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MUD FACTS Written By Raafat Hammad

All About Mud

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Page 1: All About Mud

MUD FACTS

Written By

Raafat Hammad

Page 2: All About Mud

HYDRODYNAMICS:Viscosity of Fluids : All fluids exhibit a certain resistance to flow, In general terms, a fluid is often described as being thick or thin. A thick fluid crude oil has a high viscosity than thin fluid such as water.In general viscosity is defined as the relationship between the shear stress (flow pressure) and the shear rate (flow rate), shear stress and shear rate cause deformation of mud matter and thus affect the flow property of the drilling fluid.

1. Shear stress:

It can b defined as the force required to overcome the fluid resistance to flow divided by the area that force acting on.Shear stress (t) =force applied (dynes) / A (cm2) = dunes / cm2

Where: A is the surface area subjected to stress.

2. Shear rate:

It can be defined as the relative viscosity of the fluid layers, or elements divided by their normal separation distance.Shear rate (y) = V (cm/sec) / H (cm) = sec-1

FIGURE

Assume that two flat plates are placed parallel too each other, at 1 cm apart the top plat is free to move, while the bottom plat is fixed , the space between the two plates is filled with fluid . So if a force is then applied to the top plate, so that it moves with a constant velocity of 1 cm /sec, that force will be transmitted to the fluid, thus causing the layers within to move also but with different rates. The layers that is close to the moving plate will move approximately with the same velocity of the plat, while the movement of the force that is transmitted through the layers diminishes until the movement at the fixed plat is nearly equal zero.Thus viscosity can be defined as a measure of the resistance of a fluid to flow.Viscosity = shear stress / shear rate.

Drill Fluid Rheology :

Rheology can be defined as the science of the deformation of the flow of matter.It as usually described by viscosity and gel strength.Types of flow regimes: Laminar flow. Turbulent flow.N.B. The type of flow is usually depending on the flow rate (SPM * POP), the flow pressure and the relative of the flow channel. Laminar flow: Is generally associated with low flow rate, low fluid velocities and with fluid movement in uniform layers. In laminar flow the force (pressure) required to induce flow increases as the fluid velocity increase.

CURVE

In laminar flow, the fluid particles tend to move in straight lines parallel to direction of flow. The layers near the wall of the flow channel tend to move at a lower velocity than that exists in the center of the flow channel, thus

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the flow profile of the fluid in case of laminar flow when move a cylindrical pipe will be in a sort of concentric cylinder.

FIGURE

Turbulent flow:

In generally occurs at high flow rates, high fluid velocities, and is characterized by an erratic, random movement of the drilling fluid particles.A flowing fluid is generally considered to be an either laminar or turbulent flow.There is a very critical period called transitional period between two regimes when the movement of fluid particles is no longer complete laminar, nor has it yet become complete random .I.e.: If the flow pressure is reduced slightly, the fluid particles will return to the laminar movement. Conversely, if the flow pressure is increased sufficiently the fluid particles will assume the random flow patterns associated with the turbulent flow.This transition occurs at some critical velocity, which is generally governed by the ratio of the fluids internal forces to its viscous forces this ratio is called Reynolds number (Nre) Nre = [diameter of the flow channel *average flow velocity * fluid density]/ fluid viscosity

CURVE

N.B.Shear stress and shear rate data, allows accurate determinations of the fluid behavior under varying flow conditions.This data then provides the basis for further calculations used to determine several important aspects related to the drilling fluids parameters.I.e.: proper understanding and application of rheological principles can be valuable aid in determination of dynamic performance of drilling fluid in order to establish and maintain the most effective properties for efficient and economical drilling fluid performance. These further calculations are:1. Fluid velocity.2. Calculation of the system pressure losses.3. Calculation of surge and swab pressures.4. Bit and jet nozzle hydraulics.5. Relative hole cleaning efficiency.6. Equivalent circulating density.7. Estimation of the relative extent of hole erosion.

Reynolds Number:

a. In pipe Nr = 15.46 dvw / PV.b. In annulus Nr = 15.46(dh-dp) vw / PV.Fluid velocity (ft/min):a. In pipe V = 24.51 GPM / d2.b. In annulus V = 24.51 GPM / (dh2 – dp2) OR = POP (bbl/min)/ Ann. Vol. (bbl/ft). Critical Velocity (ft/min):a. In pipe V = 64.57 PV + 64.57 [(PV)2+ 12.3 d2YP W] / wd.b. In annulus V = 64.57 PV+ 64.57 [(PV)2+9.26(dh – dp)2YP W] /w(dh – dp).Slip Velocity Vs (ft/min):a. Laminar Flow = 3210 (Wc – W) D2 V / 339 YP (dh – dp) + PV V.b. Turbulent Flow = 60 [D(Wc – W) /W] .

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I.e.: Slip Velocity is that velocity of desendigration of cuttings, according to its specific gravity, cutting size and hole size, which acts against fluid velocity, carrying capacity and viscosity of mud.

WHERE :

V = fluid velocity (ft/min).GPM = gallons per min. d = hole diameter.(in) Dp = pipe diameter (in)D = cutting diameter(in).Wc = cutting density (PPG).L = section length (ft).W = mud weight (PPG).Vc = critical velocity(ft/min).PV = plastic viscosity (cp).YP = yield point.(lbs./100sq ft).TVD = true vertical depth(ft).

Pressure drop = [Mwt in – Mwt out] * 0.0519 * TVD.

MUD FACTS AND PRINCIPLES

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PLASTIC VISCOSITY (PV)=======================================The friction to resist moving of mud layers against each other in dynamic stateIn other wordsIs the resistance of the fluid particles to move against each other in dynamic state, which is caused primary by the friction between the suspended particles and the viscosity of the continuous liquid phase.

NB: PV is a function of solidsI.e.: plastic viscosity depends on the concentration of solids, also size and shape of solids.

PV is affected by the following: 1- Size and distribution of solids2- Shape and concentration of solids.3- Fluids phase viscosity

NB:* The finer the solids, the higher the PV due to the increase of surface area which surrounded by more Volume of water.*PV may be called (bit viscosity) which is equivalent to the viscosity of mud coming out of the bit, because PV has to be measured at high shear rate.*PV = 600 reading – 300 reading

CAUSES OF PLASTIC VISCOSITY (PV) INCREASE:

1- Increases of solids concentration a- drilled solids b- commercial solids

1- Barite2- Bentonite

2-Increases of solids surface area.

Non dispersed solids Dispersed solids

less surface area * more surface area less quantity of adsorbed water * more quantity of adsorbed water more available free water *low available free water low PV *high PV low YP *high YP

CAUTION

!S T O P

IN GENERAL: PV gives an indication about the nature of solids in mud

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low GEL *high GEL low viscosity *high viscosity* High capability to removed *low capability to be removed thin fluids * thick fluids thin rigid cake *thick cake

NB: Increase of PV direct related with increases of YP, also with increases of annular pressure losses and with increases of ECD value, and decreases of ROP value.

METHODS OF DECREASING PV:=================================

1- DILUTION:a- with water in case of water base mud.b- With diesel in case of oil base mud.c- With clean premixed mud.

2-REMOVAL OF SOLIDS BY:

a- solids control equipment’s b- settling

Natural settling: is effective because some of solids are colloidal and suspended.(NB: settling does not take place by stopping agitation.)

c- adding Flocculants:This is done by flocculate solids and decrease surface area of solids.Flocculants are chemicals added to collect the solids together to decrease surface area of solids and thus can easily remove solids out of mud.

NB: treating by dilution is more effective than chemical treatment.

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YIELD POINT (YP ) :

IT’S THE ELECTRO – CHEMICALS ATTRACTION BETWEEN SOLIDS OR MUD COMPONENTS

IN OTHER WORDS:

IT’S THE FORCE REQUIRED TO SLIDE ONE LAYER OF THE MUD OVER ANOTHER

These forces are a result of the +ve and –ve charges located on the surface of fluids layers.YP is the measurement of these forces and its effect on fluids under flowing condition of drilling fluid.

NB: YP is the measure of FlocculationIn general YP gives some indication of hole cleaning ability of the fluid, when the fluid is in motion

CAUSES OF (YP) INCREASE: (CAUSES OF FLOCCULATION)=============================================================

1- FLOCCULATION DUE TO TEMPERATURE :====================================

THIS TAKE PLACE BY

A- CHEMICAL DEGRADATIONB- CLAY MOVEMENTC- DEHYDRATION

**Over 150 F the space between clay particles increases causes over hydration on the clay particles, so Water is no longer available in the system to keep mud flows, that’s why mud become more thicker

**Over 350F a chemical degradation to clay particles occurs, causes an increase in activating ions and by term an increase in Electro-chemicals attraction occurs, so Flocculation occurs accompanied by increase in YP.

TO DECREASE (YP ) DUE TO TEMPERATURE: (TEMP FLOCCULATION )

A- Dilute with water or fresh mud B- Reduce clay as possibleC- Add high temp Deflocculant

2- FLOCCULATION CAUSED BY SOLIDS CROWDING: REASONS:

A- Weighting up of mud ( water should be added to wet barite)B- Poor solid control equipmentC- Reactive formationsD- Dehydration.

TO DECREASE (YP) CAUSED BY SOLID CROWDING:

A- Dilute with water or fresh mud.B- Use high efficiency solid control equipment

3- FLOCCULATION CAUSED BY ALKALINITY CHANGES: REASONS:

A- PH increases or decreases due to cement contamination.B- Lime addition.

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C- Acid gas influx (CO2 , H2S )D- CarbonateE- Incorrect Pm/Pf ratio (lime mud )

NB: High PH causes flocculation due to increases of attraction forces between particles.

TO DECREASE (YP) CAUSED BY ALKALINITY CHANGES:

A- Increases of PH by adding caustic soda or caustic potash.B- Decreases of PH by dilution or adding organic acid such as Lignite (3.8 PH) or lignosulfonate (4.2 PH).C- Adjusting Pm/Pf ratio by adding lime or caustic soda.

4- FLOCCULATION CAUSED BY COMMERCIAL ADDITIVES ( BENTONITE & POLYMERS):

A- Overdoses of polymers (such as viscosifiers, flocculants, water loss reducer )B- Excess of bentonite.

TO DECREASE (YP) CAUSED BY COMMERCIAL ADDITIVES:

A- Dilute with waterB- Adding deflocculants.

5- FLOCCULATION CAUSED BY CHEMICAL CONTAMINATION:

A- Salt/salt waterB- CalciumC- CarbonatesD- CementE- H2S/CO2F- Anhydrite/Gypsum.

TO DECREASE (YP) CAUSED BY CHEMICAL CONTAMINATION:

A- Add deflocculantB- Chemically remove the contaminateC- Dilute

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RELATION BETWEEN (PV) AND (YP):

1- If both (PV) and (YP) increases: ( solid content problem) TREATMENT:

A- DilutionB- Maintain solid control equipment.

NB: Don’t add thinner otherwise (YP) will dramatically decreased and (PV) still high and this will causes barite settling. 2- If (PV) is steady and (YP) increases : ( chemical contamination problem-YP problem) TREATMENT:

A- DilutionB- Add Deflocculants

NB: In low saline mud and as a result of presence of CL ions (at a certain limit) the (YP) increases with no effect on (PV) value, this take place due to increases of Electro-chemical attraction between ions in mud, so if same salinity required, add deflocculants, And if we need to reduce salinity we had to dilute with water.

3- If (PV) and (YP) decreased : (in case of high saline mud) TREATMENT:

A- Add Flocculants B- Add ViscosifiersC- Add Water reducers.

NB: In high saline mud, the % of free CL ions will increase in the mud and thus will retrieve water from bentonite plates back to the system, so both PV and YP will decreases. That besides increasing of frees H2O and thus increases of water loss.

GENERAL NOTES:

1- PV = 600 READING - 300 READING

2- YP = 300 READING - PV

3- YP IS A MEASUREMENT OF THE CHARGES ON THE SOLID.

4- ALWAYS KEEP PV LOWEST AS POSSIBLE.

5- PV IS A FUNCTION OF SOLIDS.

6- IF PV INCREASES, YP MUST BE INCREASE DUE TO CROWDING EFFECT OF FINE SOLIDS. THESE FINE SOLIDS PUSHES THE CHARGES TO EACH OTHER, SO THE ELECTRO-CHEMICAL ATTRACTION BETWEEN MUD COMPONENTS INCREASES, CAUSING YP INCREASE.

7- CHEMICAL CONTAMINATION Ca, Mg AND SALT, WILL INCREASE YP WITH NO EFFECT ON PV.SO: IF PV INCREASED, YP MUST BE INCREASED TOO. BUT YP INCREASING DOES NOT AFFECT THE PV VALUE.

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GEL STRENGTH:

Is the measurement of chemical attraction forces between mud particles under static conditions. GEL Strength is an indicator for low shear rate rheology at 3 rpm reading ( V.G meter)

Gel strength importance:

A- Low gel strength : causes

1- settling of cutting and barite in static’s conditions2- building up of cuttings beds in deviated wells

B- High gel strength : causes 1- increasing pressure in break circulation to break down gel( may break down formation and

causes mud losses )2- Increasing applied pressure to the formation while running in hole. (Might break down formation, causes mud losses)3- Swabbing while pull out of hole.4- Poor cement jobs( as gel are hard to break, so that causes channeling of cement)

TYPES OF GEL:

1- Fragile or flat Gel:

Gel strength of 10 minute is slightly higher than 10 seconds gel even if 10 seconds gel reading is high.

This gel can be easily broken by low pump pressure.

This type of gel has low swab and surge pressure.

2- Progressive or elevated Gel:

Gel strength increases significantly after 10 minute, even if 10 seconds gel is low.

Causes of Progressive Gel:

1- Reactive formation resulting in high percentage of reactive solids.2- Solids crowding.3- In sufficient deflocculation.4- Carbonate contamination (CO3& HCO3).

NB: Relation between Gel,YP, and Viscosity, Cake and pore hole diameter:---

The increases of viscosity causes increase in YP & Gel, where too much increase of viscosity causes removed of filter cake and may causes wash in bore hole diameter.

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FILTRATION:

Is the rate of water loss of mud into formations

There are two aspects of the filtration phenomenon :

1- The quantity of filtrate which is the volume of filtrate that invades the formation.(Anyhow lowering the water loss helps in hole stability)

2- The quality of filtrate, which gives an idea about the type and concentration of materials dissolved in filtrate.This gives an idea about the extend of stability of mud resulting from chemical interaction forces between mud components, also gives an idea about the amount of contaminants dissolved in mud (LGS, SALT and Chemical contaminants) thatContributes this stability.NB: 5ppb water loss reducer ==== water loss = +/- 3.0

FILTER CAKE:

IS THE MEASUREMENT OF THE RELATIVE AMOUNT OF MUD SHEETS DEPOSITED ON THE PORE HOLE FORMATION SURFACE

Evaluation of filter cake depends mainly on two items:

1- QUALITY:A- ImpermeableB- Non Porous

This much affected by: percentage of solid in mud shape and size of solids chemical contaminant in mud

2- QUALITY: (THIN OR THICK)Cake must be thin to minimize well sticking and reduce friction forces between drill string and pore hole wall. This is much affected by:

Quantity of water loss. Solid content in mud Chemical contaminant

RELATION BETWEEN WATER LOSS AND FILTER CAKE.

Isolating the formation from the drilling fluids will minimize the potentially detrimental interaction between Filtrate and exposed formation and thus control the hole stability, this is complied by controlling: Water loss Quality and quantity of filter cake. In other word minimize water loss by mean of water loss reducers together with getting rid of colloidal Materials (LGS) off mud and chemical treatment of chemical contaminants .

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SOLIDS:TYPES OF SOLIDS:

A- High gravity solids (Ca CO3 +Barite)B- Low gravity solids (drilled solids + bentonite)

Increases of drilled solids effect:1- increase of mud weight2- increase of viscosity3- increase of Gel = may leads to gellationNB: Gel must be obtained from bentonite or polymers not from drilled solids (to keep cutting suspended in mud in static case not to be settled)4- Increase of water loss.5- Increase of PV & YP6- Increase cake thickness and porosity.NB: Increase of high gravity solids in mud leads to increases in mud weight only, when low gravity solids Increase in mud leads to all pervious effects and may causes flocculation in mud.

7- Severe cut to PH =which may leads to bicarbonate problem.

Removing solids off mud produces the following benefits:1- Improve filter cake quality (less coarse drilled solids) results in a less permeable and less porous cake.Improving cake quality (thinner and tougher) minimize wall sticking and pore hole wallAnd thus reducing pipes corrosion and minimizes pressure produced on formation resulting from those friction forces (surge ) and thus reducing fluid losses.

2- A decrease in concentration of drilled solids contributes to improve and maintain rheological and other mud properties and thus reduce mud maintenance cost.

Increase of solids in mud can be detected by:1- Weighting mud2- Evaporating and condensing mud fluid in a cylinder, leaving solid residual behind.3- Increase of PV

BENEFITS OF OBTAINING LOW PERCENTAGE OF LOW GRAVITY SOLIDS (LGS ) IN MUD :

1- Better hole condition2- Reduce torque and drag3- Reduce swab and surge pressure4- Reduce tendency for differential stuck.5- Fewer possibility of stuck of logging tool.6- Improve bit run7- Reduce bit and stabilizer balling8- Better hole stabilityNB: As increase of LGS % in mud causes an increase in mud weight and thus increases the hydrostatic head of mud column and by turn ECD.In other words increase the imposed pressure on formation which may exceed fracture pressure of the formation leading to a loss of circulation.9- Keep PV low and thus obtaining higher penetration rate.

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10- Low abrasive LGS in mud reduces equipment wear and repair11- Low abrasive LGS in mud minimize pipe washout.12- Better cement jobs.13- Better condition drilling fluid, thus low rate of dilution and mud treatment, which Reduces mud cost.

