Physical and Chemical Analysis of Drilling Fluid Properties

Bachelors of Applied Science in Petroleum Engineering

2015

Year 3

Physical and chemical analysis of drilling fluid properties

Course Title: Drilling Engineering

Course Code: DRLG3001

Submitted to: Jasmine Medina

Submitted by:

Andrew Grant

ID#:65188

Lab day: 13th October 2015

Due date: 22nd October 2015

1The University of Trinidad and Tobago, Point Lisas Campus Esperanza Road, Brechin Castle, Couva.

Executive Summary

This laboratory experiment was mainly evaluating the physical and chemical properties of

drilling fluids. Six test were conducted to ascertain and correlate drilling fluid properties to

their performance. As such, identifying the types of contaminants present in water based

drilling fluids were of paramount importance for recommending the relevant treatments that

were applicable for right type of contaminant. Contaminants identified were: calcium

carbonate, oil, sodium chloride and the recommended chemical treatments were soda ash,

caustic soda, gypsum and flocculation. Additionally for removal of other contaminants by

mechanical means, the following treatments were subscribed: Screen, forced settling and

dilution. These treatments are available and are widely used in the hydrocarbon industry in

order to optimize drilling operations while simultaneously reducing operational cost without

adversely affecting the environment.


Objective/Aim(s):

To determine the density and the rheological properties of original sample A and

contaminated mud samples: B, C, D, and O, using mud balance and viscometer

apparatus.

To separate and measure the volumes of water, oil, and solids contained in both

original and contaminated (samples as stated above) via retort analysis.

To ascertain the percentage of sand content of water based drilling fluids (both

original and contaminated samples) by utilizing the sand content funnel, tube, sieve-

mesh @ 75µm and 15% hydrochloric acid solution (HCl).

To determine the filtration behaviour and wall-cake-building characteristics of the

drilling fluid samples given, at low temperature and pressure using an API LPLT filter

press.

To perform chemical analysis of water based drilling samples, for determination of

the following:

o Filtration pH – using pH strips.

o Whole mud alkalinity – titrating with N/50 Sulfuric acid and using

phenolphthalein solution as indicator.

o MBT and, bentonite equivalent – using 0.5 mL of methylene blue

solution.

o Calcium carbonate concentration (CaCO3) –using 2mL of 1.0N

Versenate Hardness Buffer Solution, Calver 11 solution as indicator

and 20 Epm versanate hardness titrating solution.

o Calcium concentration –using Versenate hardness buffer solution,

Versenate hardness indicator solution and 0.02N EDTA Versenate

hardness titrant solution.

o Chloride ion content –using 0.02N (N/50) sulphuric acid, potassium

chromate indicator solution (K2CrO4), and 0.0282N Silver Nitrate

Solution (AgNO3).

Sodium Chloride and potassium chloride content using phenolphthalein indicator

solution, 0.02N Sulphuric acid solution, potassium chromate indicator solution, 0.282N

silver nitrate solution, standard sodium perchlorate solution and a hand crank centrifuge.


Theory:

Background information:The successful completion of an oil well and its cost depends on considerably on the

extent of the properties of the drilling fluid. Many requirements are placed on the drilling

fluid. In the past, main purpose of the drilling fluid was to serve as a vehicle to remove

cutting from the well bore, however in recent times, the applications of drilling fluids has

been more diversified (Gray, Caenn and Darley 1983). Hence in rotary drilling, the

principal functions performed by the drilling fluid includes the following:

Carry cuttings from beneath the bit, transport them up the annulus, and permit their

separation at the surface.

Cool and clean the bit.

Reduce friction between the drilling string and the sides of the hole.

Maintain stability of uncased sections of the borehole.

Prevent the inflow of fluids – oil, gas, or water – from permeable rocks that were

penetrated.

Form a thin and relatively impermeable filter cake which seals pores and other

openings in formations penetrated by the bit.

Assist in the collection and interpretation of information available from drill cuttings,

cores, and electrical logs.

Drilling fluids are categorized in accordance to their base .i.e. water based and oil based

muds. Water based muds are consist of solid particles suspended in water or brine. In

some cases, oil may be emulsified in water, in these cases water is considered as the

continuous phase. Whereas, oil based muds comprise of solid particles suspended in oil.

If water or brine is emulsified in oil then the oil is considered to be the continuous phase.

Another type of drilling fluid is gas. This is where drill cuttings are removed by a high

velocity stream of air or natural gas. Foaming agents are added to remove minor inflows

of water.

In water based muds, the solids consist of clays and organic colloids added to provide

the required viscous and filtration characteristics, heavy minerals (generally barite are

added to increase density when needed) and solids from the formation that become

dispersed in the mud in the course of drilling. The water contains dissolved salts either

from contamination with formation waters or purposely added for any number of reasons.

The following sections are brief introductions of the six diagnostic tests that will be

performed on the drilling fluid samples.


Density and Rheological properties:

The density Drilling fluid must be maintained to provide the required hydrostatic head to

prevent flux of formation fluids, but not so high as to cause loss of circulation or

unfavourably affect the rate of drilling and formation damage. Consequently, one of the

first test to be performed on a drilling rig is mud weight or density.

