BORE HOLE PROBLEMS

CONTAMINANT:

Any undesirable component that causes a detrimental affect to the drilling fluid.

CONTAMINANT

EXAMPLE

Drill solids

Active solids - clays

Inactive solids - silt, sand limestone,

chert, etc.

EVAPORITE SALTS

Sodium chloride, NaCl

Potassium chloride, KCl

Calcium chloride, CaCl2

Magnesium chloride, MgCl2

Anhydrite, CaSO4

WATER FLOWS

Mixed salts at various concentrations.

ACID GASES

Carbon dioxide, CO2

Hydrogen sulfide, H2S.

HYDROCARBONS

Light or heavy oils

Lignite

Coal

TEMPERATURE

Degradation of mud products.

CEMENT

Result of cementing operation.

1. WELL BORE INSTABILITY: A. Shale problems (chemical physical). 1. Indications of problem shales.

1. Sloughing shale. 2. Hole enlargement. 3. Bridges and fill on trips. 4. Stuck pipe and fishing difficulty. 5. Hole-cleaning problems. 6. High fluid maintenance cost. 7. Solids-control problems.

2. Shale hydration (surface adsorption and osmotic adsorption) will result in two distinctly different problems.

a. Swelling Expansion of clays due to intake of water. Indicators Bit balling, mud rings or gumbo attacks, hole washouts, elliptical Wellbore, fine solids build up.

b. Dispersion the disintegration of shale of shale due to water contact. Indicators Sloughing shale, bridges and fill on trips, hole cleaning Problems.

3. Stabilizing shale through inhibition. Table 1 lists the chemical and physical process used in stabilizing shale sections and typical

fluids, which employ these stabilization mechanisms.

B. Mechanically induced bore hole problems and solutions Many bore hole problems encountered while drilling are the results of improper drilling

practices. Table 2 outlines typical bore hole problems, which are mechanically induced, and

recommended solutions.

C. Unconsolidated formations( sands, gravels, etc.) 1. Indications of unconsolidated formations:

1. Rough drilling. 2. Hole fills, torque and drag on connections and trips. 3. Frequent packing off and bridges at specific depths. 4. Large amounts of caving and/or sloughing shales after trips. 5. Re-drilling of footage. 6. Mud loss.

2. Remedial procedures 1. Increase low-shear viscosities to improve hole cleaning. 2. Increase mud weight, if possible. 3. Assure laminar flow to avoid mechanical erosion. 4. Combat loss of circulation (LCM) with viscous pills containing various sizes of LCM

(see loss of circulation section).

5. Utilize cement squeeze. D. Evaporite deposits (Stringers and massive salt sections)

1. Associated problems. 1. Excessive washouts causing reduce hole cleaning and/or under reaming (caving in) of

the formation.

2. Dissolved evaporates (salts) contaminate mud system. 3. Directional problems (unwanted sidetracking).

2. Indicators 1. Salt in cuttings or increased chlorides without increased volume (no flow water). 2. Flocculation of fresh water mud. 3. Increased plastic viscosity. 4. Increase in total hardness (anhydrite).

3. Remedial procedure 1. Change to CARBO-DRILL or oil mud with balanced water phase.

Problem

Cause Indicators Solution

Mechanical

erosion Turbulent

flow rates.

Drill string geometry.

Inadequate rheological

properties.

Mixed sizes and shapes of cuttings.

Excessive lag.

Hole enlargement.

Alter rheological properties or reduce

pump output to

ensure laminar or

transitional flow.

Reduce drill string diameter.

Under

balanced

hydrostatic

pressure

Inadequate mud weight.

Geopressured formations

Gas cut mud

Excessive splintered or

concave cuttings.

Hole fill after trips

Raise mud weight to balance formation

pressure.

Pipe whip Excessive rotary speeds

Drill string not in

tension.

Cuttings small mixed shapes of

different types.

Slow rotary speed.

Ensure drill string is in tension.

Swab or

surge

pressures

Excessive pipe running

or pulling

speeds.

High gel strengths.

Improper drill string

tension.