Effect of solid size on ROP:Particles less than 1.0 micron decrease rate of penetration 12 times more than that which is higher than 1.0 micron because:1- PV increase 2- Surface area for adsorption of water increases NB: 6-8 % colloidal solids adsorb 50% of water3- Since percentage of adsorbed water increases, the mud will become thicker which may lead to flocculation

of mud.Solid analysis determines: % LGS and HGS Mass balance calculation methods Salinity corrections Percentage of reactive solids Percentage of bentonite and drilled solids Cation exchange capacity (CEC) of bentonite and shale.

Remove solids by:1- dump and dilution 2- mechanical removal (solid control equipment)3- Settling.

NB: Some times diesel acts like solids, making what is known as (mechanical solids) causing increase in PV,YP and Viscosity, this take place as a diesel in retort make a sort of droplets which don’t condense and thus gives slightly increase in solid percentage.

NB: NEVER INCREASE MUD WEIGHT WITH DRILLED SOLIDS ( LGS).

I.e.: never to put off solid control equipment to increase mud weight

Example:

To increase mud weight 0.1 PPG with drilled solids, that means ==0.1 X 2.6 X 42 = 10.92 ppb of low gravity solids which is too high and will cause a lot of solid problems as mentioned before.

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SOLID CONTROL EQUIPMENT

Solid Control Depending on:1. Screening.2. Centrifugal force.3. Combination of both.A. Screen Device: This depends on: Screening area and number of mesh. Pump out put. Solids load or penetration rate. Mud viscosity.Factors Affecting Shaker Efficiency and Solid Removal:1. Screen selection:Selecting the right screen for shakers recommended to remove the maximum amount of solids of mud, and limits solids returning to mud system.Screen selection depends on: Amount and shape of solids to be removed. Circulating rate. Viscosity. Screen life expectancy.NB: 1. You will normally remove some finer solids than the mesh size due to piggy – backing .2. Changing wire diameter will change the cut point although mesh is the same.3. Fine screen anticipating losing mesh water due to increase of surface area on smaller solids which are

removed.Screen Types:a. Sandwich: If it’s a 40 mesh I.E.: it is accurately 80 mesh.Advantages: never plugged with sand.Disadvantages : plugged with gumbo shales.b. Rectangular opening. c. Plain weave. d. Conventional. Advantages: resist more than sandwich.Disadvantages: plugged with sand faster than sandwich.e. Oblong: The best square mesh screens.f. Pyramidal: Advantages: never plugged with sand.Disadvantages: plugged with gumbo shales.What does screen mesh means?Mesh means the linear measurements of number of openings per square inch.I.E: Mesh counts opening per square inch. EG: 80 mesh 80 openings per square inch. One mesh includes width of one opening plus width of one wire. Mesh count only tells the number of openings per linear inch in each direction. Changing wire diameter without changing mesh will change the cut point although mesh is the same. Size openings depend on mesh count and wire size.NB: If screens are cutted at the same point several times you have to change the support cushion(Page6-10).

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Type of Motion:A. Circular.B. Elliptical.C. Longitudinal.

Circular and elliptical damage faster than longitudinal.But elliptical is better than circular where the solids are exposed to more surface area at the screen.Angle of Deck: Horizontal decks Have a higher liquid handling capacity than the sloped deck shakers, since the liquid has no tendency to run off the end of the shakers. Sloped decks shakers: Have a higher solid handling capacity because the deck angle tends to make solids fall off the unit as it vibrates.NB: Screen motion and deck angle controls:1) Rate of travel of cuttings along screen. 2) Solid capacity . Distribution of fluid carrying solids on screens.3) Fluid capacity.

Flow Capacity:a. As PV increases flow capacity decreases.b. As mesh screens increase flow capacity increase.c. % screen covered increase flow capacity increase.d. Plugging effect increase flow capacity increase.

PS: Screens have a viscosity and solids limit.

Precautions; Wash down screens before trips. Keep screens clean and you will reduce blinding and plugging effect.

Amplitude or Stroke Length: Shakers are available with stroke lengths from 0.025 to 0.5 inches. The greater the stroke length , the higher

solid removal because of the greater the unit the unit handling capacity. Long strokes that forces thick fluids through the screen openings, also tend to force solids into the screens

openings which cause blinding or partially blinding that particularly while handling sticky solids.

Speed of Rotation:The general vibration frequency for shakers is 1100 to 3300 RPM.

Shale shaker (G) Force:The common expression for the amount force generated by a shaker is G force.

PS:Cut point of shaker means that all cuttings above that size of mesh screens will be separated on the shaker, below that size will pass from mesh screens of shaker back to system until removed with other solid control equipments.Cut point Millimicrons.

In General the Optimum Shale Shaker Operation Depends on:

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Mounting and Leveling:Shakers must be leveled according to GPM not too much to the front so as not to lose mud. Or not too much up so as cuttings do not accumulate on the back sides of screens which by turn will cause too much load on that part of screens and thus may cause screen cut and by turn solids will escape into system. Provide required voltage and frequency . Vibrator should rotate in proper direction. Install proper screens and proper support cushions.Proper and screen size is recommended so as not to have too narrow mesh and thus solids may plug screens and thus lose mud at shakers OR too wide and thus allow cuttings to pass into system and thus increase solids percentage in mud.Also make sure that sealing rubber (support cushions) of screens is proper and not small or cutted otherwise the solids will escape into system through cutted points. Tension screens properly. Size of mesh screens so as mud to cover 75 – 80 % of length. Use water hose to wash down screens on trips. You need partial plugging of mesh screens to aid in flow capacity and cutting removal. Make sure that the bypath of shakers is not leaking. Otherwise solids will escape to system. The volume of fluid lost on shale shakers per unit time depends on 1. Shaker design.2. Screen mesh and type.3. Drilling fluid properties.4. Solid loading.PS:If only 50 % or less of the screen area is covered with mud, finer mesh screens is recommend.Inspite that without changing screens, the operating ones can become partially blocked with time by cuttings wedge in the open screens (blinded) or by sediments/ residue/ mud dried on the wire cloth(coated).

B. Centrifugal Device: Depends on separating solids based on size and specific gravity of solids.The centrifugal separator mechanically subjects the fluid to increased G forces and thus increases the settling rate of particles by mean of this method both heavy – coarse and light – fine fractions are separated of mud. Desired fractions of solids are then selected and return to the system. This recharging works well with both low density(low gravity solids), and high gravity fluids.

FIGURE

Hydrocyclones Performance Depend on: Fluid viscosity. Mechanical condition of cones. Head at cone manifold(Feed pressure = 30 – 40 psi. Solid load.Hydrocyclones Instillation & Maintenance: Flow capacity should exceed rig circulating rate by 10 – 20 %. Eliminate mud guns and use mechanical agitators. Recommended individual centrifugal pump for each set of Hydrocyclones. Pumps properly sized to give recommended head at Hydrocyclones (35 psi). Lines properly sized and short as possible. Suction out of one compartment, and discharge down stream in next Replace only worn cones or nozzles. Do not bypath shakers, as bypassing shakers causes most plugged cones. Run as fine shale shaker screens as possible.

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Operate in spray discharge for higher efficiency. Periodically unplug (clean).NB: If keeping the previous percussion you will get the best solid separation.Also separation depends on:1. specific gravity of solids (separation).2. Size of particles (separation).3. Centrifugal force (separation).4. Liquid phase viscosity (separation).5. Solid load (separation).6. Feed pressure optimum (separation).7. Mechanical condition (separation).NB1: As centrifugal forces increases the cut point decreases (I.E. decrease the size of separated particles).NB2:As viscosity increases the cut point increases (I.E. increase the size of separated particles).PS:Under Flow GPM (equipment) = 1.25 X GPM (rig).

How heavy should cone underflow be? Depends on size and nature of solids in feed. Cone should be in spray discharge. Cone underflow should be heavier than feed. Desander underflow should be heavier than desilter underflow.

Hydrocyclones Optimistic Cut Point Centrifugal force increase

Size D 50 microns12” (Desander) 65 - 706” (desilter+M.C) 25 –324” (desilter+M.C) 16 –183” (desilter+M.C) 122” (desilter+M.C) 7 -10

Effect of PV 0n separation 4” coneMud PV (cp.) D 50 microns1 1610 1823 29

The higher the viscosity and PV the lower the efficiency of the equipment.

Effects of solids 0n separation 4” conePV = 7 YP = 1 solids %

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Solids % D 50 microns1.2 182.05 22.52.37 193.9 27

Hydrocyclones Rope Versus spray discharge

Discharge Wt(PPG) Solids Lb./hour lb./dayRope 4 GPM 14.5 46% 2392 57403spray 3 GPM 13 35% 3640 87360

NB:1. Cones processes 125 – 150 % of the flow line GPM.2. Optimum pressure on the solid control equipment = M.wt X (distance between pumps of solid control

equipments 75ft and the equipment itself) X 0.0519.

GPM of Solid Control Equipment:a. Measure how much time needed to fill a viscosity cup to the mark from one cone. Convert seconds to minutes.NB: viscosity cup = ¼ gallon.Say in 8 min.

0.25 gallon was filled in 8 min.0.25/8 = 0.03125 GPM for one cone.

b. Multiply by number of cones to get GPM of equipment.a. Multiply by 60 minutes to get gallon / hour.b. Multiply by 42 minutes to get bbl / hour.NB:On calculating equipment losses always try to match the GPM of equipment with equipment losses.PS:Never measure M.wt with drilled solids.I.E: Never to put off solid control equipments to increase mud weight.EG: To increase M.wt 0.1 PPG with drilled solids that means:0.1 X 2.6 = 0.26 (ppb LGS).2.6 = specific gravity of LGS.I.E: 0.26 X 42 = 10.92 (ppb of pure LGS). Which is too high and will cause a lot of solid problems as mentioned before.

See pages 6-13, 6-14, 6-15, and 6-16.

1. Desander / Desilter Operation Tips: A. Equipment is fed by a centrifugal pump maintaining a manifold pressure of 35-40 psi. Excessive pressure contributes to a bladder wear and effects cut point.

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Excessive pressure may be due to : Feed lines are plugged. Distance between equipment pumps and equipment itself is not correct. If pressure is less than 30 psi mean that there is a leak somewhere or equipment is not working. In both high and low pressures the efficiency of solid separation is not ok.B. Proper discharge from the cones is in the form of a conical pressurized spray. Roping may occur when the

fluids to be processed has an excessive amount of solids present in the mud .

Cones discharge may be adjusted by turning the adjustment at the cone apex. If discharge coming out of the cone is like a stream (like that causing out of a tap of H 2O). this means that cones are highly wearied which will not give a chance for good centrifuging and separating of excess solids.C. Cones may become plugged from time to time and should be cleaned by opening the adjustment and

inserting a welding rod or equivalent from the bottom to dislodge the solids blocking the discharge.D. Continual plugging of cones may be due to the failure of up stream solid control equipment, which should

be checked to insure that it’s functional.ORPlugging of cones may be due to incorrect shale shaker mesh screens which allows larger amount of solids to pass into system.(use finer mesh screen after unplugging cones to solve this problem).ORPlugging of cones may be due to those guns in tank before unit is on (stop guns immediately and use normal agitation).E. Weight of discharge must be high as an indication of getting rid of excess solids.

If discharge weight is nearly the same or higher a little bit than feed in mud . this means that equipment is not working.Also you can feel the discharge by your hand if it is mud or solids.

NB: Cones processes 125-150 % of the flow line GPM.2. Mud Cleaner: The hydrocyclone / screen combination consists of a bank of desilters which are mounted over a fine mesh vibrating screen. The discard from desilter is processed by the fine screens.Particles are removed by the screen and discarded while the fluid processed through the screen is returned to the active system.Mud cleaner is a fine screen shaker, its primary function is to remove that portion of sand size or larger that passes through rig shaker.NB: Ideally a 200 mesh screen would be desirable on mud cleaner , however 140-150 mesh screens is generally necessary to minimize barite losses.3. Degasses: By mean of centrifugal action separates gas + foam from mud. Hydrocyclones ID is ranging from 6”-12”. It process mud immediately from below the sand trap not from the sand trap.4. Centrifuge: Last defend for solids. Can remove solids below 4-6 microns that will not be separated at shakers and pass

to the system.These very fine particles have a greater effect on rheology than the coarser particles. Centrifuging will not however eliminate the need for water. But dilution rates will be reduced and a fluid maintenance cost reduction will be expected.Trend of PV can give an indication of how fast solids concentration is increasing the MBT and solid content and solid content can also be an assistance guide in this determination. Each type of centrifuge have its own optimum RPM (normal RPM from 1900 to 2200). Has to be used carefully in weighted mud otherwise will separate barite and affect M.wt.

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The reference to make sure that centrifuge is working ok is the discharge weight and weight of flow of processing mud coming out of centrifuge to system.

I.E: Must have good flow . processing mud weight must be less than operating mud weight.Charging optimum RPM range of any centrifuge affects the unit efficiency.

SOLID CALCULATION:

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CALCULATION USED IN SOLID – CONTROL EVALUATION

The following equation is based on the fact that the specific gravity (sg) of the mud is Equal to the sum of the specific gravity times the volume fraction of each component.In this simplified equation, the mud will consist of three basic components: liquid, low-gravity Solids, and high-gravity solids. Sm = VwSw + VlgSlg + VhgShg

NB: Volume of salt water corrected (Vwc) and specific gravity of water (Sw) is obtained from appropriate salt table.

CALCULATE OF LOW GRAVITY SOLIDS AND HIGH GRAVITY SOLIDS VOLUME SOLIDS ANALYSIS:Calculation of low-gravity solids and high-gravity solids from a retort analysis. Correct the retort values and the specific gravity of the water phase by using the salt tables.

EQUATION TO GET VOLUME OF LOW GRAVITY SOLIDS

[{ Vw}{Pf}+ {Vss}{Pb} + {Vo}{Po}] – 100{Pm} Vlg = {Pb – Plg}

EQUATION TO GET VOLUME OF HIGH GRAVITY SOLIDS

100{Pm} - [{ Vw}{Pf}+ {Vss}{Plg} + {Vo}{Po}] Vb = {Pb – Plg}

WHERE:- Vlg = volume of low gravity solids- Vss = volume % of suspended solids- Vb = volume of high gravity solids- Vw = water fraction corrected for presence of dissolved salt- Po = density of oil- Pm = density of mud (spgr)- Plg = density of low gravity solids (LGS) = 2.6- Pf = density of water phase corrected for dissolved salts

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EXAMPLES OF SOLID CALCULATIONS: IF : M .WT = 14.0 PPG = 1.88 sp .grDensity of weighted material (Pb)== barite = 4.2 & hematite = 5.0From retort: Vs (volume of solids ) = 28 %Vo (volume of oil) = 8 % Vwr(volume of water) = 64 %CL = 100,000 mg/l (Na CL)1. Correct retort value for soluble salts from Na CL table Pf = density of water phase corrected for dissolved salt = 1.111 Volume increase factor = 1.059 Vw ( water fraction corrected for presence of dissolved salt ) = Vwr X volume increase factor = 64 X 1.059 = 67.8 % Vss (volume percentage of suspended solids) = 100 – Vw – Vo = 100 – 67.8 - 8 = 24.2 % One bbl of mud = 14 PPG X 42 = 588 ppb Weight of water = 67.8/100 X PPG of brine water(water of 100,000 mg/l Na CL salt table) X 42 = 67.8/100 X 9.27 X42 = 263 ppb Weight of oil = 8/100 X 7.0 X 42 = 23 ppb Calculated weight of solids = weight of mud – weight of water (corrected) – weight of oil = 588 – 263 - 23 = 302 ppb

2. Substitute in equation to get volume of low- gravity solids and high-gravity solids.

[{Vw){Pf}+{Vss}{Pb}+{Vo}{Po}]-100{Pm} Vg = --------------------------------------------------------- {Pb – Plg} [{67.8}{1.111}+{24.2}{4.2}+{8}{0.84}] –100{1.8} = --------------------------------------------------------------- {4.2- 2.6} = 2.3 % LGS 100{Pm}-[{Vw){Pf}+{Vss}{Plg}+{Vo}{Po}] Vb = ----------------------------------------------------------- {Pb – Plg} 100{1.8}-[{67.8}{1.111}+{24.2}{2.6}+{8}{0.84} = -------------------------------------------------------------- { 4.2-2.6} = 21.9 % HGS (Barite)

Percentage of low-gravity solids to total solids

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2.3 = ------ X 100 = 9.5 % 24.2

Percentage of high-gravity solids to total solids

21.9 = ------ X 100 = 90.5 % 24.2

Weight of low-gravity solids .

9.5 = ------ X {2.6 x8.33}X [{24.2/100}X42] 100

= 20 pounds Weight of high-gravity solids

90.5 = ------ X {2.4 x8.33}X [{24.2/100}X42] 100

= 322 pounds Fluids concentration

TYPE SP.GR PPG (SP .GR X 8.34 ) PPB(PPG X 42) WATER 1.0 8.34 350.28 BARITE 4.2 35.028 1471.176 LGS 2.6 21.684 910.728 CARBONATE 2.7 22.518 945.756

Examples:1 -fluid with 3% LGS, how much concentrate in ppb.

