM resource bases lie in the former Soviet Union, Canada, China,

Australia and the United States. However, much of the world’s CBM recovery

potential remains untapped. In 2006 it was estimated that of global resources

totaling 143 trillion cubic meters, only 1 trillion cubic metres was actually

recovered from reserves. This is due to a lack of incentive in some countries to

fully exploit the resource base, particularly in parts of the former Soviet Union

where conventional natural gas is abundant.

The United States has demonstrated a strong drive to utilize its resource base.

Exploitation in Canada has been somewhat slower than in the US, but is expected

to increase with the development of new exploration and extraction technologies.

The global CBM activities are shown in Fig.1.

The potential for supplementing significant proportions of natural gas supply with

CBM is also growing in China, where demand for natural gas was set to outstrip

domestic production by 2010 [3].

India:

India is potentially rich in CBM. The major coal fields and CBM blocks in Indian

are shown in Fig 2. The Directorate General of Hydrocarbons [4] of India

estimates that deposits in major coal fields (in twelve states of India covering an

area of 35,400 km2) contain approximately 4.6 TCM of CBM [5]. Coal in these

basins ranges from highvolatile to low-volatile bituminous with high ash content

(10 to 40 percent), and its gas content is between 3-16 m3/ton (Singh, 2002)

depending on the rank of the coal, depth of burial, and geotectonic settings of the

basins as estimated by the CMPDI. In the Jharia Coalfield which is considered to

be the most prospective area, the gas content is estimated to be between 7.3 and

23.8 m3 per ton of coal within the depth range of 150m to 1200 m. Analysis

7

indicates every 100-m increase in depth is associated with a 1.3 m3 increase of

methane content [6].

Fig 1. Global CBM activities

In India, commercial CBM production is yet to be started in full pace. Few E&P

companies like ONGC Ltd., GEECL and Essar Oil have started production, but

field development is yet to be completed.

8

Fig. 2. CBM Blocks in India (DGH, India)

9

III. MATERIALS AND METHOD:

A. Sample collection and characterization

Coal samples were collected from Dorli- Bellampalli coal Belt of Singareni

coalfield, Andhrapradesh, India. Samples are collected from various seams of the

bore holes at different locations.

TABLE I. PROXIMATE ANALYSIS RESULT

10

TABLE II. ELEMENTAL ANALYSIS OF THE SAMPLES

11

Caprock of each seam is mainly made of coarse to very coarse grained sandstone,

greyish all over. The depth under study varies from 369m to 541m. The coal

samples were first crushed, ground and sieved through 72-BSS mesh openings.

Proximate analyses of the samples were performed using muffle furnace as per the

standard method. The equilibrium moisture content of the samples was determined

using the standard test method [ASTM D 1424 – 93]. Ash contents of samples

were estimated in accordance with the ASTM D3174-04 and elemental

composition of coal samples were determined using CHNS Analyzer (Elementar

Vario EL III- CHNS analyzer). The results of the proximate and elemental

analyses are shown in Table I and Table II respectively.

12

IV. RESULTS AND DISCUSSIONS

From the results it was observed that the ash content varies from 10.52% to

26.59% except one sample that showed an irregularly high ash content of 45.99%.

Proximate analysis of the investigated coal samples reveal that the moisture

content (M %) varies from 2.46% to 3.82%, whereas volatile matter ranges from

23.30% to 40.26% and fixed carbon (FC) content varies from 26.01% to 53.21%.

From elemental analysis (Table II) it is seen that the fixed carbon percentages

varies from 38% to 71 %. In general it is recognized that the fixed carbon of coal

increases with increase in coal depth which is directly proportional to the coal

maturity and rank [8]. The similar trend is observed in the present study also as

shown in Fig 3 and Table I.

A. Gradation of coal under study:

The value of vitrinite reflectance ( %) gives idea about the coal rank and grade. In

the present study, the vitrinite reflectance (Ro%) is calculated by using the formula

by Rice [9] using the data from approximate analysis. The formula is as follows:

Ro % = -2.712 × log (VM) + 5.092 (4)

The % varies from 0.45% to 0.88% (Table III).

From the proximate analysis and value of vitrinite reflectance (Ro) varies from

0.45 to 0.88%. Hence, the coal samples under study belong to sub-bituminus to

bituminous rank.

13

B. Estimation of Methane Content

Most of the gas in the coal is adsorbed on the internal surface of micropores and

varies directly with pressure and inversely with temperature. The relationship

between the volume of adsorbed gas with pressure and temperature based on

the moisture and ash content of coal samples was estimated by Kim’s empirical

equation [10].

Kim’s correlation:

The estimated methane gas content is shown in Table II. From estimated gas

content data, it is observed that the gas content varies from 5 m3/ tonne to 9 m3/

tonne as against the economic viability of 8 to 15m3/ tonne. The values of

gas content increase with increase with depth as the maturity & rank of the coal

also enhanced (Table II). However, from the result it is seen that the gas

content is at the lower economic limit. This may be due to less maturity of the

coal and less depth.