Improper drill string design.

Loss of circulation.

Gas, oil, or water intrusions on trips.

Large quantities of fill and debris

after trips.

Improper fluid displacement.

Reduce pipe running or pulling speeds.

Condition mud to reduce gel strengths.

WATER BASE MUD (WBM) TREND ANALYSIS

TREND Changes in mud properties are an indication that something abnormal is taking

place.

MUD

PROPERTY

TREND

CHANGE

POSSIBLE CAUSE

MUD WEIGHT

INCREASE Drill solids increase, heavy spot from barite sag. Over

treatment during weight-up.

DECREAS

E

Formation fluid influx, light spot from barite sag. Excessive

water additions.

FUNNEL

VISCOSITY

INCREASE Reactive shale drilled, drill solids increase, low water content,

calcium contamination from cement, anhydrite formation

drilled.

DECREAS

E

Formation water influx, excessive water content.

PLASTIC

VISCOSITY

INCREASE Unconsolidated sand drilled, drill solids increase, low water

content.

DECREAS

E

Formation water influx, excessive water additions, and solids

content decrease.

YIELD

POINT

INCREASE Reactive shale drilled, anhydrite formation drilled, low water

content, calcium contamination from cement.

DECREAS

E

Formation water influx, excessive water additions, decrease in

low gravity solids, additions of chemical thinners.

GEL

STRENGTH

INCREASE Reactive shale drilled, low water content, calcium

contamination from cement, or anhydrite formation drilled.

DECREAS

E

Formation water influx, excessive water additions, additions of

chemical thinners.

API / HPHT

FLUID LOSS

INCREASE

Low gravity solids increase, flocculation from cement,

chloride, calcium contamination, low gel content.

DECREAS

E

Mud treatment-taking affect.

pH

INCREASE Additions of pH control additives, calcium contamination.

DECREAS

E

Additions of mud products, anhydrite formation drilled.

CHLORIDE

INCREASE Salt formation is drilled, pressure transition shale is drilled,

formation water influx.

DECREAS

E

Water additions

TOTAL

HARDNESS

INCREASE Salt or calcium formation is drilled, formation water influx.

DECREAS

E

Addition of fresh water, chemical addition.

CATION

EXCHANGE

CAPACITY

INCREASE Reactive shale is drilled, addition of bentonite.

DECREAS

E

Water additions, solids removal equipment.

(CEC)

OIL / SYNTHETIC BASE MUD ( OBM / SBM ) TREND ANALYSIS

TREND Changes in mud properties are an indication that something abnormal is taking

place.

MUD

PROPERTY

TREND

CHANGE

POSSIBLE CAUSE

MUD WEIGHT

INCREASE Drill solids increase, Heavy spot from barite sag. Over

treatment during weight-up.

DECREAS

E

Formation water influx, Excessive base oil additions, Light

spot from barite sag

PLASTIC

VISCOSITY

INCREASE Addition of water, calcium carbonate, primary emulsifier, low

gravity solids increase.

DECREAS

E

Addition of base oil, Decrease in low gravity solids.

YIELD

POINT

INCREASE Increase in organophilic clay, Addition of emulsified water or

synthetic polymer.

DECREAS

E

Addition of base oil or degellant. Decrease of organophilic

clay

GEL

STRENGTH

INCREASE Addition of organophilic gel, Addition of water.

DECREAS

E

Large base oil additions, Increase vin mud temperature.

OIL / WATER

RATIO

CHANGE Large addition of water or water influx. Large addition of base

oil. High bottom hole temperature.

ELECTRIC

STABILITY

( ES )

INCREASE Increase in emulsifier concentration. Addition wetting agent or

base oil.

DECREAS

E

Decrease in emulsifier concentration. Newly prepared OBM

has low ES but increases with lime.

WATER

PHASE

SALINITY

INCREASE Water % of O/W ratio decreasing. Addition of calcium

chloride

DECREAS

E

Water % of O/W ratio increasing from water addition or

formation water influx

HPHT

FLUID LOSS

INCREASE Addition of base oil. Decrease in emulsifier. Water present in

filtrate.