{3/100} X{910.728} = 27.3 ppb

2 –Fluid with 54.6 ppb LGS, how much concentrate in percentage

{54.6}/{910.728} X 100 = 6.0 %

3 –Fluid weight 9.2 PPG, how much ppb of LGS in un-weighted mud (LGS % = 7.5%)

for unweighted mud: solids = solids % X [Mud weight – weight of water (8.34)] LGS % = 7.5 (% solids of retort) X ( 9.2 – 8.34 ) = 6.45 % ( % of corrected solids)

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LGS ppb = [{6.45}/{100 }}X 910.728 = 58.7 ppb

4 – On adding 5.5% solids to one bbl of mud free of solids, calculate volume increase

Volume increase = {5.5}/{100} + 1 = 1.055 bbl

5 - If water = 86 % , oil = 10 % , solids = 4 %, MBT = 18 ppbCalculate:

% of solids corresponding to one bbl corrected MBT corrected solids total solids in fluid

volume increase by 1 bbl = {4/100} + 1 = 1.04 bbl corrected solid % in one bbl = {4.0}/{1.04} = 3.85 % weight of solids = {3.85}/{100}X 910.728 = 35 PPB (of solids} corrected MBT in one bbl = {18.0}/{1.04} = 17.3 ppb total corrected drilled solids in ppb (LGS) LGS in ppb = 17.3 + 35 = 52.3 ppb total LGS % = [{52.3}/{910.728}] X 100 = 5.75 %

Mixing liquids of different densities

Mass balance equation : 1 - Two phase equation:

{Vt}{Wt} = {V1}{W1} + {V2}{W2}

Example: If Vt = 1890 bbl, Mwt (Wt) = 8.8 PPG ,calculate volume of water for 100 bbls. V1 = volume of water W1= weight of water (8.34 PPG) V2= volume of LGS W2= weight of LGS

100 X 8.8 = V1 X (8.34) + V2 X 21.7 100 X 8.8 = V1 X (8.34) + {100-V1} X 21.7 1290 = 13.36 V1 V1= 96.6 % V2 = 3.4 % OR: calculate for total volume:

1890 X 8.8 = 8.34 V1 + {1890 – V1} X 21.7 13.36 V1 = 24471

V1 = 1831.66 V1 % = {1831.66} / {1890 } X 100 = 96.9 % V2 (LGS) = 3.1 %

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2 THREE PHASE EQUATION:

Vt Wt = V1W1(H2O) + V2W2(LGS) + V3W3(HGS)

EXAMPLE: Vt = 100 bbl Wt = 12.5 PPG V1 = 84 ( % or bbl because Vt = 100 )

Solution: V2 + V3 = 16 % V2 = {16 – V3} W2(LGS) = 21.7 PPG W3(HGS) =35 PPG 100 X 12.5 = {84 X 8.34} + {16 –V3} X 21.7 (wt of LGS) X {V3 X 35(wt of barite)} 13.3 V3 + 1047.76 = 1250 V3 = 202.24 V3 = 15.2 % V2 (LGS) = 16 – 15.2 = 0.8 %

3 -FOUR PHASE EQUATION:

Vt Wt = V1W1( WATER) + V2W2( LGS) + V3W3( HGS) + V4W4 (DIESEL)

EXAMPLE: IF Vt = 100 Mwt = 12.8 PPG V1 = 72 (retort value) V4 = 10 (retort value)

Solution: V2 + V3 = 100 – {72 +10} = 18 V2 = {18 – V3} W2(LGS) = 21.7 PPG W3(HGS) =35 PPG W4(DIESEL) = 7 PPG 100 X 12.8 = 72 X 8.34 + {18 – V3}21.7 + V3 X 35 + 10 X 7 V3 (HGS) = 16.46 % V2 (LGS) = 1.54 %THREE PHASE MUD WITH SALT:

EXAMPLE: Mwt = 12.1 PPG Water = 80 %

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Solids = 20 % CL = 141,000

Solution: From Na CL salt table, salinity of 141.0 k, volume increase = 1.087 Brine volume = 80 X 1.087 = 86.9 % Corrected solids = 100 – 86.9 = 13.1 % From NaCL salt table, adjust density of water corresponding to 141.0 k of CL = 9.6 PPG 100 X 12.1 = {86.9 X 9.6} + { 13.1 – V3 }X 21.7 + 35 X V3 V3 = 6.9 % V2 = 13.1 (Total corrected solids) – 6.9 V2 = 6.2 %

ALKALINITY AND PH :

ALKALINITY IS DEFINED AS THE AVAILABILITY OF H+ IN SOLUTION

PH IS A FUNCTION OF DISSOCIATION OF WATER

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PH NUMBER ARE A FUNCTION OF H+ IONS CONCENTRATION IN GRAM IONIC WEIGHT PER LITER OF MUD. ALKALINITY PROPORTIONAL WITH 1/H+

PH = 16 PH = 7.0 PH = 814 ACIDIC NEUTRAL ALKALINE

IN GENERAL ALKALINE MEDIA IS THE BEST ENVIRONMENT FOR ALL CHEMICAL PRODUCTS TO PERFORM GOOD WHILE DRILLING

PH EXPRESSED AS LOG SCALE (BASE 10)Example: PH OF 9.0 indicates an alkalinity ten times as greater as that of PH of 8.0 . PH value depending on the concentration of OH group and or CO3 , HCO3 and CO2 in mud As:

IF PH =12.0 or higher ======= Mud contaminate with OH group

PH =10.0 ======= Mud contaminate with OH & CO3

PH =9.0 – 10.0 ======= Mud contaminate with CO3 group only

PH =9.3 - 8.3 ======= Mud contaminate with CO3 & HCO3

PH =8.3 – 6.0 ======= Mud contaminate with HCO3 only

PH = 6.0 – 4.3 ======= Mud contaminate with HCO3 & CO2

PH = 4.3 or lower ======= Mud contaminate with CO2 only.

NB: Using PhPh indicator to test PH value As follows:

No color ========= PH less than 8.3 Light pink color ==== PH 7.5==8.5 Pink color ======= PH 9.0 =10.0 Violet color ======= PH more than 10.0

NB: PhPh end point is at PH = 8.3

ALKALINITY OF MUD TEST : (Pm )

Prepare 1 ml of mud + 5 ml distilled water + 3 drop PhPh (red pink color) Titrate with H2SO4 acid (N/50)===== end point == colorless indication Pm = Volume of H2SO4 used.

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ALKALINITY OF FILTRATE : ( Pf & Mf test)

Prepare 1 ml of filtrate + 2 drop PhPh (red pink color) Titrate with H2SO4 acid (N/50)===== end point == colorless indication Pf = Volume of H2SO4 used Add 2 drops of methyl orange indicator (yellowish orange color) Continue titrate with H2SO4 (N/50)===end point ==pale red color Mf = total volume of H2SO4 used.

RELATION BETWEEN Pf & Mf:

1. If Mf = Pf or little higher : That means mud contaminate with OH ions only Expected to get Ca++ ions contaminate in mud , whenever no CO3 group to precipitate Ca++.

2. If Mf less than twice of Pf: Most of ions CO3 and OH.

3. If MF = TWICE Pf: Most of ions are CO3 High pH related to CO3 not OH which may causes a problem in lignosulphonate mud Leads no response for rheological properties.

4. If Mf higher than twice of Pf: Most of ions are CO3 and HCO3.

5. If Pf = 0 and Mf very high: Most of ions are HCO3 only.

NB: Mf is a matter of measuring CO3, HCO3 & CO2 Pf is a matter of measuring CO3 & OH group. Pf end point is at PH = 8.3 Mf end point is at PH = 4.3 Example:

If PH = 9.0 Pf = 0.8 Mf = 1.6

That means high consumption of H+ ions of H2SO4 acid, take the same quantity of Pf to utilize the filtrate to reach PH = 4.3, So all alkalinity in Pf was from CO3 group.

Total carbonate = 1220 (Mf – Pf ) Treatment of carbonate contaminate in mud depending on total carbonate value (Mf & Pf ) and type of

carbonate . Carbonate contamination treated by adding Lime, or Lime +NaOH or Lime +Gypsum Carbonate contamination treated as follows:

- HCO3 value X 0.00021 == PPB of Lime (treatment value)- CO3 value X 0.00043 == PPB of Lime- HCO3 value X 0.002 ==== PPB of NaOH- CO3 value X 0.001==== PPB of Gypsum

Rule of thumb:

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CO2 AND H2S are acidic gases At high PH you have free OH ions in mud At high PH we minimize bacterial degradation Don’t treat carbonate to zero so as to have some carbonate to react w/ excess Ca ions in mud Accepted carbonate in mud is between 500 – 2000 mg/l A solids problem may look like a CO3 problem. In case of CO2 treat with lime C<2O + Ca<2OH =(CaCO3 + H2O In lime mud the influx of CO2& H2S, which are acidic gases gives incorrect Pm/Pf ratio Solubility of Ca increase with low pH, causing flocculation of mud Clay or shale becomes highly sensitive to mud in highly pH over 9.0, causing flocculation of mud as the

attraction forces between ions increases Mf value sometimes tend to be higher than actual (false value),this is because some chemicals added to mud(such as ,lignosulphonates , unical , resinex), buffer the pH of the fluid (fix it) ,so it takes more amount of H2SO4 to reach pH 4.3. High pH more than 11.0 may deactivate some polymers, best media pH is between 8.5(10.0. Low pH less than 7.0 causes breakdown (burn) of polymers Ligosulphonate becomes less affective and may cause sever foaming at pH below 8.0,so add caustic Soda to adjust PH In lime mud or excess lime Pm becomes higher than Pf as lime increases. To adjust Pm/Pf ratio add lime or caustic soda .

Contaminants : Na Cl : Source :1. salt domes .2. rock salt beds .3. evaporite formations .4. salt H2O flow .5. salty make up water.Effects :1. Increase apparent viscosity .

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2. Increase yield point .3. Decrease pH .4. Cl- ion will increase in filtration and will decrease Pf .5. Flocculation followed by aggregation of mud .6. Wash of hole .7. Chemical foam .Treatment :1. Dilution .2. Add thinner to reduce apparent viscosity, YP, Gel strength .3. Add caustic soda (Na OH) to increase and adjust pH .4. Add organic thinner to reduce filtration .5. Analyze salty make up water before adding to system otherwise it will act as if we get a salt water flow .6. To make sure that there is no increase in mud weight .7. To convert to salt saturated mud .8. Any treatment should be done as soon as possible otherwise getting a hole wash or untreated mud may cause loose control which

might result in moving in salt body into hole getting a pipe stuck .9. In case of foams, add defoamer (aluminum stearate defoamer) .

Ca SO 4 :Source :1. Gypsum (Ca SO4 2H2O)2. Anhydrite (Ca SO4 ) .3. Cap rock of a salt dome .4. Make up water .Effects :1. Cause flocculation and aggregation .2. Increase apparent viscosity .3. Increase YP & gel strength .4. Increase filtrate .5. Increase Ca++ ion in mud which cause flocculation . also increase SO4

—content in filtrate which increase hardness .6. Increase thickening of mud .Treatment :1. Add soda ash (Na CO3)with low pH or Anhydrox (Ba CO3) or Na HCO3 with high pH .

Na2 CO3 + Ca SO4 = Ca CO3 +Na2 SO4 .2. Add thinner to reduce viscosity and gel strength .3. Work on thickening and filtration by adding either CMC , Lignosulfonate . 4. If large amounts of soda ash is added , the soluble sodium sulfate tends to build up and cause (ash gels)which are indicated by

High Progressive Gel Strength . Also if HI pH is maintained this too may result in ash gels due to formation of Na2 SO4 . So it is required to

a. dilute with H2O .b. add lime for alkalinity .

5. Prepare pretreated mud with Q-broxine and caustic soda .6. Convert to gypsum mud so as Ca SO4 will have no effect on mud

Ca (OH) 2 Cement :Contamination occurs during :1. Cement squeeze operation .2. Poor casing cement job .3. Drilling out cement .4. Wet (green) cement has a greater contamination effect than hard cement because of increased solubility .NB : (Salinity + gas + oil) prevent cement to get hard. (weak cement job) .Effects :1. Increase apparent viscosity .2. Increase YP & gel strength.3. Increase pH .4. Increase filtrate .5. Increase Pf and hardness content of filtrate .

Treatment :

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1. Reduce pH by adding sodium bicarbonate , this Na HCO3 will also treat the thickness of mud . Caused from the presence of Ca+

+ ions and retain the dispersed – defllocculated condition of mud . NB : 100 lb. Of bicarbonate of soda / 2 cubic feet of hard cement . 100 lb. Of bicarbonate of soda / 1 cubic feet of soft cement . This is done to prevent flocculation of clays .1. If contamination is slight , Barafos is sometimes used as it will remove calcium ion and reduce pH .NB : Be careful of bottom hole temperature .2. Add organic thinner with little or no caustic soda to reduce the thickening of contaminated mud . Other Divalent ions :Source :EG : a- Magnesium chloride . b- Calcium chloride . c- Magnesium sulfate .1. In formation water2. Sea water .3. Evaporate formation . Mg++ ion acts like Ca++ ion contamination .NB : The magnesium can be precipitated from solution as magnesium hydroxide (Mg (OH)2) at a pH above 10 .

H 2S Gas :Source :1. In formation fluids as a result of bacterial action or from sulfur compounds commonly found in the drilling fluid .2. Thermal degradation of sulfur containing drilling fluid additives .(EG: Lignosulfonate) .3. Chemical reaction with tool joint thread lubricants that contain sulfur . Effects :1. Toxic gas .2. Corrosion of drill string .3. Decrease pH .4. H2S 2H+ + S-

H+ acidic ion cause corrosion , react with OH- ion in mud causing dehydration of mud and thus flocculation of bentonite and by turn decrease pH and get polymer back to its acidic form and thus do not work .S- cause flocculation of mud and might react with any H+ ion left to give back H2S .Treatment :

1. Add caustic soda to keep pH above 10.5 .2. Add zinc oxide , zinc carbonate

Zn O + H2S = ZnS + H2O .3. Add lime .

Lime is reported as lb. /bbl and not ppm . Multiply lb./bbl lime tests constant to get lb./bbl treating agent needed . At pH 10.5 all but 50 ppm of magnesium has been reacted . Zinc oxide has less effect on rheological properties in non dispersed systems . CO2 flocculate mud in case of bentonite mud as it will take OH- ion to give HCO3, also decrease pH . To get rid of CO2 add lime Ca(OH)2 = Ca++ + 2OH- .

HCO3 + OH- = H2O + CO3 . Ca++ + CO3

-- = CaCO3 .

Chemicals Required to Remove Ionic Contaminations

Contaminant Treating Chemical (Mg/L) X Factor = (lb./bbl)

Ca X 0.00093 = Na2CO3 (soda ash)Ca X 0.00074 = NaHCO3(Bicarb.)Ca X 0.00097 = Na2H2P2O7 (SAAP)Mg X 0.00093 = Na2CO3 (soda ash)

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Mg X 0.00116 = NaOH CO3 X 0.00043 = Ca(OH)2 (Lime)CO3 X 0.001 = CaSO42H2O (Gyps)HCO3 X 0.00021 = Ca(OH)2

HCO3 X 0.002 = NaOHPO4 X 0.00041 = Ca(OH)2

Example:Titration of the filtrate shows a calcium level of 650 mg/L. to remove all but approximately 100 mg/L, treat 550mg/L (650- 100 = 550) of calcium with soda ash.Therefor, soda ash required is approximately 550 X 0.00093 = 0.51 lb./bblthe higher the salinity the lower the pH, the higher the Ca contamination.Ca can be

CHEMICAL TREATMENT GUIDE

Contaminationion

To remove add to water base mud Amount to add (lb./bbl) to remove 1 PPM contaminated ion

Gypsum or

Anhydrite

Calcium(Ca++)

Soda ash to hold pH or raise it.SAPP to hold pH or reduce it

Sodium bicarbonate to hold pH or reduce it.

0.000927 lb./bbl0.000971 lb./bbl0.000735 lb./bbl

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cementCalcium

Ca++SAPP

Sodium bicarbonate0.000971 lb./bbl0.000735 lb./bbl

LimeCalcium (Ca+

+)Lime

(Ca++, OH-)

Sodium bicarbonate

SAPPSodium bicarbonate

0.000735 lb./bbl

1.5 lb./bbl1.135 lb./bbl

Hard water

Magnesium(Mg++)calcium(Ca++)

First: Caustic soda to pH 10.5

Second: Soda ash

0.00116 lb./bbl

0.000928 lb./bbl

Hydrogen sulfide

Sulfide(S-)

Keep pH above 10.5. add basic zinc oxide,

zinc carbonate or lime

0.00123 lb./bbl

0.00805 lb./bbl

Carbon dioxide(CO2)

Carbonate(CO3

--)bicarbonate

(HCO3-)

Gyp to hold or reduce pHLime to raise pHLime to raise pH

0.001 lb./bbl0.000432 lb./bbl0.000432 lb./bbl

NOTE: Lime is reported as lb./bbl and not PPM. Multiply lb./bbl lime tests constant to get lb./bbl treating

agent needed. At pH of 10.5 all but 50 PPM of magnesium has been reacted Zinc oxide has less effect on rheological properties in non-dispersed systems. CO2 flocculate mud in case of bentonite mud as it will take OH- to give HCO3, also decrease pH.

To get rid of CO2 add lime Ca(OH)2. Ca+2 + 2 OH-

HCO3 + OH- = H2O + CO3

Ca+2 + CO3-- = CaCO3

TROUBLE SHOOTING GUIDE

Problems Barite Viscosity MBT Low DensitySolids

Calcium Content Treatment

Weight

Weight too low

Normal NormalNormal or high Normal

Normal Add barite.

_

Low High High High Normal Dilute, add barite, XC polymer and polyac. _

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Weight too high

Normal Normal Normal High Normal Dilute w/ H2O, add prehydrated bentonite +XC polymer if needed to maintain viscosity. _

Low-Normal

Normal- high

Normal-high

High Normal Dilute w/ H2O, add XC polymer & polyac.

_

Viscosity too low

Normal_ Low

Normal Normal Add prehydrated bentonite + XC polymerNormal

Normal

_

Normal Normal Normal MBT may be due drilled solids-so dilute or remove solids, Add prehydrated bentonite + XC polymerNormal

Viscosity too high

Normal _

High Normal Normal Dilute or remove solids, add XC polymer & polyac.Normal

Normal_

Normal Normal Normal Insufficient amount of XC polymer + barite. Add both.