Figure 1 showing typical diagram of mud balance (Bourgoyne Jr., et al. 1986)

In this experiment, the density and rheological properties of the original and

contaminated samples is being performed. The apparatus used to conduct this test was

the mud balance (shown in figure 1 above). The test consists of essentially of filling the

cup with a mud sample and determining the rider position required for balance. The

balance is calibrated by adding lead shot to a calibration chamber at the end of the

scale. Water usually is used for the calibration fluid. The density of fresh water is 8.33

lbm/gal. The drilling fluid is normally degassed before being placed in the mud balance to

ensure an accurate measurement (Bourgoyne Jr., et al. 1986).

In this section of the experiment, rheological properties of the drilling samples will be

measured using the rotational viscometer. Viscometer, measures viscosity quantitatively,

whereas the marsh funnel measures qualitatively in terms of determining drilling mud

consistency. Mud is sheared at a constant rate between the inner bob and an outer

rotating speed sleeve. Six standard speeds and a variable speed setting are available on

the viscometer. The dimensions of the bob and rotor are chosen so that the dial reading

is equal to the apparent Newtonian viscosity in centipoise at a rotor speed of 300 rpm. At


other rotator speeds, the apparent viscosity is given by μa=

300θN

N , where θN, is the

dial reading in degrees and N is the rotor speed in revolutions per minutes. The

viscometer could also determine rheological parameters that exhibit non-Newtonian fluid

behaviour for example, the flow parameters of Bingham plastic model as shown in figure

2 below.

Figure 2 showing Newtonian and Non-Newtonian curves (King Fahd University of Petroleum

and Minerals, 2003)

Retort Analysis:


Figure 3 above shows the retort distillation apparatus consisting of three principal

components: a heating unit, a condenser and a receiver. The heating unit, is used to

bombard the reservoir rock sample with extreme heat. Rock samples can either be

crushed or small cylindrical core plugs in dimensions... These rock samples, either

consolidated or non-consolidated, are generally weighed before placing them in the

retort. Heat is dispensed at either in stages or directly to temperatures as high as 650 0 C

resulting in the vaporization of oil, and water. This vaporized oil and water, is then

condensed in the condenser and collected in a small receiving graduated cylinder, where

the volumes of oil and water can be measured directly. No further extraction of pore

fluids (K, 2006) are indicated by the presence of a horizontal plateau in the plot of

collected oil and water volume vs. the heating times.

Sand content of water based drilling fluids:

According to Baroid Incorporated (2015), measurement of the sand content of mud

should be made regularly, because excessive sand makes a thicker filter cake, this in

turn causes abrasive wear of pump parts, bit and pipe, may also settle when circulation

is stopped and interfere with pipe movement or settling of casing. Sand content (API)

method is defined as the percentage by volume of solids in the mud that are retained on

a 200-mesh sieve. Below shows a table that defines and characterize sieve sizes for

different types of sand.


Figure 4 below shows the standard API sand sieve that will be used for determination of

sand content in water based drilling fluids (Gray, Caenn and Darley 1983).

API fluid loss:


Fluid loss is usually termed as the loss of a mud filtrate (liquid phase) into a permeable

formation that is being drilled. Because of positive differential pressure (i.e. the pressure

difference between the mud pressure in the wellbore and the formation pore pressure),

the mud filtrate tends to flow into the formation; Consequently, this creates a an

accumulation of mud solids deposited on the wellbore walls, thus forming what is

generally referred to as mud cake (filter cake). Furthermore, initial loss of filtrate to the

formation at time zero is termed as initial spurt loss. After a mud cake is formed, the

presence of any loss of filtrate is categorized as the continuous loss (Azar & Samuel,

2007).

In the hydrocarbon industry, there are two types of filtration involved in drilling an oil well:

static filtration and dynamic filtration. Static filtration occurs when the mud is being not

being circulated and filter cake growth is undisturbed. However, dynamic filtration occurs

when the mud is circulated and growth of the filter cake is limited by the erosive action of

mud stream. The filtration of properties of drilling fluids are generally evaluated and

controlled by the API filter loss test which is a static test. However, because a static test

being performed, this is not a reliable guide to the downhole filtration which is usually

dynamic (Gray, Caenn and Darley 1983).

Chemical Analysis

In order to determine the concentration of various ions present in drilling fluids, a wide

array of chemical analyses will be performed. These tests include determination for OH -,

Cl-, and Ca2+, which are required to complete the API drilling mud report form.

Furthermore, a titration apparatus is used to conduct these type of tests. Titration

involves the reaction of a known volume and concentration. The concentration of ion to

be tested will be determined from knowledge of the chemical taking place (Bourgoyne

Jr., et al. 1986).

Experience has shown that certain chemical analyses are useful in the control of mud

performance, for example, an increase in chloride content may adversely affect the mud

properties unless the mud has been designed to withstand contamination by salt. Those

analyses that have been found to be adaptable to use in the field have been included in

API RB 13 B (Gray, Caenn and Darley 1983).

Salt Analysis- determination of sodium and potassium chloride content.


A sample of mud filtrate (neutralized, if alkaline) is titrated silver nitrate solution, using

potassium chromate as indicator. The results are usually reported in parts per million

chloride ion, although actually measured in terms of mg Cl- ion per 1000cm3 of filtrate. In

order to determine the chloride content of an oil mud, the sample will be diluted with a

mixture of Exosol and isopropyl alcohol (3:1) and diluted with water, neutralized to the

phenolphthalein end point and then titrated the usual way (Gray, Caenn and Darley

1983). However, in this laboratory session only the salinity of water based mud samples

will be examined.