DECREAS

E

Increase in primary emulsifier concentration.

EXCESS LIME

INCREASE Addition of lime. Drilling calcium formation ( anhydrite )

DECREAS

E

CO2 or H2S kick. Addition of base oil or water.

PROBLEM

INDICATION

TREATMENT

FOAMING

Foam on surface of mud pits.

Reduced mud weight.

Reduced pump pressure or

hammering of pumps.

Sprinkle pits with fine spray of water or

diesel. Add DEFOAM-X or other surface-

active agents to mud. In salt or low solids

mud, M-I gel is helpful.

CEMENT

CONTAMINATI

ON

High viscosity, high gel

strengths, increase in pH, fluid

loss and filtrate calcium.

Pretreat if possible, or for low concentrations,

remove chemically with SAPP or sodium

bicarbonate. When large concentrations are

encountered, convert to a system that will

tolerate cement.

GYPSUM OR

ANHYDRITE

CONTAMINATI

ON

High viscosity, high flash gels

and increased fluid loss and

filtrate calcium.

Pretreat for small quantities or remove

chemically with soda ash. For drilling

massive anhydrite, covert to a system that

will tolerate anhydrite (gyp/lime).

SALT

CONTAMINATI

ON

High viscosity, high gels,

increase in fluid loss and salt

content. Grainy appearance to

mud.

Adjust mud properties to tolerate salt by

using chemical treatment fluid loss control

agents, or convert to saturated salt system. If

only stringers are encountered, dilution will

reduce salt content.

HIGH

TEMPERATURE

GELATION

Difficult to break circulation.

Inability to run tools to

bottom. High viscosity and gel

strengths of mud off bottom.

Decreased alkalinity and

increased fluid loss.

Reduce solids concentration by mechanical

means and by water dilution. Treat mud with

SPERSENE, XP-20, or MELANEX-T. Treat

calcium to low levels. Raise pH to 10-10.5.

Limit M-I GEL additions to the minimum

needed for fluid loss control.

BIT BALLING

Little or no progress in

footage. Balled up bit and drill

string. Swabbing on trips. Bits

usually come out in good

condition, showing little wear

but heavily packed with

cuttings.

Add oil, SALINEX, D-D or DMS surfacants.

Maintain low viscosity and gel strengths to

keep hole clear. Utilize available horsepower

for most efficient hydraulics. Increase

circulation rate.

LOCKED CONES

Cones locked or bearing loose

with teeth structure still on

cones.

Reduce drilled solids by water dilution and/or

mechanical separators. Add oil E.P. LUBE to

improve life.

ABRASION

Premature bit failure and

excessive wear of swabs,

liners and valve seats.

Lower sand content by dilution and/or

chemical treatment. Use a desander to hold

sand content to a minimum.

HIGH FLUID

LOSS

Filter cake spongy, soft and

too thick.

If you feel that enough fluid-loss additives are

in the system, add M-I GEL to system. (Run

methylene blue test).

SALT WATER

FLOW

Increase in pit volume. Mud

continues to flow when pump

is shut down. Change in

chloride content. Increased

total hardness. Increased flow

line temperature.

Shut in well. Follow procedures for killing

the well. Adjust flow properties as needed.

Raise mud weight to control flow.

GAS KICK

Increase in pit volume. Mud

continues to flow when pump

is shut down. Gas cut mud may occur prior to this.

Shut in well. Follow procedures for killing

the well. Raise mud weight as needed to kill

the well.

PROBLEM

INDICATION

TREATMENT

MUD LOSSES

Decrease in pit volume.

Complete loss of returns.

Lower mud weight and equivalent circulating

density if possible. Add lost circulation

material, or set Diaseal M or similar soft plug,

possible a cement squeeze. Run pumps

slowly. Watch all causes for lost returns.

UNSTABLE

MUD

Barite settles out. Increase viscosity by adding a viscosifier.