Normal

Normal

_

Normal Normal HighHigh pH

Before drilling cement, pre treat w/ sodium bicarbonate rather than soda ash. Use soda ash only w/ normal drilling.

Normal

High temp.High press.

Normal Normal Low Normal Normal Add prehydrated bentonite + XC polymer & polyac.

Normal

Fluid loss too high

Normal

Normal-high

Normal Normal High Remove C++ by sodium bicarbonate rather than soda ash.

Normal

Normal Normal Normal Normal Normal Add 100-150 PPM Ca to suppress the yield of bent. This well allow more bent. to be added to the mud for better particle size distribution without excessive viscosity.

Normal

NB: Gel PV, to break down gel, dilute (fresh water + caustic soda + spersene. Replace mud. The addition of water should be slow.

CHEMICAL TEST (WBM)

Salinity: CL : 1ml of filtrate + ph.ph if pink add 0.02 H2SO4 colorless.1 ml of filtrate + 5-10 drops potassium chromate (yellow) # Ag NO3 (end point orange red ppt).

CL = volume of Ag NO3 X 10000 . KCL :

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6 ml of filtrate + 3 ml sodium perchlorate (centrifuge) ppt of potassium perchlorate, ml ppt with standard curve.

Hardness:

* Ca ++

1ml of filtrate + 10 drops of Na OH(1N) + Caliver 2 indicator pink.# EDTA end point violet color.Volume of EDTA X 400 = Ca++, Let volume of EDTA = A.

* Mg ++

1 ml of filtrate + 2-5 drops Buffer solution (Ammonia) + Erichrom black indicator (pink). # EDTA end point sky blue. Let volume of EDTA = BMg++ = (B-A) X 243.2

Alkalinity of Mud:

* Pm:

1 ml of mud + 5 ml distilled water + 3 drops ph.ph (Red – Pink).# H2SO4 (N 50) end point colorless.Pm = volume of H2SO4.

Alkalinity of Filtrate: Pf :1 ml of filtrate + 2 drops of ph.ph (pink).# H2SO4 (N 50) end pint colorless Mf: Add 2 drops of Methyl orange (yellow orange). # H2SO4 (N 50) end pint pale red.NB: Very Important:1. To increase pH add caustic soda.2. To decrease pH add dilution.3. To treat flocculation dilution + thinners.4. To treat foams add defoamer.5. To treat viscosity dilution + thinners.6. To treat water loss add filtration control agents.7. To treat Ca++ add soda ash.8. To treat Mg++ add Ca CO3.9. To treat CO3, HCO3, PO4 add lime.

To Measure PV , YP and Gel Strength: B mean of apparatus of Rheology (viscometer):1. Fill cup with mud.2. Fit agitator.3. Adjust apparatus to 600 RPM and then allow agitation. Take reading on gauge.4. Adjust apparatus to 300 RPM and then allow agitation. Take reading on gauge.5. PV = Reading 600 – Reading 300.6. YP = Reading 300 – PV.7. Adjust apparatus to 600 RPM again and then allow agitation for few minutes.

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8. Then adjust apparatus to 3 RPM. Put on , after waiting for 10 sec. Take maximum reading to be first reading for gel.

9. Then adjust apparatus again to 600 RPM , allow agitation for few minutes.10. Wait this time 10 minutes.11. Then adjust to 3 RPM, allow agitation and take maximum reading to be second reading for gel strength. To Measure Water Loss and Filter Cake: By mean of apparatus:1. Fit bottom end of cell to cell after putting a filter paper covered by a rubber o-seal.2. Fit cell with mud enough for half an hour.3. Fit cell in place over a graduated cylinder.4. Fit top part of apparatus.5. Apply pressure 100 psi.6. Mud starts loosing water collected in graduated cylinder.7. If taking reading after 7 ½ minutes multiply by 2.8. If not continue ½ an hour you will get the same reading.9. Take filter paper out. Clean filter paper from all above cake, measure cake.NB: Relation between water loss and cake:

Water loss (ml) Cake (cake/32)Above 20 3-4F/8 T/ 20 2Less than 8 12-3 1/2

To Measure Solids and Oil %: By mean of apparatus:1. Fill cell with mud.2. Put in barrel.3. Fit all together.4. Place a graduated cylinder under cell.5. Apply heat.6. All fluids will evaporite and condense to be collected in cylinder.7. When finish, the cylinder will still having an empty part which will be corresponding to solids in mud by %

reading remaining empty to filled part.8. Also read part containing oil to be oil percent %.

Test MBT:1. Add 2 ml of mud + 8 ml of deionized H2O + 15 ml of 3 % hydrogen peroxide + 0.5 ml of sulfuric acid.2. Boil gently for 10 min.3. Dilute to about 50 ml with distilled water.4. Add Methylene blue solution about 0.5 ml and steer for about 30 sec.5. While the solids are still suspended, remove one drop of liquid and place on a filter paper.6. The end point is reached when the dye appears as a blue ring surrounding the dyed solids.7. Shake or steer for two minutes and place another drop on the filter paper. If the blue ring is again evident,

the end point is reached. If not, continue as before until a drop taken after shaking two minutes shows the blue dye.

ML of Methylene blue 8. Methylene blue capacity = . ML of mud9. Where :Bentonite equivalent (lb./bbl mud) = 5 X Methylene blue capacity.

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(Kg/m3 mud) = 14.25 X Methylene blue capacity. NB: drilling mud frequently contains substances in addition to bentonite that adsorb Methylene blue, treatment with hydrogen peroxide is intended to remove the effect of organic materials such as CMC, Polyacrylates,Lignosulfonate and Lignite.

SHALE FACTOR:

Clay types have different cation exchange capacities (CEC) and consequently different adsorption capacities.It was also shown that Na montmorillonite clay will undergo diagensis to illite with the increasing of temperature by the ionic exchange of K ions instead of Na ionsIn order for diagenesis to proceed, water must be flushed out from clays.If exchange cations K are not available to exchange Na montimorillonite clay will lose its water, but will not convert to illite thus if this type of clay is drilled with a water-based mud, the clay will hydrate and causes drilling problems.The cation exchange capacity (CEC) will decrease as clays convert from montimorillonite type (with temperature and thus with depth and pressure).Pure montimorillonite clays show a CEC of 100 meq\100gm.Pure illites (shows no swelling characteristics) have a CEC generally between 10&40 meq\100gm.Kaolinites have a CEC of approximately 10 meq\100gm.In general bentonite and montimorillonite have an affinity for water.NB, the clay /shale zones will have an affinity for water in an amount proportional to the montimorillonite content.

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PORE PRESSURE:There Some Factors That Affects The Estimated Pore Pressure:1. Mud weight and background gas relationship.2. Gas cut mud.3. Cutting character.4. Hole condition.5. Temperature.6. Dex.

1. Mud weight / background gas: When the pumping stops , the hydrostatic pressure could be below the formation pressure. When connection gas occurs , that means we lost the ECD margin. It is normal to drill with normal mud weight and having formation gas coming out (FBG).NB: The gas coming out depend on porosity, permeability, gas saturation and P.

P = (W X D X 0.0519) – (FBG X D 0.0519).

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W = mud weight .D = depth.

P should be positive while drilling.If P is negative a continuos influx occur showing by high background gas and gas cut mud while circulation.C.G.Trip Gas. Must be taken in our consideration.Formation Type.

2. Gas Cut Mud:In shallow wells great problem.In deep wells could be with no problem

Gv = { (d/2H) X (3.14 ROP/60) X X Sg } X 7.48Gv = gas rate. d= hole diameter. Sg = gas saturation.Gas @ atmospheric pressure = 14. 7 psi.Gva = Gv X (P/14.7). Mud flow (GPM)W1 = X W2(uncut mud). Mud(GPM)+ Gas (GPM)

W1 –W2 3.53 X W2 X DPressure reduction( P) = 14.7 In W1 1000D = depth of gas zone.

3. Cutting Characters (Cavings) (Cvg):The more the caving the more unsuitability of the well which indicate that hole is under balance.4. Hole Condition: If the following conditions occur: Caving occur. Over pull and drag while tripping. Torque while drilling. Connection gas and trip gas increases. Pit level is increasing (I.E formation fluids are coming out to well).This indicates that ECD margin is balance or below the formation pressure and we are taking or about to take a kick.NB: Watch ROP it will increase and P.P. also will increase.NB: Over pull could occur because of :a. Over pressured zone which cause swelling .b. Swelling of shale due to absorption of water.c. Due to ledges or dog legs.This could be solved by increasing the mud weight. Or by jarring, or by back reaming, or by an acid job (in case of carbonates), or by pumping fresh water in case of salt.5. Shale Density: Under normal conditions shale density increases with depth.N.B: Any accessories will cause increase in shale density (I.E silty, pyritic, calc content …. Etc.).If shale density decreases while increasing of depth, this indicates high pore pressure zone.6. Temperature: Increases with depth.

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NB: Any sudden drop in temperature is an indication of a pressure zone. This drop in temperature at or before pressure zone. TYPICAL DENSITIES

Type Matrix DensityS.S 2.65L.S 2.71DOLO 2.87ANHY 2.98SALT 2.03GYPSUM 2.35CLAY 2.7 – 2.8FRESH H2O 1SALTY H2O 1.15OIL 0.8

7. D Exponent:It is affected by RPM, tooth effect, drilling hydraulics (P.P, pump flow, nozzles and mud rheology) matrix stress and formation compaction.The DXC a correlation of drilling parameters with ROP in shales

Soft formation (porous & permeable) Hard formation (compact) Trend

PORE PRESSURE TRANSMISSION:

As well known that shale rock have no permeability, but shale as beds has a sort of unextended cracks which acts as secondary permeability.As a rule of thumb the hydrostatic pressure of mud column acts against the formation to control the formation pressure.But by time part of the hydrostatic pressure migrate into the formation through its pores (degree of migration depends on porosity &permeability of the rock ).(The filter cake acts to prevent this transmission of pressure into formation , offcoarse if this filter cake is a good rigid impermeable cake).In case of shale and as there is no possibility of formation of filter cake the shales is directly exposed to hole and thus to hydrostatic head of mud. So this transmission is possible through its cake if present.By time this transmitted pressure will accumulate inside the shale rock and acts as a formation pressure in a reverse way against the hydrostatic mud column together with original formation pressure.If the summation of both formation and transmitted pressures exceeds the hydrostatic mud column or ECD the formation will acts as over pressurized zone, and caving occurs together with other bore hole problems as mentioned in pressure control section and shale bore hole problems section. FORMATION PRESSURE :

All sedimentary rocks are porous to some degree. These void spaces within a rock grains are filled with fluids (liquid or gas or combination of both). These fluids within pore spaces exhibit a sort of pressure known as PORE PRESSURE.

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Pore pressures are equivalent to the average hydrostatic pressure exerted by the fluid contained in the pore spaces from water table (on shore) and sea level (off shore).

PORE PRESSURE GRADIENT :

Is the pressure per unit depth , which is refereed to water table on shore and sea level off shore(pressure gradient =0.0519*ppg).

EG: off shoreDepth = 1000 ft Sea water density = 8.6 ppgDistance between RKB to sea level =60 ftActual pore pressure gradient = (1000 – 60) * 0.0519 * 8.6 = (420 psi) (0.446 psi/ft)EG : on shoreDepth = 1000 ft Water density = 8.34 ppgDepth of water table = (220 ft (from RKB ) Air gap = 30 ft (between RKB & surface)Actual pore pressure gradient = (1000 – 220) * 8.34 * 0.0519 = (338 psi) (0.433 psi/ft)NB : Actual pore pressure =depth(from sea level or water table) * pore water density(ppg) *0.0519But while drilling pore pressure is referenced to the flow line not to water table(on shore) or sea level(off shore). Thereby due to the difference in height between flow line and the water table(on shore) and flow line and sea level(off shore), so the measured gradients during drilling will not be the actual pore pressure gradients , but will represent the hydrostatic pressure of the drilling fluid required to balance the formation pressure at the depth from the flow line. This can be termed as NORMAL FORMATION BALANCE GRADIENT .From EG 1 : If the distance from RKB to flow line = 5 ftCalculated pore pressure gradient form flow line (hydrostatic pressure of drilling fluid required to balance the formation pressure at 1000 ft from flow line ) = 420 / [ (1000-5) * 0.0519 ] =8.07 PPG (0.419 psi / ft ).From EG 2 : Calculated pore pressure gradient from flow line = 338 / (995 * 0.0519 ) =6.5 PPG (0.338 psi /ft ).PS : Apply on greater depth of 3000 ft2 For EG 1 : Actual pore pressure gradient = ( 300 – 60 ) * 0.0519 * 8.6 = 1312 psi (0.446 psi / ft )pore pressure gradient from flow line=1312 /[ ( 3000-5 ) * 0.0519 ] =8.44PPG (0.438 psi /ft )For EG 2 :Actual pore pressure gradient = (300-220) * 0.0519 * 8.34 =1203psi (0.433psi/ft)pore pressure gradient from flow line=1203 / (2995 * 0..0519) =7.74PPG (0.402psi/ft)Apply on greater depth 10000 ft .For EG 1 :Actual pore pressure gradient = (10000-6) * 0.0519 * 8.6 =4437 (0.446psi / ft)Pore pressure gradient from flow line=4437/[ (10000-5) * 0.0519 ] =8.55PPG (0.444 psi/ft)For EG 2 :Actual pore pressure gradient =(10000-220) * 0.0519 * 8.34 =4302 (0.433 psi/ft).Pore pressure gradient from flow line=4302 / (9780 * 0.0519) = 8.48PPG (044 psi/ft) .Its apparent that with depth increase the normal FBG will approach the actual pore pressure.But at shallow depths the differences between actual pore pressure and normal FBG are extremely remarkable .Since there no water – base mud dose have a density of 6.5 or 8.1 PPG . So drilling with the least available water – base mud densities (8.6 –8.8PPG) in shallow holes will approach or exceeds the fracture pressure of the formations resulting lost circulation and no returns .Since the pore pressure is not constant from surface all the way down bore hole , but actually increases with increase of depth.The gradient as measured from the flow line is termed FORMATION BALANCE GRADIENT (FBG) and this is precisely equal to static equivalent mud density (Eq M wt ) required in the bore hole to balance formation pore pressure.(so the terms may be used interchangeably).

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FBG is always less than pore pressure gradient . PS :Formation pressure = pressure on the standpipe gauge (after stopping circulation and closing chock) +hydrostatic pressure of mud column in the drill pipe (as mud inside drill pipe will be normally not contaminated).Formation pressure = SIDP +(M wt * TVD * 0.0519) .Controlling the formation pressure is one of the primary functions of drilling fluids that is mainly controlled by the hydrostatic pressure exerted by the fluid column in the annulus ,whenever the formation pressure exceeds the total hydrostatic pressure of the drilling fluid ,the formation fluids will invade the well bore causing a kick .

OVERBURDEN PRESSURE :

Overburden is that pressure resulting from the combination between those pressures resulting from overburden weight of the rock grins and pore pressure resulting from fluid content in pore spaces. Po =Pf +Pc Where Po = overburden pressure gradient (psi/ft) Pf = fluid pressure gradient (psi/ft) Pc = rock grains pressure gradient (psi/ft)EG : Rock grain density = 2.6 gm/cm3 Pore fluid density =1.07 gm/cm3 Porosity =34% 2.65 * (66/100) = 1.75 gm/cm3 1.07* (34/100) = 0.36 gm/cm3Average overburden density of this rock =1.75+0.36 =2.11gm/cm3 =2.11*8.34*0.519 =0.92 psi/ftNormal overburden pressure varies from approximately 0.84 psi/ft near the surface to 1.0 psi/ft @20000 ft.

NORMAL FORMATION PRESSURE :

When a formation is deposited , the formation keeps some fluids in its pores (mostly water) until being exposed to another overlying sedimentation which exerts a sort of compression pressure on underlying sediments causing escape of some underlying formation fluids due to that compression force on its pore spaces , the amount of escaped fluids depends on degree of compaction of rock(resulting from above compression force) also its permeability.If the amount of escaped fluids off formation are equivalent to overburden pressure and the depth , also corresponding to equivalent temperature and pressure at that depth. So the formation keeps a normal pressure . Normal Formation Pressures :# Marine basins = 0.465 psi/ft =9.0 PPG with salinity of 80000 mg / l CL.#Island areas = 0.433 psi/ft = 8.34 PPG .

ABNORMAL FORMATION PRESSURES :

When fluids are sealed within a formation (due to impermeability ) and unable to escape ,they then support apart of the weight of the overburden . As the depth increase the overburden load increases and accordingly the formation pressure increases . Also increase of temperature will lead to abnormal pressure. Causes For Abnormal Pressure :1- Rapid sedimentation rates accompanied by thick and low – permeability shale sections.2- Tectonic activities such as salt intrusions and anticline folds.3- Diagenetic alterations such as conversion of anhydrite to gypsum . The resulting volume increase could generate substantial

pressure increase within a sealed zone.4- Formations that have been charged with water from surroundings, and this water was captured inside the formations.

How to Recognize Abnormal Pressure Zones :Abnormal pressure zones are usually accompanied by under compacted shales. This change in shale characteristics generally results in :1- Increase in normal porosity.2- Increase in formation fluid content and change in formation density.3- Increase in shale conductivity. METHODS OF FORMATION PRESSURE PREDICTION :

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1- Seismic data the area to be drilled :

Since the abnormally pressured zones have not compacted normally with depth and hence its porosity is high ,together with presence of high content of gas or fluid occupied within its pore spaces, so the velocity of sound waves traveling through these formations is reduced .I.e.: very high adsorptive function to sound waves ends thus very low reflective function to sound waves traveling through it. This method is highly useful in detecting shallow gas sands, but more difficult to detect deeper gas.(need to have more geologic information about area from nearby offset wells).

