Borehole Problems

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BORE HOLE PROBLEMS

BORE HOLE PROBLEMSCONTAMINANT:

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

CONTAMINANTEXAMPLE

Drill solidsActive solids - clays

Inactive solids - silt, sand limestone, chert, etc.

EVAPORITE SALTSSodium chloride, NaCl

Potassium chloride, KCl

Calcium chloride, CaCl2

Magnesium chloride, MgCl2

Anhydrite, CaSO4

WATER FLOWSMixed salts at various concentrations.

ACID GASESCarbon dioxide, CO2

Hydrogen sulfide, H2S.

HYDROCARBONSLight or heavy oils

Lignite

Coal

TEMPERATUREDegradation of mud products.

CEMENTResult 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

CauseIndicatorsSolution

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

TRENDChanges in mud properties are an indication that something abnormal is taking place.

MUD PROPERTYTREND

CHANGEPOSSIBLE CAUSE

MUD WEIGHTINCREASEDrill solids increase, heavy spot from barite sag. Over treatment during weight-up.

DECREASEFormation fluid influx, light spot from barite sag. Excessive water additions.

FUNNEL

VISCOSITYINCREASEReactive shale drilled, drill solids increase, low water content, calcium contamination from cement, anhydrite formation drilled.

DECREASEFormation water influx, excessive water content.

PLASTIC

VISCOSITYINCREASEUnconsolidated sand drilled, drill solids increase, low water content.

DECREASEFormation water influx, excessive water additions, and solids content decrease.

YIELD

POINTINCREASEReactive shale drilled, anhydrite formation drilled, low water content, calcium contamination from cement.

DECREASEFormation water influx, excessive water additions, decrease in low gravity solids, additions of chemical thinners.

GEL

STRENGTHINCREASEReactive shale drilled, low water content, calcium contamination from cement, or anhydrite formation drilled.

DECREASEFormation water influx, excessive water additions, additions of chemical thinners.

API / HPHT

FLUID LOSSINCREASE

Low gravity solids increase, flocculation from cement, chloride, calcium contamination, low gel content.

DECREASEMud treatment-taking affect.

pHINCREASEAdditions of pH control additives, calcium contamination.

DECREASEAdditions of mud products, anhydrite formation drilled.

CHLORIDEINCREASESalt formation is drilled, pressure transition shale is drilled, formation water influx.

DECREASEWater additions

TOTAL

HARDNESSINCREASESalt or calcium formation is drilled, formation water influx.

DECREASEAddition of fresh water, chemical addition.

CATION EXCHANGE CAPACITY (CEC)INCREASEReactive shale is drilled, addition of bentonite.

DECREASEWater additions, solids removal equipment.

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

TRENDChanges in mud properties are an indication that something abnormal is taking place.

MUD PROPERTYTREND

CHANGEPOSSIBLE CAUSE

MUD WEIGHTINCREASEDrill solids increase, Heavy spot from barite sag. Over treatment during weight-up.

DECREASEFormation water influx, Excessive base oil additions, Light spot from barite sag

PLASTIC

VISCOSITYINCREASEAddition of water, calcium carbonate, primary emulsifier, low gravity solids increase.

DECREASEAddition of base oil, Decrease in low gravity solids.

YIELD

POINTINCREASEIncrease in organophilic clay, Addition of emulsified water or synthetic polymer.

DECREASEAddition of base oil or degellant. Decrease of organophilic clay

GEL

STRENGTHINCREASEAddition of organophilic gel, Addition of water.

DECREASELarge base oil additions, Increase vin mud temperature.

OIL / WATER RATIOCHANGELarge addition of water or water influx. Large addition of base oil. High bottom hole temperature.

ELECTRIC STABILITY ( ES )INCREASEIncrease in emulsifier concentration. Addition wetting agent or base oil.

DECREASEDecrease in emulsifier concentration. Newly prepared OBM has low ES but increases with lime.