Use M-I GEL or XC Polymer where

applicable

HIGH

VISCOSITY

High funnel viscosity High plastic viscosity Normal yield point Normal gels High solid content

Run mechanical solids removal equipment to

discard drilled solids. Water dilution also will

be required. Increase deflocculates

concentration to maintain stable properties.

HIGH

VISCOSITY

High funnel viscosity Normal plastic viscosity High yield point High gels Normal solid content

Add dispersant. Run mechanical solids

removal equipment.

HIGH

VISCOSITY

High funnel viscosity High plastic viscosity High yield point Normal gels Normal solid content

Run mechanical solids removal equipment to

discard drilled solids. Water dilution also will

be beneficial. Later thinner may be added.

HIGH

VISCOSITY

High funnel viscosity Normal plastic viscosity High yield point Normal initial gel strength High 10-min gel strength High Pf, Low pH, High

Mf.

Possible carbonate problem. Run pH/Pf

analysis or Garrett Gas Train for carbonates.

Treat with lime and/or gypsum as necessary.

HIGH FLUID

LOSS

Normal viscosity Add fluid loss control agent through hopper

HIGH FLUID

LOSS

High viscosity mud. Does not

take fluid loss control

additive.

Prepare a batch of new mud with excess fluid

loss control additive and add to mud over one

circulation. Treat contamination problem in

original mud.

SLOUGHING

SHALE

Excessive cuttings over

shaker. Tight connections.

Increase mud weight if possible. Reduce fluid

loss. Convert to inhibitive fluid or add

STABILHOLE. Increase viscosity. Reduce

drill pipe whipping. Reduce pressure surges.

DIFFERENTIAL

STICKING

Full or partial circulation.

String against porous zone.

No key seats. High fluid loss

with high solid content mud.

Place diesel or mineral oil and PIPE-LAX

fluid to cover drill collars and keep some in

pipe to move at 10-min intervals. In weighted

systems, use PIPE-LAX W additive.

Condition filter cake and reduce fluid loss

with M-I GEL, RESINEX.

PROBLEM

INDICATION

TREATMENT

PLASTIC SALT

Tight connections. Ream to

bottom after trips. Stuck pipe

could result.

Increase mud weight. Ream through tight

spot.

PLASTIC SALT

Stuck pipe when fluid is

saturated water-base or oil-

base.

Place fresh water to dissolve salt where pipe

is stuck, usually near the bit. Then increase

mud weight.

Contami

nant

Contamin

ant

compound

/ion

Contami

nant

Source

Method of

Measurem

ent

Possible

Effect on

Mud

Course of Action

Anhydrit

e /

Gypsum

CaSO4/

CaSO4.2H

2O Ca++

Formatio

n,

Ca++

titration

High yield point

High fluid loss

High gels Thick filter

cake

Ca++ increase

Treat with sodium carbonate (

soda ash )

Ca++(mg/L) x 0.00093 =

Na2CO3 ( lb/bbl)

Commerc

ial

gypsum

Break over to gypsum mud.

MgCl2

Mg++

Cl-

Formatio

n,

Seawater

Total

hardness,

Cl-

titration.

High yield point

High gels High fluid

loss

Thick filter cake

Total hardness

increase.

PH decreases.

Pf decrease.

Treat with caustic soda, NaOH

(pH >/= 10) for moderate

contamination, eg: seawater.

Mg++(mg/L) x 0.00116 =

NaOH (lb/bbl)

Treat with additional thinner

and fluid loss chemicals.

Convert to MgCl2 mud if

contamination is severe.

NOTE: For severe MgCl2

contamination, continued

additions of Na(OH) or

Ca(OH)2 could result in an

unacceptable viscosity

increase.

Cement/li

me

Ca(OH)2

Ca++

Cement, Titration

for Ca++,

High yield point

Treat with sodium bicarbonate

Ca++(mg/l)x0.00074 = commerci

OH- al lime, Pm High fluid loss

Thick filter cake

PH increases

Pm increase

Ca++ increase

NaHCO3 (lb./bbl)

Treat with SAPP

Ca++(mg/l) x 0.00097 =

Na2H2P2O7(lb./bbl) contamin

ated

barite Treat with lignite 7 to 8 lb./bbl

precipitates 1 lb./bbl Ca(OH)2

to form Ca salt of humic acid.