2- Electric log analysis:

a- Conductivity Logs :

Abnormally pressured zones can be predicted by analyzing changes in shales conductivity recorded on conduction logs.This is done by taking several points of shale conductivity Vs depth. Then draw the best straight line of shale conductivity. Any shift from that line indicates an abnormal pressure zone .Then calculate the ratio of shale conductivity observed to the normal conductivity of that shale, that was suppose to fall on guide line if normal situation Like that we can indicate the equivalent formation pressure and thus the equivalent fluid density to drill with. This varies from one area to another.EG : At depth 13000ft Observed shale conductivity = 1670 Normal shale conductivity = 630So the ratio of observed conductivity =1670 /630 = 2.65 DIGRAM This 2.65 is corresponding to a formation pressure of :16.1 PPG in South Louisiana 12.9 PPG in Texas GULF Coast 12.1PPG in North Sea 13.5 PPG in South China Sea

TABLE

B- Sonic Logs :Sonic logs measure transit time of sound for a fixed distance through formations(the same as the seismic logs information). Interval transit time (micro seconds per foot) decreases as the formation porosity decrease because a density material transmits sound waves at a higher velocity than a less dense material.Porosity generally decreases at near linear rate as a function of depth in normally compacted shales.A plot of shale travel time is normally near a straight line with graduated reduction in travel time as a function of depth .Increased shale porosity (which usually indicates a change in compaction and abnormal pressure)would produce an increase in shale travel time.Plot a graph of shale transit time versus depth, any shift from normal compaction trend of shale indicates abnormal pressure zone .EG : At depth 13000 ft Observed transit time = 130 (micro sec/ft) Normal transit time = 95 (micro sec/ft) Difference = 35 (micro sec/ft)Which is equivalent to a pore pressure of 15.8 PPG U.S Gulf Coast14.75PPG South Texas Gulf Coast14.25PPG West Texas13.15PPG North Sea13.6 PPG South China Sea

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DIAGRAM & TABLE

SOME SUGGESTIONS FOR SELECTING THE SHALE DATA PIONTS POINTS TO BE USED IN FORMATION PRESSURE PREDICTION ARE :

1- Select clean shales in intervals of low spontaneous potential (SP) deflection and uniform conductivity or sonic readings2- Shales selected for data points should be at least 20 ft thick with points obtained from the center of the section if possible 3- Shales stringers within massive sand sections tend to exhibit high unreliable readings 4- Avoid shale readings immediately above known gas sand. These readings will characteristically display high unreliable values 5- If available, the caliper survey should be scanned for excessive hole enlargement, excessive enlargement can create a skip in

signal on sonic logs and lead to erroneous data .6- Avoid plotting silty or limey shales by inspecting the SP curve. Minimum SP values will result in more reliable data . DRILLING PARAMETERS USED TO INDICATE AN ABNORMAL PRESSURE ZONE :

1- RATE OF PENETRATION : The increase of ROP indicates abnormal pressure zone . A rule of thumb is that a uniform decrease in ROP of shales normally occurs with depth. This decrease in ROP results from the increase of compaction and density of the shales. To understand the action during drilling , when a bits tooth penetrates hard formation it forms a cone of crushed rock immediately beneath the tooth. The formation of cracks alone will not make a hole, so the cuttings must be removed as they are formed. The most effective force for the removal of cuttings is high velocity jetting by the bit. (PS : In plastic formations the material will be gauged rather than crushed).The ease with which cuttings are removed (and hence picking up ROP )depends upon the differential pressure across bottom.Differential pressure = is the difference between bottom hole circulating pressure (ECD) formation pore pressure (or formation balance gradient FBG ) If circulating pressure is much larger than formation pressure (overbalance) cuttings will be held down against bottom by the excess differential pressure . As the overbalance is decreased , these effects are reduced , cuttings will be removed easily and ROP will increase . In drilling overpressured zone the formation pressure is sufficiently exceeding the circulating pressure (underbalance) ,the mud filter cake ceases to form, and the cuttings are forced away from the formation , and thus increase in ROP occurs .PS : It can be seen that the ROP can be controlled by differential pressure alone.In most drilling situations it is desirable to maintain the mud density slightly higher than FBG (formation pressure PPG).The resulting differential pressure can be calculated as follows = (W * D * 0.0519 ) – ( FBG * D * 0.0519 ) = Pwhere W = mud density PPG D = depth ft FBG = formation pressure gradient PPG P = differential pressure NB 1:Substituting ECD for W gives differential pressure while drilling .NB 2 :P should be positive during all drilling operations.NB 3 :If FBG > hydrostatic pressure , influx occurs . Generally we can not count on ROP only as there are other parameters affects the ROP such as:A – Lithology changes B – Bit weight C- Bit typeD –Bit condition E – Rotary speed F –Drilling fluid propertiesG –Hydraulics (bottom hole cleaning)

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2 - VARINACE IN SHAPE AND SIZE OF SHALE CUTTINGS : Shale cuttings from an abnormally pressured zone are larger than those from a normally pressure zone. They are characterized by sharp and angular edges and needle like shape , while normal pressured cuttings are generally small and flat with rounded edges .The variables which determine the size and shape of shale cuttings are :a- Mineralogical , chemical and physical properties .b- Type of drilling fluid .c- Hole geometry .d- Down hole agitation .

3 - CHANGE IN ROTARY TORQUE : During normal drilling operation , rotary torque gradually increase with depth due to the effect of wall contact of the drillstring on the well bore also the action of formation on bit rotation Any abrupt changes from this trend indicates :(a twist of in the drill string , a locked cone on the bit , a wash out in the drill string , a change in formation pressure)Increase of pre pressure causes larger amount shale cuttings to come into the well bore ,and the bit teeth will take larger bites into the formation.The increased amount of shale tends to stick or impede bit rotation.Rotary torque can not be an indicator for abnormal zones in deviated holes.

4 – CHANGE IN DRAG AND OVERPULL : When drilling in a balanced or near balanced situation, an increase in drag and over pull can occur while making a connection in abnormally pressured zone.This increase in over pull and drag is due to :a- Plastic nature of some pressured shales, which may cause close of shale around the drillcollars and bit.b- Swelling action of shalec- Extra pressured shale cuttings which enter the well pore when keeping abnormal pressure.

5 - SHALE DENSITY : Shales which are normally pressured have undergone normal compaction and thus densities increase uniformly with depth, this uniform increase allows shale density to be predicted.Any significant reduction in shale density (due to improper compaction and occupying of more fluids than usual) indicates an overpressured zone.

6 - INCREASE IN CHLORIDE IONS IN MUD ABOVE 10,000 mg/l : 7 - DECREASE OF FLOWLINE TEMPERATURE : A normal trend for flow line temperature should be plotted or recorded .Any significant decrease in flow line temperature (6F or above)indicates overpressured zone. But still this parameter has to be compared with some other parameters be positive of presence of an overpressured zone .

8- GAS CONTENT OF DRILLING FLUID :Increase of gas content of drilling fluid was recommended an indicator for detecting abnormal pressured zones.Since the gas cutting is not always a result of an underbalance condition, so correct interpretation of gas cutting trends is recommended .Also a trend for background gas and connection gas is recommended . So as when having any abnormal significant increase in gas it can be referred to presence of an abnormal pressured zone .# Gas may be entrained in mud column as a result of the following conditions :a - When a formation containing gas is drilled, and while circulating cuttings containing gas up the hole , gas in these drilled particles expanded and released to the drilling fluid system causing cut in the mud weight .in such cases , increasing M.wt will not stop the gas cutting. This condition can be verified by reducing drilling rate or by stopping drilling and circulating bottoms up.b- While drilling a pressured formation the differential pressure between the ECD and formation pressure is reduced to be very close.I.e. : ECD is very slightly higher than formation.But when stopping circulation the static hydrostatic fluid column pressure is nearly equal or even less than formation .So on making a connection or trip the piston effect of upward pipe movement can swap formation gases and fluids into the well bore causing cut in M.wt especially gas which will expand on circulating up causing gas cut.Ps :If differential pressure increases but from negative side .I.e. formation become > hydrostatic pressure So the influx activity of the formation content bore hole increases and might exceed to cause a kick.# To detect the amount of gas entering the mud system as follows :

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Gv =(d/24) * (#*R/60) *porosity *Sg * 7.48Where Gv = rate of gas entering the mud system at reservoir pressure (gal/min) R = rate of penetration (ft/hr)

d = hole diameter (inch) Sg = gas saturationEG : If d =8.5 porosity = 25% R = 85 Sg = 70% With a reservoir pressure at 15,000ft of 7,000 psi Gv = (8.5/24) (3.14*85/60) * 0.25 * 0.7 * 7.48 = 0.731 GPM @7,000 ftthe gas volume each minute at atmospheric pressure(14.7 psi) using ideal gas low (neglecting temperature effect) is :Gva =Gv *(P/14.7) =0.731 *(7,000/14.7) = 348 GPM @ atmospheric pressurewhen the gas reaches the surface the volume of gas flowing with mud is about 350 GPM.If the normal flow of mud is 280 GPM using a M.wt of 9.2 PPG , the gas mixed with mud at that GPM will result in a mud density of :W1 =[GPM (mud) / GPM (mud) + GPM (gas)] *W2 Where W1 =gas cut mud density PPG W2= uncut mud density PPG W1 =[280 / (280+350)] * 9.2 = 4.1 PPG.NB : Increasing the mud density will not reduce gas cutting as the hydrostatic pressure of 9.2 PPG mud @ 15,000 ft is7162 psi . i.e., 162 psi greater than reservoir pore pressure.The pressure reduction caused by mud cutting : P = 14.7 * [(W2-W1) / W1] * Ln [(3.53*W2*D) / 1,000]P = pressure reduction caused by mud cutting psiW1= gas cut mud density at the flow line PPGW2=uncut mud density PPGD =depth of gas zone ftUsing information from previous example : P =14.7[(9.2-4.1) / 4.1] * Ln[(3.53*9.2*15,000) / 1,000 ] = 113 psiSo the actual mud gradient @ 15,000 ft is :W = [hydrostatic pressure – P ] / D * 0.0519 = [7162 – 113] / 15,000 *0.0519 = 9.0+ ppg PS : The decrease in bottom pressure in deep wells is small as shown in previous example, But in shallow wells it is a major problem . EG : Hole diameter = 12.25” Drilling rate = 500 ft/hr Depth = 1,000 ftFormation has 30 % porosityFormation has 70 % gas saturation.Formation pressure = 467 psi (9 PPG).M.wt = 9.2 PPGPump rate = 450 GPMAmount of gas entering the mud system =(12.25/ 24) *[ (3.14 * 500) / 60 ] * 0.3*0.7*7.48 = 10.7 GPM @ 467 psi.Gas volume each minute at atmospheric pressure = 10.7*[467/14.7]= 340 GPM.The resultant mud density = [450/(450+340)] * 9.2 = 5.2 PPG.

Thus the pressure reduction at 1,000 ft P =14.7*[(9.2-5.2)/5.2] * Ln [(3.53*9.2*1,000)/1,000] = 39 psialthough the pressure reduction appears to small, only 39 psi, but the resultant mud gradient @ 1,000 ft = [9.2*1,000*0.0519]-39 =438 psi [438 / (1000*0.0519)] = 8.4 PPGThe mud gradient is reduced from 9.2 PPG to 8.4 PPG by a reduction of 39 psi @ 1,000 ft.If formation pressure gradient is 9.0 PPG @ 1,000 ft, the well will kick if this situation is permitted to occur.NB : Gas cut mud @ shallow depths may be extremely hazardous as a severe kick and loss of well control can result !These calculations do not take into account the effect of temperature and compressibility has a small effect on gas expansion when compared to effect of pressure .

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But due to difficulty of estimating formation temperature and obtaining realistic values for gas compressibility . The calculation only takes pressure into account.On surface the temperature effect is insignificant .NB1:Circulating gas out without controlling gas expansion causes reduction in annulus hydrostatic column and thus cause disturbance in differential pressure (formation pressure comes to be >hydrostatic pressure ) as pervasively mentioned causing more gas influx into the well bore leading to gas kick .NB 2 :Deferential pressure is one of the major factors that affect the amount of gas that enters the mud Other factors effecting the gas influx are porosity and permeability of the formation and also gas saturation.NB 3 :Negative differential pressure can be shown by increasing background gas .NB 4 :Large cutting can be produced under conditions of very high underbalance from beneath the bit.NB 5 :Negative differential pressure during tripping may result in swabbing , kick and severely gas cut mud upon recirculation.NB 6 : On stopping circulation ,differential pressure small or close to zero can cause connection gases to be produced from gas bearing permeable formations.NB 7 :Connection gases produced from clays are indicative of reasonable high negative differential pressure.

9 - DRILLING EXPONENT : The rate at which a formation can be drilled is controlled by a number of drilling parameters which are :a- Bit size .b- WOB .c- Tooth shape and distribution and tooth efficiency .d- Drilling hydraulics .e- Differential pressure .f- Matrix strength .g- Formation compaction .h- RPM .Since DXC is a function of those drilling parameters . So by mean of plotting a normal trend for DXC of the area.So any deviation from that trend is an indication for abnormal formation.DXC = { Log(R/60N) / Log(12W/1000B) } .Corrected DXC = DXC *[ N. FBG/ECD]R = rate of penetration (ft/hr)N = rotary speed (RPM)B = hole diameterN. FBG =normal formation balance gradient (PPG)ECD = effective circulating density (PPG)W = weight on bit (1,000 lbs.) For metric system :DXC ={Log(R/18.29N) / Log (W/14.88B)} * (N. FBG / ECD)R in m/hrB in cmN in RPM N. FBG and ECD in g/ccW in tones (1,000 kg)

10- PALEO INFORMATION : Abnormally high pore pressured zones are frequently related to certain environmental conditions within a given geologic time period. This depositional environment is marked by presence of certain fossils.

CAUSES OF A KICK :1- Insufficient mud density .2- Swab and surge pressures. When the pipe is tripped from the hole it acts like a piston so swab occurs causing bottom hole pressure reduction.As the pipe moves upward, frictional forces between the pipe, mud and bore hole wall will cause a pressure reduction .

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The maximum effect of this pressure reduction on mud density will be immediately below the bit. The maximum over pull pressure reduction will occur at the bottom of the hole . NB : An open drillstring will allow some fluid to flow through the jets allowing some degree of pressure relief. But if the drillstring has a float or down hole BOP swabbing pressure will be at a maximum . As a rule of thumb , this pressure reduction can be at least the same as the annular pressure loss. Swab values will depend on pipe pulling speeds and hole condition. A safe weight to trip can be determined from the annular pressure losses using :W trip < W- [annular pressure losses psi] / [0.0519*D]Pressure reduction due to swabbing can be serious when drilling geopressured intervals, as the dropping of the BHCP/ECD may cause the will to flow.Large changes in mud density or effective mud density should avoided as these changes cause unexpected in magnitude which may lead to severe hole problems.

The following items act to increase swabbing effect :a- Thick filter cake.b- Bit balling. c- If nozzles are blocked and back pressure value in the drillstring .d- The speed at which pipe is pulled has a great effect on swabbing.e- High gel and viscosity (as both have a large effect on swabbing)NB : If swab does occurs pipe should be run back to bottom and circulation out invaded fluids or gases.Surge pressure when running into the hole (pipe or casing )may be sufficient to overcome the fracture pressure of weak formations , So the pipe run into the hole should be at a speed that produces a surge pressure, below the minimum fracture pressure.This is important to be taken into our consideration any where in the bore hole as pressures are transmitted to the bore hole even when the bit is inside the casing.3- LOW DIFFERANTIAL PRESSURE : The majority of kicks occur when the bit is off bottom while tripping. When the pumps are shut down prior to tripping. There a pressure reduction in the bore hole equals to the annuals pressure loss(annular friction pressure loss) . If the pore pressure is nearly equals the mud hydrostatic pressure or even higher , flow may occurs when circulating stops and may lead to a kick .4- DROP IN LENGTH OF DRILLING FLUID COLUMN IN BORE HOLE : In case of loss circulation with presence of failure to keep the hole full, the fluid level in the hole will drop and thus result in loss in hydrostatic pressure due to decrease in length of drilling fluid column. If not controlled this hydrostatic pressure loss , this may lead to disturbance balancing formation pressure, and thus allowing influx of formation fluids into bore hole.5- RISER EFFECT : The mud density used must be capable of balance the formation pressure. when the marine riser is removed.It is important to determine pressure reduction resulting from removal of riser on running casing job :EG :Water depth = 250 ftAir gap = 45 ft to RKBRKB to flow line = 5 ftSet 30” casing @ 600 ftTotal depth = 1500 ftM.wt = 9.2 PPGNB : Gas shows were recorded at 800 ft and 1100 ft.Calculate the hydrostatic pressure !- at 600 ft =9.5*(600-5)*0.0519 =293 psi- at 800 ft = 9.5*(800-5)*0.0519=392 psi- at1100ft =9.5*(1100-5)*0.0519=540 psi- at 1500ft=9.5*(1500-5)*0.0519=737 psiIn order to pull the riser it is necessary to displace it with sea water of density 8.5 PPG.So the resulting pressure would be: - at sea bed = (250+45-5)*8.5*0.0519 = 128 psi- at 600 ft =[9.5*(600-290)*0.0519]+128 = 281 psi- at 800 ft =[9.5*(800-290*0.0519]+128 =379 psi- at 1100ft =[9.5*(1100-290)*0.0519]+128=527psi- at 1500ft =[9.5*(1500-290)*0.0519]+128=726psi From results a reduction in EQMD =- at 600 ft = 9.1 PPG- at 800 ft = 9.15PPG- at1100ft = 9.25PPG

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- at 1500ft =9.3 PPG If gas zones at 800 ft and 1100 ft are permeable and with that big difference between 9.5 PPG on having riser and 9.1 and 9.15 PPG on removing riser, we might have a gas flow to bore hole. On removing riser, the fluid level in riser falls to sea level causing further reduction pressure. So the hydrostatic pressure will be :- at sea bed = 8.5*250*0.0510 =110 psi- at600 ft =[9.5*(600-290)*0.0519]+110 = 263 psi- at 800 ft =[9.5*(800-290)*0.0519]+110 = 361 psi- at 1100ft =[9.5*(1100-290)*0.0519]+110=509psi- at 1500ft =[9.5*(1500-290)*0.0519]+110=708psi So from results an other reduction in EQMD =- at 600 ft =8.5 PPG- at 800 ft =8.75PPG- at1100 ft=9 PPG- at 1500 ft=9.1PPG To keep a 9.5 PPG gradient at 1100 ft will be necessary to increase the mud density into hole before disconnecting riser, the new mud weight can be calculated as follows : New M.wt =[(D*W) –8.5*(Dw –BOPl)] /[D-Dw-A+BOPl ]D =vertical depth of hole(ft) from flow lineW =mud density in hole (PPG)Dw=water depth (ft)BOPl =height of BOP stack from sea bed to riser conductor (ft) = eg 35 ftA =distance from flow line to sea level (ft)8.5 = density of sea water (PPG)So the new M.wt ={[(1100-5)*9.5]-8.5*(250-35)} /(1100-5)-250-40+35 = 10.2 PPG.So the new Mwt must be = 10.2 PPG to keep a 9.5 PPG gradient @ 1100 ft.