Procedure:

As per lab manual

Results:


SampleDensity (lb/bbl)

Viscometer Speed/RPM 75°F 120°F 75°F 120°F 75°F 120°F 75°F 120°F 75°F 120°F 75°F 120°F600 40 33 61 58 148 135 45 50 43 35 40 33300 25 22 52 51 102 95 40 49 27 22 25 22200 20 18 48 48 82 75 37 49 22 20 20 18100 13 12.5 44 45 54.5 50 31 48 13 13 13 12.5

6 4 5 35 35 18 13 31 42 5 6 4 53 4.6 5 31 26 16 18 31 42 3 8 4.5 5

Pv 15 11 9 7 46 40 5 1 16 13 15 11Yp 10 11 43 44 56 55 35 48 11 9 10 11

10 second gel 3 3.5 5 34 27 11 17 20 74 410 minute gel 4.5 7 35 25 25 30 30 66 6 10

5 min7.5 min10 min15 min20 min30 min

FC Properties

Filtrate pHPmPf

Chlorides, mg/lCalcium, mg/l

MBTBentonite Eq., lb/bbl

CaCO3, lb/bbl

% solids b/f acidization% solids after acidization

% sand

% Oil% Water% Solids

% CST% NaCl

Contaminant

Sand Content

Retort Analysis

Salts

5.26.27.1

0.2004

28.50

8.610.212.4

Soft and Pliable

80.6

35.632.1

9

Orignal9

A7.7

B9.25

Rheological Properties

Chemical Analysis

34.714

C8

D9.2

O9.25

17.419.822.427.730.837

8/32

4.2

10

55.86.67.88.810.6

4.85.56.67.69.2

5.46.27.28.69.611.7

0.8 1

3/32Soft and Pliable '4/32

32.0612.95

1.10.150.30.65

0.6

0.81.5

-

991

1.78020

960.2

4

2/32

3.74.5

28.53.5

100.81.20

0.27

49.90.7

100.50.2

4

107416

0991

8020

960

7416

0982

982

0 2NaCl

0.3Bentonite

019901.5

Pure0

Oil1.5

CaCO3

2321.50

141.42

6193

2276.2

Table 1 above showing results for six experiments performed on drilling fluid samples (A-D).


0 2 4 6 8 1 0 1 2 1 4 1 6 1 8 2 00

5

10

15

20

25

30

35

40

f(x) = 2.0869695760317 x + 0.679211299935657

f(x) = 1.74326822765552 x + 0.454079029029487

f(x) = 1.58280146243316 x + 0.125606921247678

f(x) = 1.27002245409114 x + 0.312899083410306

f(x) = 1.12762362029637 x + 0.178339151665386

Graph 1 showing spurt loss V vs √tSample B Linear (Sample B) Sample CLinear (Sample C) Original Sample Linear (Original Sample)Sample D Linear (Sample D) Sample ALinear (Sample A)

√t

Volu

me

filtr

ate


Calculations:

The following are sample calculations for each experiment conducted.

Using data from original sample for all sample calculations, except where specified.

Density and Rheological Properties

PV (Plastic viscosity, (lbs/100ft2)/300rpm) = θ600-θ300

YP (yield point in lbs/100ft2) = θ300 – PV

PV=θ600−θ300=40−25=15 lbs /100 ft 2 /300rpmYP=θ300−PV=25−15=10lbs /100 ft2

Retort Analysis

Volume Percent (%) Oil = Vo =

100 (Oil volume collected, mL)Sample Volume, mL

Volume Percent (%) water=V w=

100 (Water volume collected, mL )Sample Volume, mL

Volume Percent (%) Solids =Vs=100−(Vo+Vw )

⇒Vo=100(0 )10

=0 %

⇒Vw=100(0 . 99)10

=99 %

⇒Vs=100−(0+99)=1%

Chemical Analysis

Methylene Blue Capacity (MBT) = methylene Blue, mL/Drilling fluid, mL

Bentonite equivalent, lb/bbl = 5 (Methylene Blue, mL)/Drilling Fluid, mL

⇒MBT=8ml2. 0ml

=4

⇒5 (4 )/0 .71=28 lb /bbl

Volume (mL) titrating solution) * (3.5) = lb/bbl calcium carbonate

For sample B, titrating solution = 1.8 mL


1 .8∗3 .5=6 .3lb /bbl

Total hardness for sample B as calcium, mg/I= 400 x (VEDTA/VS)

Where VEDTA = volume of EDTA solution, mg/I

Vs = Volume of sample, mL

mg / I=400∗1 cm3

1cm3 =400

NaCl- Determination

c[Cl] = 10000 x (Vsn/Vf)

Where Vsn = the volume of silver nitrate solution, ml

Vf = the volume of filtrate sample, ml

c[Cl] : 10000 x {12.1/1} = 121000 mg/I

∴NaCl=1. 65∗12100=199 ,650mg /I

Conversion of Mg/I to weight percent and PPM at 68 0 F gives ≈180,000 ppm.