Additional thinner / fluid loss

chemicals.

Dilution

Dump if flocculation can not

be controlled.

Allow Ca(OH)2 to remain and

convert to lime mud or allow

Ca(OH)2 to deplete over time.

In some cases use acids such as

HCl, phosphoric.

Treat with soda ash

Ca++(mg/l) x 0.00093 =

Na2CO3(lb./bbl)

Since effect of pH are often

more detrimental to mud order

chemical treatment should be

1. sodium bicarbonate 2. lignite 3. SAPP 4. Soda ash

Sodium bicarbonate is

treatment by choice.

Salt NaCl Formatio

n i.e., salt

dome,

stringers,

Cl-

titration

High yield point

High fluid loss

Thick filter cake

High gels Cl-

increase

Dilution with fresher water

Addition of thinner/fluid loss

chemicals reasonably tolerant

of NaCl.

saltwater

flow,

Convert to salt mud using

chemicals designed for salt.

make up

water

Presolubilize chemicals where

possible

Dump if flocculation is too

severe for economical

recovery.

Carbonat

e

bicarbona

te

CO3

HCO3

Formatio

n,CO2

gas.

Garrett gas

train, pH,

Pf method,

P1/P2,

Mf/Pf

high yield point

high 10 min gel

high HTHP

Treat with lime

HCO3-(mg/l) x 0.00021 =

Ca(OH)2 (lb./bbl)

And CO3 (mg/l) x 0.00043 =

Ca(OH)2 )lb./bbl) thermal

degradati

on of

organics,

titration fluid loss

Ca++ decrease

Mf increase

pH instability

flocculation

contamin

ated

barite,

over

treatment

with soda

ash or

bicarbona

te.

Treat with gypsum

CO3 (mg/l) x 0.001 = CaSO4.

2H2O (lb./bbl)

And caustic soda

HCO3- x 0.002 = NaOH

(lb./bbl) Bacterial

action on

organic

Hydrogen

sulfide

H2S H2S from

formation

gas,

thermal

degradati

on of

organics,

bacterial

action.

Garrett gas

train,

(quantitativ

e),

automatic

rig H2S

monitor(qu

antitative),

lead acetate

test.

High yield point

High fluid loss

Thick filter cake

pH increase

Pm increase

Ca++ increase

Course of action to be in

compliance with all safety

requirements.

Pretreatment/treatment with

MIL-GARD or MIL-GARD-R.

Increase pH >11 with Ca(OH)2

or NaOH.

Condition mud to lower gels

for minimum retention of H2S.

Operate degasses, possibly

with flare.

Displace with oil mud.

CHEMICALS REQUIRED TO REMOVE IONIC CONTAMINANTS

CONTAMIN

ANT

(MG/L)

X FACTO

R

= TREATING CHEMICAL

Ca++ X 0.00093 = Na2CO3 (soda ash)

Ca++ X 0.00074 = NaHCO3 (bicarbonate of soda)*

Ca++ X 0.0097 = Na2H2P2O7 (SAPP)

Mg++ X 0.00093 = Na2CO3

Mg++ X 0.00116 = NaOH (caustic soda)**

CO3= X 0.00043 = Ca(OH)2 (lime)*

CO3= X 0.001 = CaSO4. 2H2O (gypsum)

HCO3- X 0.00021 = Ca(OH)2**

HCO3- X 0.002 = NaOH (caustic soda)

PO4 (-3) X 0.00041 = Ca(OH)2**

*Best to use where pH and calcium are high.

** Use with caution; may cause high pH.pj\v.[kb/

EXAMPLE:

Titration of the filtrate shows a calcium level of 650 mg/l. to remove all but approximately 100

mg/l, treat 550 mg/l, (650 100 = 550) of calcium with soda ash. Therefore, soda ash required is approximately

550 x 0.00093 = 0.51 lb./bbl.