14

TABLE III. ESTIMATED GAS CONTENT

C. Relationship between Total Gas Content and Non- Coal content (ash +

moisture content):

Since it is generally true that methane is not adsorbed onto non-coal material, ash

and moisture values can be used to make appropriate corrections on the total

measured gas contents. Gas content is seen to increase with depth, and bituminous

coals are associated with the highest gas contents, followed by sub bituminous

coals. Cross plot of Gas Content versus non- coal content (ash + moisture content)

is shown in Fig.4.

15

Moisture and ash content within the coal reduces the adsorption capacity of

methane. Adsorption capacity of methane decreases with increasing ash and

moisture percentage within the coal. As little as 1% moisture may reduce the

adsorption capacity by 25%, and 5% moisture results in a loss of adsorption

capacity of 65% [11].

V. PRODUCTION OF GAS FROM COALBED.

A. Gas Transportation mechanism in reservoir:

Production of gas is controlled by a three step process (i) desorption of gas from

the coal matrix, (ii) diffusion to the cleat system, and (iii)flow through fractures

[12] as shown in Fig 5.. Many coal reservoirs are water saturated, and water

provides the reservoir pressure that holds gas in the adsorbed state.

Flow of coalbed methane involves movement of methane molecules along a

pressure gradient. The diffusion through the matrix pore structure, and steps

include desorption from the micropores, finally fluid flows (Darcy) through the

16

coal fracture (cleat) system. Coal seams have two sets of mode; breaking in tension

joints or fractures that run perpendicular to one another.

The predominant set, face cleats, is continuous, while the butt cleat often

terminates into the face cleats. Cleat systems usually become better developed

with increasing rank, and they are typically consistent with local and regional

stress fields.

The size, spacing, and continuity of the cleat system control the rate of fluid flow

once the methane molecules have diffused through the matrix pore structure. These

properties of the coal seams vary widely during production as the pressure

declines. Coal, being brittle in nature, cannot resist the overburden pressure with

reduction in pore pressure during dewatering; and fractures are developed. In

addition, hydraulic fracturing is done to increase the permeability of coal. Because,

permeability and porosity of coal is extremely low for which production rate is also

low. The basic petrophysical properties of coal responsible for production of

methane, e.g. porosity, permeability vary widely with change in the pore pressure

during dewatering as well as gas production period. Hence, efficient production of

methane from coal bed needs continuous monitoring of variation in porosity,

permeability and compressibility of coal. The unique features of the coal are that

17

coals are extremely friable; i.e., they crumble and break easily. Therefore, it is

nearly impossible to recover a ―whole‖ core. Direct measurement of intrusive

properties like permeability, porosity, compressibility, relative permeability

measurements are very difficult and must rely on indirect measurement.

In India, ONGC Ltd. has implemented multilaterial well technology to increase

the drainage area and enhance the production in the Jharia block. But, brittle

characteristic of coal restricts the production at the expected rate. Moreover, coal

is highly compressible (~as high as 2x10-3 psi-1) [13]. Variation of permeability

and bottom hole properties during production requires accurate well test analysis

using correct model. CBM reservoirs are of dual porosity system, which demands

for special models of well test analysis. So, only static adsorption-desorption study

can not suffice the analysis of coal bed methane production. As these properties

will continuously vary during production, efficient & economic production of

methane from coal bed requires constant monitoring and analysis of the system by

experienced and proficient persons.

B. Enhanced recovery techniques:

The main hurdle associated with the production of CBM is the requirement of

long dewatering of coal bed before production. This difficulty may be resolved to

some extent with implementing the CO2 sequestration technology.

Due to higher adsorption affinity of CO2 to coal surface [7], methane will be

forced to desorb from the coal surface at comparatively high pressure and can

reduce the dewatering time and hence the total project period. Also the problem

associated with variation in coal properties related to pressure depletion may be

alleviated. China, Australia, USA have been started to implement this technology

for enhanced recovery of CBM gases.

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VI. CONCLUSIONS

CBM technology is proceeding with good space to prove itself as a cleaner energy

security to India as well as the World. However, production strategy of methane

from CBM is very much different from conventional gas reservoir. The study

revealed that the coal type, rank, volatile matter and fixed carbon are strongly

influence the adsorption capacity of methane into the coal bed. With increasing

depth maturation of coal increases and generation of methane gas also increases.

Gondwana basin as the most prospective CBM field is being developed now. From

the studies, it is observed that Singareni coal field under Gandowana basin contains

low gas Hence, presently it is not considered for CBM exctraction. However, in

future this field may be considered for methane extraction using advanced

technology and in emergency condition.

Sequestration of CO2 helps in mitigation of global warming, at the same time

helps in recovery of methane gas from coal bed unveiled otherwise. However,

detailed and intensive studies are required for efficient and economic production of

coal bed methane. India with ~4.6 TCM of methane reserves in coal bed can enrich

its per capita energy demand by successful exploitation of CBM.

19

REFERENCES:

[1] U. P. Singh. ―Progress of Coalbed Methane in India‖, North American Coalbed

Methane Forum, 2002.