Using the graph of NaCl weight% against NaCl mg/I and 180,000ppm gives 15 wt% of NaCl.

KCl determination

c[KCl], ppb = (7/Vf) x (x-axis value from standard curve, ppb)

c[KCl], ppb = (7/0.65) x 11.6 = 124.92 ppb

c[K+]+ = 1500 x c[KCl], ppb

c[K+]+ = 1500 x 124.92 = 187,384.61

y ml KCl ppt = 0.0393 x (lb/bbl ppt ) + 0.2042

y ml KCl ppt = 0.393 x 11.6 + 0.2042 = 4.763 lb/bbl


Discussion:

Density and Rheological properties:

Density or mud weight, was determined by weighing a precise volume of mud and dividing it

by the volume. The mud balance was the instrument utilized to obtain the density for both

original and contaminated mud samples. To date in the petroleum industry, the mud balance

provides the most convenient way of obtaining a precise volume. The procedure that is

normal used on a drilling rig, is to fill the cup with mud, put on the lid, wipe off the excess

mud from the lid, move the rider along the arm until a balance is achieved and the density

was read at the side of the rider towards the knife edge (Gray, Caenn and Darley 1983).

Density could be expressed in pounds per gallon (lb/gal), pounds per cubic foot (lb/ft3), and

grams per cubic centimetre (g/cm3) or as a gradient exerted per unit depth.

As shown in table one, the density for the original sample was recorded at 9.0 ppg, whereas

samples A to O densities were recorded at: 7.7, 9.25, 8, 9.2 and 9.25 lb/bbl respectively. The

disparity in densities between the original mud sample and the contaminated mud samples

could be attributed to the following:

Contaminated samples may have excess API barite. API barite is a dense, inert

mineral having a specific gravity of approximately 4.2 and this could be added to any

clay / water mixture to increase density (Bourgoyne Jr., et al. 1986).

Furthermore, the contaminated samples could also contain inert solids. These solids

are termed inert, because they do not hydrate with other components of the mud.

Inert solids are generally classified as sand, silt, limestone, feldspar and also API

barite. In this experiment mud samples B, D and O have higher densities than the

original mud sample. It was observed from table one above, that these samples have

relatively more percentage sand content than the original sample. This observation

was supported by the presence of calcium carbonate in samples B, D and O. When

these samples were in the same mixture containing hydrogen chloride, they

effervescence and their sand content after acidification was reduced. This reaction

was not observed in the original mud sample.

When inert solids such as sand are present in drilling fluids, they adversely affect the

functionality of the drilling fluid; such as, they may increase the frictional pressure drop, in

the fluid system, but they do not greatly increase the ability to carry the rock cuttings to the

surface. The filter cake formed from these solids is thick and permeable rather than thin and

relatively impermeable. Consequently, delay in drilling activities arises dud to stuck pipe,


excessive pipe torque and drag, loss of circulation and poor cement bonding to the formation

(Bourgoyne Jr., et al. 1986).

In addition excessive mud density due to inert solids could possibility increase the

hydrostatic pressure on the borehole walls so much so that the hole fails in tension. This

failure is known as induced fracturing. This phenomenon is where mud is lost into the facture

that formed and the level of the annulus falls until equilibrium conditions are obtained.

Another disadvantage of excessive mud densities is their adverse influence on rate of

penetration. This occurrence have been proven by laboratory experiments and field

experience that in the event of mud overbalance especially drilling in very low permeability

rocks, the rate of penetration is significantly reduced. Also, a high overbalance pressure

increases the probable risk of sticking the drill pipe. Finally, these aforementioned problems

that could arise from the presence of inert solids in drilling fluids causes unnecessary drilling

costs and overruns. To date, excess concentration of inert solids in drilling muds can be

reduced to a desirable levels by: screening, forced settling, chemical flocculation and

dilution.

Rheological properties

The rotational viscometer was used to measure the rheological characteristics of the mud

samples prepared. The mud was sheared at a constant rate between an inner bob and an

outer rotating sleeve. The viscometer, was also used to determine rheological parameters

that described Non-Newtonian fluid behaviour. Two flow parameters that were required to

characterize the mud samples that follow the Bingham plastic model were plastic viscosity

and yield point. The plastic viscosity, cP, in centipoise was computed using: cP = θ600-θ300

where θ600 was the dial reading with the viscometer operating at 600 rpm and θ300 was equal

to the dial reading with the viscometer operating at 300 rpm (Bourgoyne Jr., et al. 1986). The

shear stress divided by the shear rate (at any given rate of shear) is known as the effective

or apparent viscosity. Effective viscosity decreases with the increase of shear rate, and was

therefore a valid parameter for hydraulic calculations only at the shear rate at which it was

measured.

Moreover, the decrease in effective viscosity with increase in shear rate is known as shear

thinning, and normally this is a desirable property, because of the effective viscosity would

be relatively low at the high shear rates prevailing in the drill pipe, thereby reducing pumping

pressures, and relatively high at low share rates prevailing the annulus, thereby increasing

cutting carrying capacity.


The fact that the consistency curves (illustrated in graph 1) of clay muds intercept at the

stress axis (i.e. y-axis), at a greater value that zero was indicative of gel structure

development.