KICK RECOGNITION :

1- Increase in flow rate.2- Increase in pit volume.3- Well flowing with pumps off.4- Increase in chloride content of drilling fluid at flow line (above 100k mg/l).5- Gas cutting.6- Circulating pressure drop because of the unbalance between the hydrostatic column in the drill pipe and annuals after penetrating

an abnormal zone, it may take less pump pressure to circulate the fluid. Flow rate and pit volume increase would normally be observed before a circulating pressure decrease.

7- Hole not taking proper quantity of fluid while tripping pipe out due to formation fluid invasion into bore hole.(swab).8- Drag while tripping in .

WELL CONTROL AND KILL PROCEDURES

1- Record predetermined kill rate (SPM), and kill rate pressure[Other names :Slow Circulating Pressure](SCP) or Reduced Circulating Pressure (RCP) ] . A predetermined slow rate for circulation out a kick is recorded each tour. This is done to stand on any change in slow rate pressure due to chock line friction or kill line friction. also to compensate for changes in depth or any fluid weight changes. This slow rate is recommended to be ½ of the normal rate or even less to prevent any excessive well bore pressure, when circulating out a kick through chock lines or kill lines.2- Position Kelly and tool joint , so that tool joint are clear of sealing elements .3- Stop pumps and check for flow.4- If flow is noted, close will in without delay.5- Record shut-in drill pipe pressure (SIDP) and shut-in casing pressure (SICP) . The drill pipe pressure gauge or pump pressure gauge is in reality a bottom hole pressure.After a well kick , and when the pump is off and the well is shut-in the drill pipe is then a large gauge stem that reaches to the bottom of the hole . So the drill pipe pressure gauge reads in a some how the bottom hole pressure as seen from the gauge stem. PS : If the drill pipe was empty the surface gauge would read bottom hole pressure. But the drill pipe is filled with the drilling fluid, which is normally not contaminated so the gauge reading shows the difference between bottom hole pressure and the hydrostatic pressure of mud column in the drill pipe.

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The SIDP (or kick pressure)is the difference between the hydrostatic pressure exerted by the mud column in the drill pipe and the bottom hole pressure exerted by formation (formation pressure). Formation pressure = stand pipe gauge reading after stopping the pump (SIDP) +the hydrostatic pressure of the drilling fluid column inside the drill pipe .NB : Casing pressure will normally always be higher than drill pipe pressure , because kick gas or water well normally be lighter than the mud and by turn cuts M.wt in annulus . This makes the mud column pressure in the annulus less than the full non contaminated column of the mud in the drill pipe. So the formation pressure acting against the hydrostatic pressure of mud column in annulus will be much easier than acting against the hydrostatic mud column inside the drill pipe and thus the annulus surface pressure will be higher than the drill pipe pressure.Shut-in drill pipe pressure can be determined by :a- Read directly from gauge if there is no back pressure value in the string .b- If a back pressure value in the string then :- Start pump slowly , continue until fluid moves or pump pressure increase suddenly .- Watch casing pressure , stop pump when the annular pressure starts to increase.- Read drill pipe pressure at this point.- If casing pressure increase above its original pressure when closing the well this would indicate trapped pump pressure must be

subtracted from drill pipe pressure reading at the point when stopping circulation. This is the SIDP . These procedures should be repeated until having the same value two consecutive times .

OR : If predetermined slow rate and slow rate pressure have been recorded.- Open chock and start pump slowly .- Hold casing pressure at the same level as the SICP .- Bring pump speed up to predetermined slow rate , keeping casing pressure constant.- Read new circulating pressure at predetermined slow rate from stand pipe gauge (at this kick situation) .- Then subtract predetermined circulation pressure at predetermined slow rate from the new circulating pressure in this kick

situation at the same predetermined slow rate. The difference will be the amount of underbalance or SIDP .6- Check BOPs and manifold for any leaks .7- Check accumulator pressure.8- Check flow line and check exhaust lines for flow .9- Record volume gain and mark pits.10- Fill up kill sheet .11- Calculate well kill calculations . a- Initial circulating pressure = slow circulation pressure + SIDP . As previously mentioned a predetermined slow circulation rate (usually ½ the normal drilling rate)and corresponding pressure loss versus depth and variation in M.wt should recorded each tour . This recorded pressure plus the SIDP will equal the initial circulating pressure (ICP) .

If no predetermined slow rate has been recorded the SICP can be used as a reference point . Open the chock slightly and bring the pump up to a slow rate while maintaining the original SICP at all times . When a satisfactory slow rate has been reached and the casing gauge still reads original pressure , the initial circulating pressure can be read from the drill pipe gauge .b- Calculate required M.wt increase =SIDP / (0.0519*depth)EG :M.wt =12 PPGSIDP =260 psiTVD =10,000 ftM.wt increase =260 /(0.0519*10,000) = 0.5 PPGc- Calculate required M.wt (kill M.wt) to equalize formation pressure

= required M.wt increase + original M.wtSo the new M.wt to equalize formation pressure =12 + 0.5 = 12.5 PPG.

d- Final circulation pressure (FCP) : With the new M.wt at slow circulating rate = ICP-SIDP*(Mwt2 / Mwt1) =SCP*(new M.wt / old M.wt)e- Maximum allowable casing pressure : So as at any time not to reach that value .I.E : Always keeping casing pressure under maximum allowable casing pressure with a satisfactory value . Otherwise causing changing to the casing if its pressure increases . = (Fracture M.wt – Present M.wt) * Casing depth * 0.0519 .

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TYPES OF MUD

KCL POLYMER MUD

Composition and properties :Kcl-polymer mud are considered to be the most inhibitive mud against clay , fluid interaction on drilling massive layers of hydratable clays and shales.Its beneficial effect is based on inhibitive properties of potassium ions towards shale hydration and on the encapsulating and coating of both cuttings and bore hole wall by selected polymers . Kcl-polymer mud is often refereed to as (low solids) mud which means that :- No collided or suspended solids are used in the initial make up.- Treatment is geared to prevent the dispersion of drilled solids to enable solids removal (no thinner added) . 1- Fresh H2O, saline H2O, brine H2O or even sea water , in all types of water should check and treat the hardness of used water as

polymers used are very sensitive to Ca content . so always keep Ca content below 400 mg/l .2- Kcl ,(however the concentration of Kcl may vary depending on the degree of inhibition required) the typical concentration is 10%

by W or 35 lb./bbl . Alternatively concentration Kcl brine may be diluted in a 1: 1 ratio with water.

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3- Caustic soda (0.5 lb./bbl) to maintain pH between 9-10 to provide non corrosive conditions.4- Soda ash (0.1 lb./bbl or 0.3 kg/m3) to treat out Ca content to be less than 400mg/l.5- PAC-LV Resinex & starch {3lb./bbl or 8.6 hg/m3- 4lb./bbl or 11.5kg/m3} for fluid loss control.6- PAC-HV {1-2 lb./bbl or 2.8-5.7 kg/m3} or XCD polymer(BipolyE) (0.5-1.0 lb./bbl or1.5-2.8 kg/m3). PACs are CMC- type

polymers. They are different from technical grade CMC in that the molecules have more anionic sites (promoting adsorption into clay particles) are larger(higher viscosity) and the material contains less impurities.

7- Polyacrylomide (1 lb./bbl or 2.8 kg/m3) (optional)is added to encapsulate clay cuttings. This additive as a liquid concentrate (as a dispersion in oil) to facilitate rapid addition to the mud.

8- Barites as required..

PARAMETERS NEEDED :1- Density > 10.80 kg/m3 .2- M.F viscosity 45-50 sec .3- PV 15-20 cp. (14-20 m Pa.sec).4- YP 20-25 lbs/ft2 (10 12 Pa) .5- pH 9.5-10.5 .6- API fluid loss < 10 cm3 .7- K+ content 52 gm/l .NB : If its required a low fluid loss mud directly from the start (e.g. : permeable formations closely below the casing show) addition of fine particulate matter could be required to aid in filter cake build up , use of prehydrated bentonite (approximately 5lb./bbl or 14 kg/m3) or finally graded Calcium carbonate with a medium particle size of 25 micron , is then recommended . Effect of Clays and Shales :The polymer (Polyacrylomide) in Kcl-polymer mud is through to aid in shale stabilization. It is generally perceived that the polymer (anionic polyelectrolyte) is adsorbed at the positive sites on the edges of clay crystal lattices. It seems likely that this adsorption occurs multiple points along the chain of the elongated polymer molecules , thus linking particles together and form a jelly coating at the surface of the drilled shale and clay particles and on the pore hole wall and thus slow down the rate of transport of water into the shale. It was found that not all anionic polymers seem to be equally effective encapsultors only Polyacrylomide and biopolymers (XCD polymer) have encapsulating properties .Inspite of its inhibiting properties , mud shale interaction can not be prevented completely as a result of ion – exchange with drilled clays the K+ content of the mud will decrease . And as in bentonite and gypsum based muds the mud properties which are affected by shales are: a- Viscosity .b- Density .c- Plastering properties .d- pH .e- Water loss .# The increase of water loss is due to :It is well known that the fluid loss in this type of mud is controlled mainly by polymers. So as a result of depletion of these polymers which adsorb onto drilled shale particles , together with entrance of clay properties into mud in a flocculated state, poor filtration characteristics .I.e. increased value fluid loss will result in a thicker mud cake.# Still many operational problems related to mud shale interaction are reduced by using Kcl polymer muds .EG : Balling problems will be less than during drilling with other mud types . If still occurs ,this an indication for insufficient inhibition and should be treated by increasing Kcl level . A- Tight Hole and Over pulls :They are often experienced when drilling gumbo shales, because shale hydration is reduced , hole erosion is reduced as will as a result the well bore will be in gauge , which is easily experienced as a tight hole . In a dispersed system rapid erosion would avoid this. This can be avoided by continuos reaming before each connection .B- Caving and Hole Enlargement : In more brittle shales, sloughing resulting in Caving and hole enlargement is often a result of hydration along micro fractures, permeable bedding planes and other lithological inhomogenities. The degree of further disintegration of cuttings depends on the shale strength and hydration potential and may therefore be limited in a Kcl polymer mud .Caving circulated out of the hole are often hard and dry with a surface which is clearly not affected by hydration .Operational problems in sloughing shales are Over pulls and difficulties in hole cleaning. When using less inhibitive muds dispersion of Caving may be the reason that sloughing remains unnoticed during drilling , because Caving circulated out cuttings size. An excessive hole size over the unstable zone is often the only indication of shale sloughing in these muds .To avoid these problems its necessary to adopt certain operational problems such as frequent check tripping to restore the hole gauge and to thoroughly clean the hole prior to making trips and ream and clean prior to making drill pipe connection .

# Treatment Whilst Drilling Shales and Clays : In Kcl polymer muds inclusion of clay and shale is avoided by , hydration is minimized and particles are protected from disintegration by encapsulation .

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Kcl polymer muds are also called Low Solids Muds .

# Viscosity and Fluid Loss Control :They are avoided by polymers (XCD polymer, PAC-HV for viscosity and modified starch or PAC-LV for fluid loss control) . Bentonite should not be used for this purpose as it contributes to the clay content of the mud . Chemical treatment with thinner to control rheology should not be done , because clay particles would then be dispersed to unremovable size# Both Viscosity and Density : should be controlled by dilution only, this normally implies disposal of old mud and addition of fresh mud. Treatment indicators are the(rheological indicators PV, YP, Gels) which may exceed set limits, and MBT.NB :The upper limit of bentonite association is 25lb./bbl or 72kg/m3 . Above this value the rheology will rapidly increase to intolerable values .NB :Always the added new mud should be at least ¼ of the circulating volume and should contain all additives as required in the basic make up.NB :One could be tempted to add fresh volume with a reduced viscosity to counteract the high viscosity in the circulating mud. By doing so , one would start to convert to a system which relies on the viscosity being provided by drilled clays rather than by polymers . Reduction of the overall polymer level result in incomplete encapsulation hence increased hydration and dispersion of clay particles and a more rapid deterioration of mud properties.

# K+ and Polymer may deplete rapidly while drilling reactive clays and shales and the level of these additives should mounted closely to enable timely replenishment . The Cl- level of the mud remains virtually constant , however it therefore not possible to monitor K+

content in Kcl –muds by relating to Cl- measurements. Both Kcl and Polyacrylomide (which is available as a liquid concentrate) can be added directly into the active system (no hopper required).Its good practices to start off with a slightly higher Kcl level than specified. EG:(40lb./bbl or 115kg/m 3) when 35lb./bbl or 100 kg/m3

is specified. A more or less constant addition rate can be estimated from the observed rate of depletion.In area when mud plant facilities are available Kcl is often supplied as concentrated brine (80-90 lb./bbl Kcl). Altranativly Kcl supplied in big bags (1or1.5MT content).# For Polyacrylomide additions in reactive shale a rule of thumb is 1 pail (approximately 25L polymer solution) for every single drilled. Addition rate should be adjusted to maintain the excess polymer content at approximately 0.5 lb./bbl or 1.4 kg/m3 in the mud at the flow line. Addition of PPA can result in a thickening of mud in the active pit (say to a MF viscosity of 60-70 sec). This is perfectly accepted as it should be realized that the concentration is automatically reduced when the mud enters the annulus where the polymer is adsorbed onto the surface of cuttings and formation face . The Polyacrylomide content may not depleted because restoring the level may cause excessive viscosity . Deficiency of polymer may result in the build up of fine hydrated clay particles in the mud . Subsequent addition of polymer may then result in blocky structure of flocculated particles with accompanied effect on the mud viscosity, which can only be restored by prolong shearing and circulating .Physically this phenomenon is very similar to the (over the hump)effect in bentonite muds upon salt or Ca++ additions .

FACTS [% of K+] 3% (W) or less is enough to consolidate illitic shales. 20% (W) is required for gumbo shales of young age. 10%(W) 35 lb./bbl is desired to whenever the requirements dictated by formation properties are not known .

INDICATORS FOR INCOMPLETE INHIBITION :1. When cuttings generated are sticky I.E cuttings generated should be firm and move off the shaker screens as discrete particles and

when squeezed in the hand they should not form a sticky mass . If sticky means that hydration is still taking place and inhibition is incomplete.

2. High reduction rate of K+ ion level .3. Rapidly deteriorating rheology properties (requiring high dilution rate)4. Occurrence of potential problems (balling , tight hole). - Increasing the Kcl level improves the inhibiting effect of the mud.- Increasing the polymer level does not contribute to better inhibition . As long as some excess polymer can be detected in the mud

from the hole encapsulating is considered optional.- Polyacrylomide can be left out without adverse effect on the mud or the drilling performance . This indicates that the

encapsulating effect of other polymers present in the mud( EG :XC polymer ) can be sufficient. It is recommended however to include Polyacrylomide if such experience does not exist .

- Kcl polymer are sensitive to drilled solids which might get into the mud and thus will affect viscosity and gels of the mud, therefore it is required high efficiency solid removal equipments especially with respect to shale shaker.

- EFFECTS ON DRILLING ANHYDRITE :

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Contamination by anhydrite does not affect the properties of a Kcl polymer mud. The only indication of anhydrite contamination will be an increase of dissolved calcium to approximately 600 mg/l which is not sufficiently high to give a noticeable effect on Polyacrylomide .NB : Hydration of drilled clay is sufficiently prevented by K+ to avoid flocculation by Ca+2.

- EFFECTS ON DRILLING CEMENT :- Since drilled clays have been converted to a form with K+ as the base ion , which provides inhibition against hydration .- So the cement will only show an increase of pH and Ca+2 content and mud alkalinity (Pm, Mf) .- In case of mud containing polyacrylamide

- Ca+2 levels in excess of 1000 mg/l will deactivate, precipitate and consume the polyacrylamide. But still other polymers ( PACS, XCD POLYMER AND STARCH ) will have a higher tolerance to Ca+2.

- Ca+2 levels in excess of 2000 mg/l and high pH in excess of 11.5 will affect, precipitate and break down XCD POLYMER, PACS and MODIFIED STARCH.

- TREATMENT WHILE DRILLING CEMENT:

- With NAHCO3 ( 0.25 – 0.5 lbs/bbl OR 0.7 – 1.4 kgs/m3 )- In case of severe contamination with cement, dump the contaminated mud.

- EFFECT ON DRILLING SALT

The properties of KCL – POLYMER Mud are not affected by salt contamination other than increase in cl- content. Similar to other non – saturated mud, the mud should be saturated prior drilling through a salt layer.