WATER PHASE SALINITYINCREASEWater % of O/W ratio decreasing. Addition of calcium chloride

DECREASEWater % of O/W ratio increasing from water addition or formation water influx

HPHT

FLUID LOSSINCREASEAddition of base oil. Decrease in emulsifier. Water present in filtrate.

DECREASEIncrease in primary emulsifier concentration.

EXCESS LIMEINCREASEAddition of lime. Drilling calcium formation ( anhydrite )

DECREASECO2 or H2S kick. Addition of base oil or water.

PROBLEMINDICATIONTREATMENT

FOAMINGFoam 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

CONTAMINATIONHigh 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 CONTAMINATIONHigh 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 CONTAMINATIONHigh 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 GELATIONDifficult 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 BALLINGLittle 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 CONESCones 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.

ABRASIONPremature 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 FLOWIncrease 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 KICKIncrease 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.

PROBLEMINDICATIONTREATMENT

MUD LOSSESDecrease 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 MUDBarite 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 contentRun 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 contentAdd dispersant. Run mechanical solids removal equipment.

HIGH VISCOSITY High funnel viscosity

High plastic viscosity

High yield point

Normal gels

Normal solid contentRun 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 LOSSNormal viscosityAdd fluid loss control agent through hopper

HIGH FLUID LOSSHigh 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 SHALEExcessive 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 STICKINGFull 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.

PROBLEMINDICATIONTREATMENT

PLASTIC SALTTight connections. Ream to bottom after trips. Stuck pipe could result.Increase mud weight. Ream through tight spot.

PLASTIC SALTStuck 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.

Contaminant Contaminant compound/ionContaminant SourceMethod of Measurement Possible Effect on MudCourse of Action

Anhydrite / GypsumCaSO4/ CaSO4.2H2O Ca++Formation, Ca++ titration High yield point

High fluid loss

High gels

Thick filter cake

Ca++ increaseTreat with sodium carbonate ( soda ash )

Ca++(mg/L) x 0.00093 = Na2CO3 ( lb/bbl)

Commercial gypsum

Break over to gypsum mud.

MgCl2Mg++

Cl-Formation, SeawaterTotal 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/limeCa(OH)2

Ca++

OH-Cement, Titration for Ca++, Pm High yield point

High fluid loss

Thick filter cake

PH increases

Pm increase

Ca++ increaseTreat with sodium bicarbonate

Ca++(mg/l)x0.00074 = NaHCO3 (lb./bbl)

commercial lime,

Treat with SAPP

Ca++(mg/l) x 0.00097 = Na2H2P2O7(lb./bbl)

contaminated 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.

SaltNaClFormation i.e., salt dome, stringers,

Cl- titration High yield point

High fluid loss

Thick filter cake

High gels

Cl- increaseDilution 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.

Carbonate

bicarbonateCO3

HCO3Formation,CO2 gas.Garrett gas train, pH, Pf method, P1/P2, Mf/Pf titration high yield point

high 10 min gel

high HTHP fluid loss

Ca++ decrease

Mf increase

pH instability

flocculationTreat 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 degradation of organics,

contaminated barite,

over treatment with soda ash or bicarbonate.

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 sulfideH2SH2S from formation gas, thermal degradation of organics, bacterial action.Garrett gas train, (quantitative), automatic rig H2S monitor(quantitative), lead acetate test. High yield point

High fluid loss

Thick filter cake

pH increase

Pm increase

Ca++ increaseCourse 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

CONTAMINANT

(MG/L)XFACTOR=TREATING CHEMICAL

Ca++X0.00093=Na2CO3 (soda ash)

Ca++X0.00074=NaHCO3 (bicarbonate of soda)*

Ca++X0.0097=Na2H2P2O7 (SAPP)

Mg++X0.00093=Na2CO3

Mg++X0.00116=NaOH (caustic soda)**

CO3=X0.00043=Ca(OH)2 (lime)*

CO3=X0.001=CaSO4. 2H2O (gypsum)

HCO3-X0.00021=Ca(OH)2**

HCO3-X0.002=NaOH (caustic soda)

PO4 (-3)X0.00041=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.