Clay particles in drilling fluids are highly anisodimensional and can build a structure at very

low solid concentrations, because of interaction between attractive and repulsive forces. At

low shear rates the behaviour of clay particles was influenced by these forces and as a

result, the particles viscosity were relatively high, but as shear rate increases, the particles

gradually align themselves in the direction of flow and the viscosity then becomes largely

dependent on the concentration of all solids present in the mud. This phenomena was

observed for all drilling sample fluids; because of these occurrences, the degree of deviation

from linearity in the Bingham plastic consistency curves (as shown in graph one above) of

drilling muds differs from mud to mud in the rotary viscometer and this was depended on

particle size and shape, and concentration of bentonite (Gray, Caenn and Darley 1983).

This phenomenon directly affected the filter cake properties developed by the samples in the

lab as seen in table1. This type of behaviour was observed with samples with low solid muds

containing a high proportion of clay particles and high solid muds such as barite.

Unfortunately, it is highly challenging to determine the linearity of the consistency curves,

other than by measurement in a multispeed rotary viscometer. In practice the most widely

use of the PV and YP quantities is for the evaluation of drilling mud performance and is used

as a guide for drilling mud treatments. Thus PV is sensitive to the concentration of solids and

this is indicative of dilution requirements; YP is sensitive to the electrochemical environment,

and hence indicates the need for chemical treatment (Gray, Caenn and Darley 1983).

Usually, the consistency curve of a Bingham plastic in a rotary viscometer should be linear at

rotor speeds above that required to keep all the fluid in the annulus in laminar flow. In reality

however, drilling fluids are not ideal Bingham plastics and as such they deviate from linearity

at low shear rates.

A third non-Newtonian rheological parameter called gel strength, in units of lbf/100 sq ft2 was

obtained by noting the maximum deflection when the rotational viscometer was turned on at

a low rotator speed of 3 rpm. Gel strength was termed as observing the maximum deflection

before the gel breaks. Gel strength for all the samples were measured after allowing the mud

to stand quiescent for 10 seconds, the maximum dial deflection obtained when the

viscometer was turned on was the initial gel strength. The gel strength of fresh water clay

muds, increases with time after agitation has ceased, a phenomenon called thixotropy.

Furthermore, after standing quiescent the mud was subjected to a constant rate of shear, its

viscosity decreases with time as its gel structure was broken up, until an equilibrium viscosity


was reached. Thus the effective viscosity of a thixotropic mud was time dependent as well

as shear-dependent.

Retort Analysis

The mud samples were placed in a steel container and were heated (approximately 516 +/-

22 0 C) until the liquid was vaporized. The vapours passed through the condenser and were

collected in a graduated cylinder. The volumes of the respected samples were measured

and then converted to a percentage based on the volume of whole mud in the retort cup.

Volume percent of solids (Vs) = 100- (V0 + Vw)............................................... 1

From equation one above, the solids both suspended and dissolved, were equal to 100%

minus the liquid percent. This procedure also gave the percent of oil in the mud sample.

Consequently, it was found that sample C was the only sample contaminated with oil. The

mud samples were then subjected to further tests to elucidate the nature of contaminated oil

content.

The retort procedure was a very rapid and simple technique, however, the retort distillation

method has notable disadvantages. Firstly, the rock samples were completely destroyed and

secondly, high temperatures were required. However, the application of extreme heat was

unavoidable because, oil in the reservoir rock samples contained very high molecular weight

or high boiling point substituents. Consequently, the application of very high temperatures

was essential to ensure that all the oil was completely extracted from the rock samples (K,

2006). Using elevated temperatures of this magnitude resulted in the following errors:

At such high temperatures, the water of crystallization within the rock was driven off,

causing the water recovery values to be greater than the pore water (K, 2006).

High temperatures also may fracture and the coke in the oil causing the collected oil volume

not to correspond to the volume of oil initially in the rock sample. The cracking and coking of

the hydrocarbon molecules, may likely to reduce the liquid volume and also in some cases

may also coat the internal walls of the rock sample itself. The water of crystallization and the

cracking and coking of hydrocarbons was quantified in Emdahl based on the core analysis of

Wilcox sands in which fluid saturations were measured by the retort distillation method,

indicating an error of around 33% in the water saturation with the volume of oil recovered

and the volume of oil in the sample varied due to V oil actually in the sample = 1.2198 (V0.859

oil collected in receiver)..........................2.18

The University of Trinidad and Tobago, Point Lisas Campus Esperanza Road, Brechin Castle, Couva.

Equation 2 indicates that the volume of oil recovered or collected in the receiver was

decreased due to cracking and coking of the hydrocarbon molecules (K, 2006).

In addition to these errors, other practical errors could also occur in the retort distillation

method, such as formation of oil-water emulsions that do not allow accurate volume

measurements and the absence of clear demarcation between the plateaus of pore space

water and the water of crystallization which could introduce uncertain measurement of water

volume.

Sand content and water based drilling fluids

The sand content test was a measure of the amount of particles larger than 200 mesh

present in mud samples. Effectively this test defines the size and not the composition of the

particles (Gray, Caenn and Darley 1983). The mud samples were first subject to dilution by

adding mud and water to the respective marks inscribed in the glass tube. The mixture was

then shaken and poured through the screen in the upper of cylinder, and then washed with

tap water until clean. The substance that remain on the screen was then backwashed

through the funnel into the glass tube and allowed to settle and finally the gross volume was

read from the gradulations on the bottom of the tube.