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The effect and treatment of Kcl – poly mer mud when drilling different formations

Formation M.wt Vis WL MBT pH Alk CL Ca K Treatment

Clay + Shale + + + + + + - - - - Add K – CL & polymer, dumb old partly, replace by fresh mud @ MBT 25 bbl, solid removal.

Sand + Silt + + + + Solid removal, dumb and replace by fresh mud.

Chalky L. ST.

Cement + + + + + + + pol Pretreated with NaHCO3, restore fluid loss and polymer content, dumb contaminated mud.

Anhydrite + No treatment required .

Salt + + Consider conversion to salt saturated mud.

H2S / CO2 - - - - Add C. soda & suitable scavenger Zn CO3 (H2S)Lime (CO2).

Formation + + - - - - - + + + + - - Increase M.wt, treat Ca w/ soda ash, pH w/ C. soda

Brine Correct fluid loss, restore polymer, and consider conversion to salt saturated mud.

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GEL – POLYMER MUD

Preparation :1. Water .2. Caustic soda .3. Soda ash to treat out Ca +2 .4. Bentonite 5-10 lb./bbl .5. Polymer (viscosifires type depends on depth, temperature, pressure and salinity ), (CMC – HV, XCD, PAC – R, CATA Free,

BIPOLY E ) 3 lb./bbl .6. Starch – poramile in case of high salinity .7. W.L. reducer (CMC – LV, Resinex[used when MBT>5lb./bbl, but never use in high salinity ], SALTEX, POLY- PAC, PAC- SL,

POLY TRIX ) .NB : Mixing viscosifires and W.L reducers must be very slow , together with good agitation , and use guns while mixing (at least 10 min/sack). As fast addition will result in poor mixing which by turn will result in :a. plugging of rig pump screens, and thus pump pressure increases.b. Fish eye .c. The used polymer will be inactive .NB : On using mud from previous phase first of all work on Ca+2 contaminations resulting from cement by NaHCO3 to adjust pH , viscosity, Pf, Mf, Pm and dump highly contaminated mud .

Parameters Needed :1. pH 10-10.5 .2. Viscosity 45 s .3. YP 15 –20 4. PV +/- 5 .5. MBT 5 – 10 .6. W.L as required .7. Density as required .Effects of Different drilled Formations : 1. Drilling clay or shales :a. Increase MBT .b. Cause flocculation followed by aggregation . Thus increase viscosity at beginning then viscosity will decrease .c. Increase weight .Treatment :a. Dump and dilution with fresh water .b. Add water loss reducer .c. Solid removal .d. Add dispersants if necessary .2. Drilling sand + silt :a. a. Increase weight .b. Increase viscosity + PV .c. Increase W.L .Treatment :a. Remove solids by solid control equipments .b. Dilute by mean of fresh mud .c. Add W.L. reducer and dispersants if necessary .3. Drilling Cement :a. Increase hardness .b. Increase alkalinity pH, Pf, Mf, Pm .

c. Increase W.L .d. Increase viscosity .e. Decrease YP .Treatments :a. Treat with NaHCO3 in case of high pH , soda ash Na2CO3 in case of low pH .b. Add W.L. reducer (RESINEX, POLYTRIX, and OR CMC- LV) .c. Add thinner (SPERSENE) .d. Add viscosifier to retain YP if necessary e. Dump highly contaminated mud and add fresh water .

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4. Drilling Anhydrite a. Increase Ca+2 content .b. Increase viscosity .c. Increase W.L.Treatment :a. Add soda ash .b. Thinner .c. W.L. reducer .d. Consider conversion to gypsum mud .5. Drilling Saltsa. Decrease pH .b. Increase then decreases viscosity .c. Increase weight .d. Increase W.L.e. Foaming due to chloride increase .Treatment :a. Add thinner .b. Dilution and dump sand trap every 4 connections .c. Correct W.L.d. Add defoamer [no foam, or AL Stearate(1kg/gallon diesel to be sprayed on surface of foamed mud in pits)] .e. Use solid control equipments .f. Consider converting to salt saturated mud .6. Effects of CO2

Causes CO3 gelatin.a. decrease pH .b. decrease alkalinity of mud .c. increase viscosity .d. increase W.L.Treatment :a. If pH is not too low add caustic soda .b. If pH is too low add lime .c. If pH ok add thinner (Lignosulfonate + caustic soda) .

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GENERAL TROUBLE SHOOTING IN WBM:1. In case of increase of % of gas in system , which will affect the mud weight even with true balance increase surface area of mud ?

Putting on Desander to increase of gas from the mud .2. In case that in active is contaminated with CO2 which will lead to CO3 gelation . This will result in foams . Add lime straight

away on system to get rid of CO3 and by turn foams (CO2 gas) 3. NaHCO3 + cement =(may result in ) come CO2 dissolved in mud , this only take place at low pH .4. For quick treatment of Ca+2 contamination add NaHCO3 directly on settling + intermediate . I.E mud out .5. In case of a gas kick while circulation through check use pH paper after hydrated with H2O. Put it in chock line ,if CO2 is present

the color will change from yellow to green which indicate acidic medium .6. In case of bit balling a. Batch (H2O + caustic soda + Spercene ) .b. Drum drilling detergent .c. Redicoat .d. Nut plug to make friction surface under bit .NB :The higher the salinity the lower the pH . The higher the Ca+2 contamination .NB : Ca+2 can be treated by caustic soda , the ppt is Ca(OH)2 (lime) .NB : Treating Ca+2 by mean of caustic soda . So required cut of X 0.1/100 = ppb of NaOH to treat out Ca+2

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OIL BASE MUD

Introduction :The most important feature of any drilling fluid is that there no interaction between the fluid and the drilled formation which if present will affect the mechanical properties of the formation .If a water based system is used the water will inter the formation causing change in its mechanical properties and thus cause instability of this formation(this can be minimized by using a system like Kcl-polymer mud). However the only way to prevent the water wetting of the pores of the rock is to contact the formation with a fluid thus will not wet the rocks and thus will not enter the pores and cause a change in the mechanical properties of the rocks. These fluids having oil to be the continuos phase of the drilling fluid .

ADVANTAGES DISADVANTAGES

Shale stability and inhibition. Temperature stability. Lubricity Resistance to chemical contamination Gauge hole in evaporite formations. Solids tolerance. Reduced production damage. Reduced tendency for differential sticking. Drilling under-balanced. Re-use. Reduced cement cost High penetration rate. Flexibility. Reduced of stress fatigue. Reduced corrosion.

High initial cost per barrel. Mechanical shear required. Reduced kick detection ability. Pollution control required. High cost of lost circulation. Disposal problems. Solids control equipments based on

centrifugation does not work effectively. Hole cleaning. Rig cleanliness. Special skin care for personnel may be required. Hazards vapor. Effect on rubber. Fire hazard. Special logging tools required. Gas stripping.

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Oil Based Drilling Fluids are of Two Types :1. Oil Base Fluid : This type does not rely on entrained emulsified to drive the basic properties of rheology and fluid loss control.Normally these would be formulated without water. Generally contain less than 10% water( usually from 1%-5%by volume of water). This formulated with refined oils such as diesel fuel.NB : Crude oils can be used (they contain high levels of air blown asphalts).2. Invert Emulsion Fluid : Has a continuos exterior oil phase but must have water into interior phase to provide same of the rheological properties and fluid loss control. This type may contain from 10% - 50% water by volume with the continuos oil phase which can be oil or diesel .

OBM is mainly composed of : 1. The oil phase (mainly diesel) Which is the continuos phase into which every thing is mixed ?2. The brine phase (Ca Cl2 + H2O) It exists in the drilling fluid in the form of extremely small droplets ranging in size form submicron to a few microns in diameter. These droplets act as solids in the fluid and impact the basic viscosity . Usually Ca Cl2 not Na Cl is used as it gives greater flexibility in adjusting the activity of the system .3. The solid phase (barite) : This consists mainly of the weighting agent., which is mainly barite . But also having fine drilled solids which must be minimized by removal as much as possible. This done by adding lime.

The main advantages and reasons for using OBM :1. Protection of producing sands : As some producing formations have clays in their pore spaces that swell when contact with water base mud due to water mud filtration . This swelling results in partial to complete blockage of the formation which by turn prevents the passage of formation fluids. The oil filtration of an oil muds does not swell formation clays and therefore does not reduce permeability. Even on drilling clean sands with water base mud may cause water blocked because of the interfacial and surface tension properties of water mud filtrate.2. Drilling water sensitive shales : Some shale formations that slough when contacted with water mud are drilled readily with oil mud. The external phase of the oil mud is oil and does not allow water contact the formation, the shales thereby prevented from becoming water wet and dispersing into the mud or caving into the hole. The result is closer to gauge hole, this have a great advantage on drilling deep wells or deviated wells and thus prevent and relieving stuck pipe .3. Drilling deep hot holes : Oil mud do not undergo any chemical changes at high temperature, which cause solidification of water muds, and thus this advantage make oil muds an excellent drilling for deep hot wells.4. Drilling soluble formations : The drilling of water soluble formations such as salt, potash and gypsum by using water base muds can present a difficulty in controlling viscosity, gel strength, yield, filtration and density. Also the problem cavities in massive salt formations. Oil muds aids in overcoming these problems as the external of an oil base mud is oil and non of the normally encountered salts are soluble in the mud. NB : Two exceptions are calcium chloride and magnesium chloride which will dissolve in the emulsified water , but have no adverse effect on oil mud properties . NB : The non polar nature of the oil muds ensures that the system is in generally insensitive to the chemical contamination that affect water base systems, such as contamination with salt, anhydrite, cement, carbon hydroxide, sulfides .5. Coring fluid for oil producing zones : When water muds a coring fluids , invasion or flushing may destroy the reliability of the data obtained from the core . The total amount of core which is recoverable may be reduces when water mud is used . For these reasons oil muds is used as a coring fluid. As oil muds have a low oil filtrate which allows cores to be cut with only slight invasion and flushing.

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NB : The water in the oil mud which is squeezed into the core by the high pressure under core bit will slow upon distillation of the core, as connate water. For this reason its desirable to prepare either oil fluid have a very low percentage of water or water free system to avoid any damage to the core , but this is quite expensive .6. Spotting to free differentially stuck pipe : Because of lubricity property of oil and oil muds, it have been used to prevent and relieving all types of stuck pipe.# Two things are always present when differential sticking occurs : A permeable zone exposed in the open hole. A mud with sufficient solids, and a sufficient high filtration rate under down hole conditions, to deposit a thick filter cake. Therefore to relive differential sticking , it is necessary to effect some change in the cake already deposited . And to prevent differential sticking it is necessary to prevent deposition of a thick filter cake. Because of the ability of an oil mud to penetrate the water mud cake and because the inherent lubricity of oil muds they are quite successful in freeing pipe that was differentially stick while using water mud. It is well known that oil muds have low filtration rate and head thin cakes at elevated temperature and pressure .7. Plastic flowing shales : Gumbo shale is unique in that it contains low concentrations of hydratable clay(10% - 25%) and a large amount of relatively fresh water (20% - 30%) . When water base mud is used to drill this(gumbo) the shale immediately disperses into the mud. The mud becomes so thick that drilling must proceeds at controlled rate or the mud will plug the annulus. Bit and collar balling , stuck pipe , also shaker screens become plugged because of cutting are soft and gummy. Oil muds overcome all gumbo drilling problems but only solid control problems .NB : By incorporating a fairly highly concentration (10-15 lb../bbl) of Ca Cl2 into the water phase of an oil mud a dehydration of this wet shale would occur and make it drill and act like firmer shale type . The mechanism of this dehydration appears to be osmotic because of the difference in salt concentration in the shale and in the water phase of the oil mud.8. Casing pack and packer fluids : It was found that oil muds have a long term stability and non conduct nature which make them useful in casing packs and packer fluids in completion and workover situations . The requirements for a fluid that is to be placed in the casing tubing annulus are relatively simple. This fluid should be :a- Provide density required to assist in maintaining the packer seal and prevent burst or collapse of pipe. There should be no

compacted settling of solids and slugging and top oil separation should be minimized .b- To be non – corrosive .c- To be fluid enough to permit placement a small annulus, or a good clean displacement in a large annulus .d- To be stable in down hole conditions of temperature and pressure .e- Have a very low filtration rate to avoid significant loss of volume or change in composition.f- Be sufficient gelled to prevent migration of fluids into the annulus .g- Protected casing from corrosion by formation fluids . It is not difficult to prepare an oil mud to meet these requirements . But if the fluid to be used in an open hole annulus , so to migrate corrosion attack , or to facilitate recovery of the casing later, it must be meet much higher standards .

9. To obtain proper pressure control via formation pore pressure : 10. Can be stored and reused :

Thus having the advantage to reduce cost comparing with water base mud which can be only used in one well.11. Low solids oil muds : a- Diesel oil 85% as fast as water base mud and the same factors that reduce drilling rate whether oil or water is the base fluid.b- Diesel oil is less dense than water .c- Solids do not disperse in oil readily as in water .d- Diesel oil is relatively non – corrosive . 12. Treated curds : In some areas low cost oil muds are prepared for drill – in and completion work, simply by treating a field crud to give some property such as filtration control or carrying capacity.

Requirements for preparing OBM :1. E MUL / E CON :

These two products combines to form a very tight film of surfactants at the interface between brine droplets and oil phase , and thus ensures the emulsion stability in the presence of high temperature and high pressure. These two products are high molecular weight sodium and calcium shapes, having a slow acting and requires high shear for dispersion to obtain highly stable water in oil emulsion.NB : Since no fatty soaps are employed , so there is no instability introduced at low alakalinities introduced by H2S and the system will not react adversely with high levels of magnesium contamination . Also E MUL acts as an effective oil wetting agent, this helps to make the fluid resistant to contamination from drilled solids and salt. E CON also imparts the basic filtration control properties to the drilling fluid, upon addition of this product it requires the presence of lime but after the initial reaction the presence of lime is no longer required .

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2. Lime : Gives alkalinity to mud. React with H2S gas

H2S + Ca(OH)2 CaS +H2O . Help to give gel mud stability (leak of lime will cause high viscosity, high YP, high PV).3. E VIS :

It is an organophilic clay which is a viscosity agent which gives the drilling fluid excellent rheological properties (viscosity and carrying capacity) this product also aid in filtration control.

4. E TON :Is an asphaltic HT HP filtration reducer . It also functions as a thinner and difflocculant for high density fluids in high temperature environment.

5. E WET :This product is an extremely powerful oil wetting agent developed to give the drilling fluid extra stability when drilling extremely wet formations .It also acts as a thinner when substantial quantities of solids are present .

NB : While adding barite add E WET slowly at the pit to wet barite and keep it always in suspension and prevent its settling .I.E So as solids get gate by diesel. Mixing OBM : Diesel H2O + + Emulsifier (MUL or CON) Ca Cl2

+ Lime 1. Fill tank with required volume of diesel .2. Add emulsifier (15 lb.,/bbl) and mix thoroughly .3. Dissolve required salt in a separate tank in the required H2O. Add brine slowly under maximum shear to the diesel E MUL

mixture .4. Simultaneously add the Lime and the E CON .

The mud color will darken with shear and time . Shear for maximum stability .5. Add required E VIS (5lb./bbl) and shear until required rheology is achieved .6. Add required E TON (8lb./bbl) and shear until required rheology is achieved .7. Add all Barite if high densities are required a small dose of E WET (1-2 lb./bbl)is recommended .8. Agitate and shear the system as large as possible to get the maximum stability .

Precautions :A. Make on water addition while adding Barite, or vice versa.I.E : Barite addition should never be made in the presence of free H2O .B. Vigorous agitation while adding (high shear)is necessary when adding materials to give stability to the mud .C. Do not increase mud weight when the when the mud has a higher percent water then that desired at the final weight.D. When oil is added , E MUL + E VIS + E TON + E WET, should be added so that the overall concentration of these materials in

the mud is not reduced .E. Determine the oil/water ratio and add proportionate amounts of oil and water. For example if O/W ratio is 75/25, then add the

volumes of diesel oil and volume of water per time period(hour) .F. The amount of each oil mud product to be added in maintaining the mud is based on the total volume of new mud prepared .

The suspension additives can usually be omitted from new volume unless large volumes are prepared, or weight materials is settling from the mud.

NB : This emulsion is generally adequate for bottom hole temperature up to 300 F0 , with respect to filtrate control , and have good rheology if the proper O/W ratio is used and maintained based on final mud weight .NB : The treatments required to maintain an oil mud will vary widely depending on several factors : Drilling rate . Type of formation . Temperature. Weight. Type of solid control program being used. Water contamination . Extremely high bottom hole temperature .

Properties of Brine :Mix brine slug pit or small tank .

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# Preparing 100 bbl of OBM with O/W ratio 80/20 80 bbl diesel / 20 bbl H2O Put 20 bbls of H2O over dead volume of tank (EG: dead volume = 10 bbls)1. From drill program needed brine with 30% Ca Cl2 by wt .2. From CaCl2 chart. 30%CaCl2 by wt 149.95 (ppb/H2O)3. Ca Cl2 (ppb/H2O) * volume of H2O = 149.95*30 = 4498.5lb.# Weight of one sack of CaCl2 = 110 lb.# No of sacks to be added to 30 bbl of H2O = [4498.5/110] = 41 sx.NB: Keep always an excess lime of 5ppb in the initial emulsion.I.E : If dead volume in the mixing tank = 30 bbl. For mixing 100 bbl of OBM 0f O/W ratio 80/20.5 lb./bbl lime * 130 (total volume) = 650 lb.Total volume =30 bbl dead volume +80 bbl diesel +20 bbl brine.Weight of one sack of lime = 55lb.No of lime sacks =650 /55 = 12 sx.NB : On adding E VIS (5 lb./bbl). 130 * 5 = 650 lb. /bbl.Weight of on sack of E VIS = 55 lb. No of E VIS sacks = 650 / 55 = 12 sx.Add E VIS very slowly, add one sack from 10-15 min, and keep gun together with mixing agitator on all the time .NB : Still the new emulsion will not give the maximum good performance except when handling at least one complete cycle as the maximum shearing will be at the bit together with the help of bottom hole temperature .NB : Brine activates in OBM are most commonly adjusted using common salt (sodium chloride and calcium chloride) sodium chloride is most often used when salt sections and high activities are expected .For lower activities calcium chloride is most commonly used .In general for all adjustments to activities for sections calcium chloride is preferred because the greater versatility it offers .