[2] F. V. Bergen, J. Gale, K. J. Damen, A.F. B. Wildenborg. ―Worldwide selection

of early opportunities for CO2- enhanced oil recovery and CO2-enhanced coal bed

methane production‖, Energy, 2004, 29, 1611-1621.

[3] World Coal Institute (WCI), (2009), http://www.worldcoal.org/coal/coal-seam-

methane/coal-bedmethane/.

[4] DGH : CBM Exploration, Directorate General of Hydrocarbons, Ministry of

Petroleum and Natural Gas, New Delhi, India, March 18, 2008,

http://www.dghindia.org/site/dgh_cbm_blocks_under_psc.aspx.

[5] D.N. Prasad, Personal communication with D.N. Prasad, Ministry of Coal, May

16, 2006.

[6] M2M-India (2005): Methane to Markets Partnership – CMM: India Profile,

submitted to Methane to Markets International by the Government of India, 2005.

www.methanetomarkets.org/events/2005/coal/docs/india_profile.pdf.

[7] G.Q. Tang, K. Jessen, A.R. Kovscek. ―Laboratory and simulation investigation

of enhanced coalbed methane recovery by gas injection‖, SPE, 2005, 95947.

[8] C. Laxminarayana and P. J. Crosdale, ―Role of coal type and rank on methane

sorption characteristics of Bowen basin, Australia coals,‖ Int. J. Coal Geology

1999 40 309–325.

[9] B. E. Law and D. D. Rice, ―Composition and origins of coal bed gas; In:

―Hydrocarbons from coal‖ (eds) AAPG Studies in Geology 1993, 38 159–184

[10] G. A. Kim, ―Estimating methane content of bituminous coal beds from

adsorption data,‖ U.S. Bureau of Mines 1977, RI8245 1–22.

[11] R.D.Lama, J.Bodziony, ―Outburst of Gas, Coal and Rock in Underground

Coal mines‖. Wollongong, 1996. 499 pp.

http://www.worldcoal.org/coal/coal-seam-methane/coal-bedmethane/



http://www.dghindia.org/site/dgh_cbm_blocks_under_psc.aspx


http://www.methanetomarkets.org/events/2005/coal/docs/india_profile.pdf

20

[12] B.Thimons and F.N.Kissell. ―Diffusion of methane through coal‖: Fuel, 1973,

52, 274-280.

[13] R. D. Roadifier. ―Coalbed Methane (CBM) A Different Animal & What’s

Really Important to Production and When?‖ SPE unconventional Reservoir

Conference, 2008, SPE 114169.

About AUTHORS

Dr. Keka Ojha, Associate Professor of the Department of Petroleum Engineering,

Indian School of Mines has more than ten years of research and teaching

experience. Before joining ISM Dhanbad, she has worked as Research Associate in

University of Notre Dame, USA and Lecturer in Heritage Institute of Technology,

Kolkata, India. She is currently running a number of R&D project in various field

of Petroleum Engineering including Coal Bed Methane, green house gas emission.

Dr. Ojha has about fifty publications to her credit in peer reviewed

national/international journals & conferences.

Dr. A. K. Pathak, Head & Professor of the Department of Petroleum Engineering

has been serving the department as faculty since 1984. Research area is surface

activity of oil & its fraction and their effect on fluid flow through porous media.

He is actively involved in development of computer soft wares and expert system

on various areas of drilling system design, Directional drilling and on Horizontal

Well Technology. He is currently working on various field of Petroleum

Engineering including Coalbed Methane, Surface/ interfacial activity of Crude Oil

and its fractions, Horizontal /Slanted Well Technology.

Dr. Ajay Mandal is presently working as Associate Professor in the Department of

Petroleum Engineering, Indian School of Mines, Dhanbad. He is the recipient of

Gold Medal in M.ChE. (J.U.) in 1998 and DAAD Fellowship (Technische

Universidad Braunschweig, Germany) in 2008. Currently Dr. Mandal is carrying

out his research works on gas hydrates, enhanced oil recovery, coal bed methane,

21

multi-phase flow system, microemulsion etc. He has published around 40 research

papers in reputed peer reviewed Journals and presented/participated more than 25

National and International Conferences. He is the reviewer of more than 15

International Journals in the field of chemical and petroleum engineering. He is

currently handling five major projects sponsored by CSIR, UGC, ISM and

Ministry of Coal. Dr. Mandal is also a member in the editorial board of

International Journal of Petroleum Engineering and section Editor of Journal of

Petroleum Engineering & Technology.

Bibhas Karmakar is a Senior Research Fellow in the Department of Petroleum

Engineering, Indian School of Mines, Dhanbad. Mr. Karmakar did his M.Sc. from

Presidency College, Kolkata and Master of Technology in Petroleum Exploration

from Indian School of Mines, Dhanbad, India. His research area is Enhanced

Coalbed Methane Recovery by CO2 Sequestration. Mr. Karmakar is an active

student member of different professional organization including AAPG, SPE.