As mentioned earlier, the presence of excessive sands in drilling fluids have direct

catastrophic problems on drilling operations of a well and as such there were four methods

that could be employed to prevent a high concentration of inert solids. These were:

Screening. This method is usually applied first in processing the annular mud stream.

This allows the removal of most of the solids before their size has been reduced to

the size of the API barite particles. API specifications for commercial barium sulphate

require that 97% of the particles pass through a 200-mesh screen. Particles less than

approximately 74µm in diameter will normally pass through the 200-mesh screen.

Forced Settling. When natural settling failed to screen out inert particles, devices

such as hydroclones and centrifuges are utilized to increase the gravitational force

acting on the particles. At present, both devices are used as forced settling

instruments with unweighted muds (Bourgoyne Jr., et al. 1986).

Chemical flocculation. The removal of fine active clay particles could also be used by

adding chemicals that cause the clay particles to flocculate or agglomerate into larger

units. Once agglomeration of fine clay particles have been achieved, separation can

be facilitated more easily.

Dilution. This method requires discarding a portion of additives used in previous mud

treatments.


API fluid loss

The API fluid loss test was used to determine the static filtration characteristics of the mud

and the need for treatment with fluid loss additives (only used for water based muds). The

filter press was used to determine, the filtration rate through a standard filter paper and the

rate at which the mud-cake thickness increases on the standard filter paper under standard

test conditions. This test was indicative of the rate at which permeable formations were

sealed by the deposition of a mud-cake after being penetrated by the bit.

If unit volume of a stable suspension of solids was filtered against a permeable substrate,

and x-volumes of filtrate were expressed, then 1-x volumes of cake (solids plus liquid) would

be deposited on the substrate. Therefore if Qc be the volume of the cake and Qw the volume

of the filtrate:

QcQw

= 1−xx

and the cake thickness (h) per unit area of cake in unit time would be

h=1−xx

∗Qw

However, Darcy’s law stated that:

dqdt

= KPμh

Therefore

dqdt

= KPμQw

∗ x1−x

Integrating

Qw2=2 KPμ

∗ x1−x

∗t

Then substituting:


Qw2=2 KPμ

∗QwQc

∗t If the area of the filter cake was A, then

Qw2=2 KPA2

μ∗QwQc

∗t This is the fundamental equation governing filtration under static

environment.

According to Bourgoyne et al (1986) the filtrate volume should be proportional to the square

root of the time period used. Thus, the filtrate collected after 7.5 minutes should

approximately be half the filtrate collected in 30 minutes. This phenomenon was observed

for all drilling fluid mud samples. . In order to determine if a significant spurt loss of volume of

filtrate was observed for each of the mud samples the volume of filtrate collected vs square

root of time (√t) was plotted on a graph (see graph 1 above). The spurt loss was determined

by extrapolation and the following equation was utilized: V30 = 2(V7.5-Vsp) + Vsp . Spurt loss of

volume of filtrate Vsp was often observed before the porosity and permeability of the filter

cake stabilizes (Bourgoyne Jr, Chenevert, Millheim, & Young Jr, 1984). As of consequence,

the API cake thickness differ for each mud sample.

Cake permeability: The higher the cake permeability the higher the fluid loss (Azar &

Samuel, 2007). That is, the more interconnected pore space a mud has, the higher its

effective porosity, as of consequence the higher its fluid loss. It was inferred from

observation that both original sample and sample B were more permeable and thus a higher

fluid loss relatively to the other mud samples.

Chemical Analysis

pH paper strip method

The pH, or hydrogen ion concentration, was a measure of the relative acidity or alkalinity.

The pH values ranges from 0 to 14, with 0-6 being acid, 7 being neutral and 8-14 being

alkaline. For the purpose of this experiment, pH strips were used. These strips change

colour in accordance with the acidity or alkalinity of the filtrate or mud. The pH determined

for the original sample and contaminated samples A to D were: 8, 10,10,9, and 10

respectively. The pH of mud plays a major role in controlling the solubility of calcium. At high

pH values –as shown above-, calcium solubility was very limited; this makes high pH mud

suitable for use in the drilling of carbonate formations, which normally were susceptible to

erosion and dissolution by freshwater mud. The pH value was also an important indicator for

the control of corrosion. According to Azar and Samuel (1984), a minimum of 9.5 should


always be maintained to prevent oxygen corrosion of casting, drill pipe, etc. A high pH tends

to disperse the active clays in the mud.

Whole mud alkalinity (Pm)

Alkalinity refers to the ability of a solution or mixture to react with an acid. The

phenolphthalein alkalinity refers to the amount of acid required to reduce the pH to 8.3, the

phenolphthalein end point. The phenolphthalein alkalinity of the mud and mud filtrate is

called the Pm and Pf, respectively. The Pf test includes the effect of only dissolved bases and

salts while the Pm test included the effect of both dissolved and suspended bases and salts.

The methyl orange alkalinity refers to the amount of acid required to reduce the pH to 4.3,

the methyl orange endpoint. The methyl orange alkalinity of the mud and mud filtrate is

called the Mm and Mf, respectively. The API diagnostic test include the determination of Pm,

Pf and Mf. The Pf and Mf test were designed to establish the concentration of hydroxyl,

bicarbonate, and carbonate ions in the aqueous phase of the mud. At a pH of 8.3, the

conversion of hydroxides to water and carbonates to bicarbonates was essentially complete

(Bourgoyne Jr, Chenevert, Millheim, & Young Jr, 1984). The bicarbonates originally present

in solution do not enter the reactions. Thus, at a pH of 8.3,

OH- + H+ HOH, and CO32- + H+ HCO-3

-.

As the pH was further reduced to 4.3, the acid then reacts with the bicarbonate ions to form

carbon dioxide and water:

HCO3- + H + CO2 + HOH.

However, one disadvantage of this type of test is that in many mud filtrates, other ions and

organic acids are normally present that can adversely affect the Mf test.

The Pf and Pm test results indicate the reserve alkalinity of the suspended solids. As the

[OH-] solution was reduced, the lime and limestone suspended in the mud would go into

solution and tend to stabilize the pH. This reserve alkalinity generally was expressed as an

equivalent lime concentration. Converting the Ca(OH)2 concentration from 0.02N to field

units of lbm/bbl yields

0.02 gew/1L x 37.05/g/L = 0.26 lbm/bbl. Thus, free lime was by 0.26 (Pm –fw * Pf), where

fw was the volume fraction of water in mud which was reported to be 0.0098.

MBT and Bentonite equivalent


This test gives an estimate of the cation exchange capacity of mud solids as well as to

indicate the amount of active clays in the mud system. Also this test could be used to

determine colloidal characteristics of clay minerals. A standardized solution of methylene

blue dye was added to 1 ml of mud that has been treated with hydrogen peroxide and

sulfuric acid and was then gently boiled to decompose the polymers and organics (which

have a very high exchange capacity and would otherwise interfere with the test). The

methylene blue was added in 0.5 ml increments until the mud solids no longer absorb the

dye. This endpoint was determined by putting a drop of the solution on a standard Whatman

filter paper. When the dye was in excess, a halo of free dye formed around the blue dot. The

halo that formed was turquoise blue in colour and was very distinct form the blue colour of

the dye. This was reported as equivalent lbs/bbl bentonite.

Calcium Carbonate Determination

After retort and sand analysis were performed on both original and contaminated samples,

determination of calcium carbonate content of the water based drilling samples were then

carried out. In order to determine the calcium content of both samples, the total hardness of

the samples were estimated using the versanate method. The hardness of water or drilling

fluid was due to mainly the presence of calcium and magnesium ions. When EDTA was

added to water, it combined with calcium ions and the endpoint was determined in the

presence of calver 11 indicator. When all the calcium ions was complexed with the EDTA

solution, it gave a colour change at a pH of 12-13. The colour change observed in the

solution was from a wine colour to blue black. It was observed that sample D showed

presence of calcium carbonate contaminant.

In the petroleum industry, the practice of chemical removal of contaminants are utilized. The

addition of chemical contaminants to the drilling fluid, either at the surface or through the

wellbore, produces an imbalance in the chemical equilibrium of the fluid, which can cause

serious rheological or drilling problems to develop. For example, when calcium enters the

mud, sodium montmorillonite will convert to calcium montmorillonite, which first produces

flocculation and eventually aggregation of the montmorillonite. This is often desirable to

remove the calcium by chemical treatment. In most cases, calcium is removed from the mud

system by adding soda ash (Na2C03) which forms in soluble calcium carbonate:

Ca2+ + 2OH- + Na2O3 ⇒CaCO3 ↓+ 2Na+ + 2OH-

Furthermore, if cement or lime get into the mud, the pH usually increases to unacceptable

levels because of the hydroxyl ions as well as calcium have been added. In these


circumstances, either sodium acid pyrophosphate SAPP-Na2H2P2O7 or sodium bicarbonate

is usually added. When SAPP is added the following occurs:

Ca2+ + 4OH- + Na2H2P2O7 →Ca2P2O7 ↓+ 2Na+ +2OH- + 2H2O. In this reaction, calcium

was removed and the four hydroxyl ions on the left side of the equation are reduced to two

hydroxyl ions on the right side (Bourgoyne Jr, et al. 1984).

Calcium test/Water Hardness

The mud hardness indicates the amount of calcium suspended in the mud as well as the

calcium in solution. This test usually is made on Gypsum-treated muds to indicate the

amount of excess CaSO4 present in suspension. A small contaminated sample of mud was

first diluted to 50 times its original volume with deionized water so that any undissolved

calcium or magnesium compounds can go into solution. Since the mud samples were diluted

50 times their original volume, a 50 cm3 sample was titrated to determine the calcium and

magnesium present in 1 cm3 of mud. Water containing large amounts of Ca 2+ and Mg 2+

ions is known as hard water. These contaminants were often present in the water available

for use in the drilling fluid. In addition, Ca 2+ can enter the mud when anhydrite (CaSO4) or

Gypsum (CaSO4.2H2O) formations are drilled. Cement also contains calcium and can

contaminate the mud. The total Ca 2+ and Mg 2+ concentration was determined by titrating

with a standard (0.02 N) Versenate (EDTA) solution. The standard Versenate solution

contains sodium Versenate, an organic compound capable of forming a chelate with Ca 2+

and Mg 2+ . The chelate ring structure very stable and essentially removes the Ca2+ and Mg2+

from solution. Disodium ethylenediaminetetraacetic acid (EDTA) plus calcium yields the

EDTA chelate ring: See chemical reaction below (Bourgoyne Jr., Chenevert, Millheim, &

Young Jr., 1984).


Magnesium ion forms a wine red complex with the dye Eriochrome Black T. Since the

solution containing both Ca 2+ and Mg 2+ was titrated in the presence of this dye, the

Versenate first forms a calcium complex. After the [Ca2+] has been reduce to a very low

level, the Versenate then forms a complex with the magnesium ions. The depletion of the

available Mg2+ ions from the dye Eriochrome Black T causes the colour of the solution to

change from wine-red to blue.

These unwanted ions could be removed by chemical treatment. Magnesium could be

removed by the addition sodium hydroxide as seen in the chemical reaction below:

Mg 2+ + 2 NaOH →Mg(OH)2+ 2Na +

Chloride Ion content

Salt can enter and contaminate the mud system when salt formations were and when saline

formation water enters the well bore. The chloride concentration was determined by titration

with silver nitrate solution. This caused the chloride to be removed from the solution as AgCl,

a white precipitate:

Ag + + Cl- AgCl

The endpoint was detected using a potassium chromate indicator. The excess Ag+ present

after all Cl- has been removed from the solution reacts with the chromate to form Ag2CrO4,

and orange-red precipitate:

2 Ag+ + CrO4 Ag2CrO4

Since AgCl was less soluble than Ag2CrO4 , the latter cannot form permanently in the

mixture until the precipitation of AgCl has reduced the [Cl-] to a very small value. For

titration, .02 N AgNO3 concentration was used (Bourgoyne Jr., Chenevert, Millheim, &

Young Jr., 1984)

Salt analysis

7ml of filtrate was measured and 3ml of standard sodium perchlorate solution was added to

this. The resultant mixture was then centrifuged at 1800 rpm for one minute and the

precipitate volume were recorded which was 0.65 and this was extrapolated on the

calibration curve to obtain 11 lb/bbl of KCl.

The maximum density of a solids-free fluid depends on the type of salt used. Each salt has a

maximum concentration before it reaches saturation. The table below indicates the

maximum densities of various brines. Thermal expansion of the water affects the density of

clear brine. At elevated temperatures the density decreases. Densities were reported at a 25

The University of Trinidad and Tobago, Point Lisas Campus Esperanza Road, Brechin Castle, Couva.

specific temperature such as 70 0F. Combinations of salts can be used to economically

achieve densities from 8.34 to 19.2 ppg (Geo Drilling Fluids Inc, 2014).

Questions

1. Both original sample and sample B had relatively the same mud cake thickness i.e.

‘4/32 and they were both thin soft and pliable. However, sample A’s mud thickness

was recorded to be 8/32 which was twice the mud thickness of the original mud

sample. This could be attributed to contaminants such as NaCl and hardness of

water. Hardness of water means that there were calcium and magnesium ions present

in the mud system thereby reducing sodium montmorillonite to expand and hydrate in

water. Furthermore, high concentration of salts in water could greatly affect the ability

of some clays to hydrate in water.

2. Percent solids in original sample was found to be 1%; in contrast to the contaminated

samples B and C contained 4% bentonite and 16% oil.

3. Sample A has sand and Sample D has carbonates.

API Fluid loss Questions

1. The original sample has more concentration of bentonite which acts as a

viscosifier and readily hydrates in water thus increasing viscosity of the mud and

decreasing fluid loss.

2. Removal of contaminants and adding other types of high yield clays such as

smectite or attapulgite as well as CMC’s and other polymers.

3. Some factors are: Filtrate viscosity, cake permeability, pressure differential.

4. See graph1. Spurt loss is calculated by the following:

a. The spurt loss of the cell can be obtained by extrapolation to zero time and

finding the gradient.

For the original sample:

Time Filtrate Volume

1 4.472 cm3

7.5 10

4 . 472−(10−4 . 472√7 .5−√1 )∗√1=1 . 29cm3


5.Qw2= 2 KPA2

μ∗QwQc

∗t

Vf=√2kΔp( fscfsm−1)∗A √ √t

√μ This equation indicates that the filtrate volume is

proportional to the square root of the time period used. Thus, the filtrate collected

after 7.5 minutes should be half the filtrate volume in collected after 30 minutes. It

was concluded that filtration rate increases with temperature because the viscosity

of the filtrate is reduced.

Determination of KCl concentration questions

1. Sample A had NaCl.

Conclusion:

Drilling fluid densities for water based Lignosulfonate mud was obtained using a non-

pressured mud balance. One of the product formulation was Bentonite, which was added for

mud viscosity, gel strength and even fluid loss control. Within an industry setting, the

presence of bentonite is beneficial for cuttings-carrying-capacity and filter cake

characteristics. Rheological properties were investigated using a rotating viscometer (which

is a type of diagnostic test for mud properties and thus performance). It was determined that

the mud samples were non-Newtonian in character. Meaning that the apparent viscosity for

the mud samples did not exhibit a direct proportionality between shear stress and shear rate.



Physical and Chemical Analysis of Drilling Fluid Properties

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