Oil Mud Calculations :

To determine and calculate the amount of materials required to prepare a given volume of OBMPreparing 100 bbl of OBM : 15 lb./bbl E MUL 8 lb./bbl E TON (To be mixed in diesel.) 2 lb./bbl E WET1. Determine density of oil/water mixture being used.

If O/W ratio is 75/25 for example, Set up the following material balance ?0.75(6.7) + 0.25(8.3) =1 xx = density of mixture PPG .6.7 = density of oil PPG.

1. = density of water PPG.x = 7.1 PPG.This is the initial density of oil/water mixture.

2. Determine the volume of liquid and amount of barite needed to prepare 100 bbl of mud ?Using the starting formula :SV = [ (35.4-W2) /(35.4-W1) ] * Diesel volume(bbl)SV =starting volume.W1 = initial density of oil/water mixture.W2 = desired mud weight (EG : 16 PPG)SV =[ (35.4-16) / (35.4-7.1) ] * 100SV = 69 bbls of liquid.Of these 69 bbls , 75% or 51.7 bbls is the volume of oil required, and 25% or 17.3 bbls is the volume of water required to make 100 bbls of mud of weight 16 PPG. The amount of barite is found by :Diesel volume – required volume.X no of sacks of barite to make one bbl by volume(15 sx) = no of sacks to be added to rise up volume to 100 bbls.(100 – 69 ) * 15 = 465 sx

3. Determination of amount of other oil mud materials .Determine the amounts of other materials by multiplying the concentration of additives times the number of bbls to be prepared.

15 lb./bbl (E MUL) * 100 = 1500 8lb./bbl (E TON) *100 = 800

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2 lb./bbl (E WET) * 100 = 200NB: The mud weight will approach 16 PPG before all the barite is added because of the volume and density contributed by OBM materials . About 900 lbs of these materials will occupy one bbl of volume.4. Determination of oil/water ratio from retort data :

The significance of the O/W ratio has been previously started . To determine the O/W ratio it is first necessary to measure oil and water percent by volume in the mud by retort analysis .From the data obtained the O/W ratio is calculated as follows :% oil in the liquid phase = [% oil by volume / (% oil by volume+H2O by volume)] * 100 .% water in the liquid phase = [% H2O by volume/(%H2O by volume +% oil by volume)]*100The O/W ratio = % oil in liquid phase / % H2O in liquid phase .

For example :Retort analysis :51 % oil by volume .17 % H2O by volume .32 % solids by volume .So % oil in liquid phase = [51/(51+17)] * 100 = 75 %% H2O in liquid phase = [17/(17+51)] * 100 = 25 % .NB :# To change O/W ratio : It may become necessary to change the O/W ratio of an oil mud while drilling. If the O/W ratio is to be increased add oil, if it is to be decreased add water.To determine how much oil or water is to be added to change the O/W ratio, the following calculations are made :a. Determine present O/W ratio as mentioned before .b. Decide whether oil or water is to be added.c. Calculate how much oil or water is to be added for each 100 bbls of mud .

To increase O/W ratio 80/20:O/W ratio = 75/25 51 % oil by volume17 % water by volume32 % solids by volumeUsing base of 100 bbls of mud . Here are 68 bbl of liquid (oil & water). To get the new O/W ratio we must add oil.The total liquid volume will be increased by the volume of oil added but the water will not change. The 17 bbls of water now in the mud representing 25 % of liquid volume , will not represent only 20 % of the final new liquid volume. Therefore :New liquid volume – original liquid volume = bbls of liquid (oil in this case)to be added. 0.2 X = 170.2 = new % of water volume.17 = old % of water from retort.X = new total final liquid volume.So X = 17 /0.2 =85 bbls.85 – 68 = 17 bbls of oil to be added.Check the calculations as follows :If the calculated amount of liquid is added what will be the result O/W ratio ?% oil in liquid phase = [(original volume of oil + new oil added) / (original volume + new oil added)] * 100 . = [(51+17) / (68+17)] * 100 = 68/85 * 100 = 80 %so 100- 80 = 20 % water in liquid phase .New O/W ratio =80/20

To decrease O/W ratio 70/30:O/W ratio = 75/25 .51 % oil by volume .17 % water by volume .32 % solids by volume .using base of 100 bbls of mud .There are 68 bbls of liquid in 100 bbls of mud . In this however water will be added and the oil volume will remain constant.The 51 bbl of oil representing 75 % of the original liquid volume will now represent only 70 % of the final liquid volume .Let X = final liquid volume .0.7 X = 51.X = 51/0.7 = 73 bblsNew liquid volume – original liquid volume = amount of liquid(H2O in this case)to be added.

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So 73 – 68 = 5bbl of H2O to be added.% of H2O in liquid phase=[(original H2O vol.+H2O added)/(original liquid vol.+H2O added)]*100[(17+5) / (68+5) * 100 = 30 % water in liquid phase .100 – 30 = 70 % oil in liquid phase .So the new O/W ratio = 70/30 .# For example : If the total volume to be changed from 75/25 to 80/20 is 585bbls, multiply the amount of oil to be added(17) by 5.58 to give the total bbls of oil to added to charge the whole volume.5. Determine the amount of weight material due to effect of liquid additions on mud weight ?When oil or water is added to change the O/W ratio, the density of the mud will change .(Mud density PPG)(mud volume bbl) + (density of added liquid PPG)(volume of added liquid bbl) = [mud volume bbl + liquid volume bbl)(new mud density PPG).Using 17 bbl of oil to be added to 100 bbl of 16 PPG mud.(16 PPG)(100 bbl) + (6.7 PPG) (17 bbl) = (100 +17 bbl) XX = new mud density PPG .X = (1600+114) /117 = 14.65 PPG.The same calculations can be made for any liquid or solid which may be added to the mud as long as the material balance takes from V1 D1 + V2 D2 = VR DR NB : The volume and density units must be constant .NB : V1 + V2 = VR.Example : If we have two fluids of known volumes and densities .The resulting volume and density can be calculated as follow : Fluid # 1 Fluid # 2 Volume = 210 bbl Volume = 150 bbl Wt =16 PPG. Wt = 14.5 PPG.(16) (210) + (14.5) (150) = VR DR

VR = 210 +150 = 360 bbl.[16] [210] + [14.5] [150] = 360 DR

DR =[3360 + 2175] /360 = 15.375 PPG.

The volume of the mud of known density required to change of another mud to a desired value can be calculated as follows : How much 13.6 PPG mud must blended with 410 bbls of 16 PPG mud so that the resulting mixture will have a density of 15.2 PPG?[410][16] + V2[13.6] = [410 + V2][15.2] 6560+ V2[13.6] = 6432+ V2][15.2]

6560-6232 = V2[15.2-13.6]V2 =328/1.6 = 205 bbl .

Displacement procedures :1. When ever possible displace the water base mud with OBM whilst in the casing.2. If allowable , the OBM should have a density heavier than the water base fluid to be displaced.3. Decrease the viscosity of the water base fluid if in casing dilution and treatment with a deflocculant (such as ferrochrome ,

lignosulphonate) FCl can be used . If the hole is open, heavier treatments with (FCl) will be necessary in general the weight reduction from a large dilution can not be treated .It is desirable the gel strength and yield point of the water based fluid be as low as possible to provide for the cleanest and sharpest interface between the two fluids .

4. With about 20 bbls of OBM prepare a viscous spacer and pump this first .5. Pump the OBM slowly (5 bbl/min) to produce the least inter merging of the two fluids .6. Rotate the drill pipe at + , -,(60 RPM) while displacement. This will prevent the water based fluid from gelling and will also aid

in removing the water based fluid from all parts of the hole.7. If the spacer has not been not contaminated it may be incorporated back into the OBM . NB : If the changeover of fluid has taken place in the open hole the filter from the water based fluid may plug the shale shaker during the first circulation . If this happens the screens should be with oil and brushed .Also the OBM should be carefully observed for signs of water wet solids and treated with E WET if required.

Recommended Properties and Control : Rheological Control :The polar interaction between charged clays and polymers that take place in a water based fluid are absent in the non polar oil phase and only the relatively weak hydrogen bonding can occurs. These weak forces are readily broken by heating the medium. So the viscosity tends to be substantially reduced by temperature increases.NB : The optimum range of the factor of a properly maintained OBM is normally in the range of 0.75 – 0.85 .The plastic viscosity is affected by 1. Quality of oil and water .

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2. Quality of solids , and size of the solids .3. The temperature .

High values of PV and YP are mainly due to excessive solid concentrations or an unfavorable O/W ratio.The solids may be removed by fine screens or centrifugation . If this have no effective results dilution with either diesel or fresh volume of OBM is recommended . The YP is less affected by temperature than PV , but is related to the solids content and water content.Very high values of YP may be due to water wet solids in the drilling fluids. This will result in high yield and high gel .Oil wetting agents used to reduce the YP. derived from water wet solids.Dilution may also be required to lower YP .

Settling of barite may also occur , this is treated by adjusting gel strength with oil wetting agent (E WET). Also temperature will have an effect on suspension properties.# Separation of the lighter oil to the surface of emulsion fluid might occur need to add emulsifiers with presence of good mixing and maximum shearing.

NB : Always density is measured of the top and bottom halves of the fluid .The settling factor is (SF) given by the following formula : SF = (Wt of the bottom half) / (Wt of the bottom half + Wt of the top half)If no settling is taking place the value will be within o.5 .The values of less than o.55 are satisfactory for packer fluids and volume of 0.55 is acceptable for drilling fluids.Gel strength of 4-5 lb./100 ft3 initial and 6-8 lb./100 ft3

10 minutes gel. Will suffice normally for barite suspension in most mud densities. These vales can be obtained by addition of E VIS (3-5 lb./bbl).The viscosity effect on oil base mud depends on several factors :1. Concentrations of emulsifiers .2. Emulsion stability .3. Mud density.4. Solid distribution. NB : Emulsifiers or oil wetting additives should be added at the same time while adding E VIS to obtain the required YP . Hydraulic Control :The effects of temperature and pressure on the rheological properties of the OBM, have to be taken into account before the normal equations are used .To calculate the critical velocities , swab and surge pressures, and pressure losses in the drill string and annulus .As a first approximation is assumed that the viscosity changes of diesel oil with temperature and pressure can be applied to the oil based emulsion. This assumption has more accurate applications in systems with high O/W ratio and low solid concentrations .The relationship between viscosity and temperature and pressure is given in figure 7.From this data a correction factor can be calculated that can be applied to the rheological data determined at the flow line . To do this the down hole temperature and pressure have to be estimated . Maximum circulation temperature = {[(BHT – Ambient temperature) * 3] /4} + Ambient temperature. The hydrostatic pressure at the point of highest temperature occurs three quarters of the way down the hole.

Hydrostatic pressure at maximum temperature = depth(ft) * Mwt(PPG) * 0.039 psiOr = depth(ft) * Mwt(kg/l) *0.075.This data of temperature and pressure is then used with figure 7 to obtain the viscosity of the diesel oil at these conditions .Average viscosity of diesel oil = [flow line viscosity +down hole viscosity] / 2This average viscosity of diesel oil is then compared with viscosity of diesel at the temperature at which the measurements were taken to drive the correction factor.Correction factor =average viscosity of diesel / viscosity of diesel at measurement temperature.EG : Flow line temperature = 75 Co (167 oF).Bottom hole temperature = 182 Co (360 oF).Ambient temperature = 20 Co (68 oF).# Step 1 Maximum circulation temperature = (182-20)*0.75 +20 =141.7 Co (287 oF).# Step 2 At depth 20,000 ft (6096 m)the mud density = 18 PPG ( 2.16 kg/l).So pressure at a maximum circulation temperature = 20,000*18*0.039 =14,040 psi.Viscosity of diesel @ 141.7 Co = 14.04 psi.From figure 7 = 1.3 cps .# Step 3 Rheology determined @ 50 Co (122 oF).viscosity of diesel @ 50 Co = 1.9 cps .from figure 7 viscosity of diesel at flow line.From figure 7 @ 75 Co and o psi =1.25 cpAverage viscosity = (1.25 + 1.3) /2 = 1.28 cps.

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Correction factor for VG data =1.28 / 1.9 = 0.67 .

Trouble shootingOne of the most important parameters of a drilling fluid is the rheology .However it is affected by many other parameters such as solids, O/W ratio and oil wetting of solids.# Solids :solids do not present such a problem with OBM as in water based fluid for two main reasons :1. The solids in OBM can not be hydrated and thus soften and disperse into the fluid .2. In oil continues fluid ,polar interactions between charged solid particles can not take place because the medium will not polarize

or conduct electricity .Solids behave as essentially inert and OBM has a higher tolerance to solids than water based fluids.Operational aspects :In general the contamination of any mud with solids will cause :1. Increase drilling fluid maintains cost .2. Difficulty in maintaining proper rheological properties.3. Reduce penetration rates .4. Decrease bit life and increase wear of pump parts .5. Increase frequency of differential sticking .6. Increase circulation pressure losses . Effect of Solids on PV :The increase of solids increases PV due to mechanical friction between solid particles in the drilling fluid . PV depends primarily on size shape and number of solids in the fluid. Effect of Solids on YP and Gel Strength :As YP and gel strength the degree of attractive forces between particles in the fluid. These attractive forces are related to the distance between the particles . Therefore the increase of solids increases YP and gel strength .However chemical treatment , dilution , and mechanical removal of solids are done to overcome the continuos of PV and YP and gel strength due to build up of percentage of solids.The removal of very fine particles produces a greater reduction in viscosity than does the removal of an equivalent volume of coarser solid due to the difference area.NB : 1. The smaller the particle size the more pronounced the effect on the fluid properties .2. The smaller the particle size the more it is to remove or control its effects on the fluid.NB : In general high PV , YP and gel may result in thick filter cakes which by turn will result in over pulls in trips . Also high pump pressure due to high pressure losses.High annular pressure losses may result in severe hole erosion.NB : The drilling fluid has a tendency to thicken when left for a long time period without circulation .

Treatment

A. By mean solid removal equipments remove drilled solids as soon as they are generated .1. Use small shaker screens (120 mesh if possible) it is recommended not to use small mesh screen for a long period.2. Desilter .3. Desander .4. Mud cleaner .5. Centrifuge .B. If excessive solids do build up then the whole mud volume must be diluted .

Water wet solids : The OBM drives many of its advantages from the fact that the formations only contacted with oil. A rule of thumb : the vapor pressure of the emulsified water droplets is also adjusted so that the water remains in the emulsified

fluid . However , sometimes drilling formations with very high porosity and at the same time impermeable and keeping in its pore

spaces high percentage of water . That kind of formations will produce water wetted cuttings , that can interact into mud if there is any lack in the percentage of emulsifiers or oil wetting agent in the mud .This result in polar interactions between water wetting particles and associated brine droplets in the mud .

That will give rise to :1. Viscosity , YP and gel strength.2. Decrease emulsion stability .

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3. Increase filtration .4. Mushy structure of cuttings which will cause blinding and plugging shaker screens .5. Severe settling fills after trips .6. Mud has a dull lock .7. Thicking of the fluid may occur depending on solid concentrations .

Treatment : 1. the problem can be overcome addition of higher levels of emulsifiers (E MUL + E CON) which increase combination between

diesel and water , also make an oil film around wetted cuttings , thus retain stability of fluid and give rise to the basic filtration control of the drilling fluid.

2. Add oil wetting agent to give the drilling fluid extra stability and surrounds (wet) the water wet particles resulting from wet formations . Also oil wet the formation itself and thus decrease the invasion of water wet particles from getting into drilling fluid. It also acts as a thinner and thus helps the dispersion and suspension of invaded water wet particles . thus retain good rheology to drilling fluid .

Electrical stability : The inert nature of the fluid is derived from the fact that the water present is tied up in the form of droplets , stabilized by a complex layer of surfactants . The stability is affected by the size of the droplet which in turn is related to the concentration of emulsification reagent and the shear imparted into the system. The smaller the droplet the greater the stability and resistance to coalescence of drops.- The stability is measured by application of a DC voltage across two terminals immersed in the fluid to pass a certain current. The stability is often measured in volts. A value of 400 volts is generally considered adequate , but higher is easily obtained and characteristic of the strong emulsification system .The emulsification stability can be increased by addition of E MUL and E CON either single or together in conjunction with mixing under maximum shear conditions .

Filtration control : The emulsified water droplets act as colloide sized solids that combines with the other solids in the fluid to form a very effective filter cake .

The good filter cake and filtration control are highly affected by : 1. The strength of emulsion .2. Type and nature of solids .3. Viscosity of oil emulsion .To obtain a measurable quantity of filtrate , this is done under high temperature(300 Fo) and high pressure (500 psi).The HT HP fluid loss should be free of water or traces of emulsion and is usually low .- The filtration rate will be lowered by addition of E CON and filtration reducer (E TON)- However this product is used when required an extremely low filtration for low density fluids Alkalinity :The alkalinity of drilling oil fluids should be kept in the range of 2-4 cc. Is important to maintain this range , regardless of the other parameters required due to ionic nature of the various electrolytes and because of different additives especially E CON emulsifier which functions more effectively in that range .This is maintained by adding lime .Drilling different salts , KCl, Na CL, Mg Cl2, Ca Cl2 and encountering brine water flow :Effects :1. Decrease stability .2. Salt is very hygroscopic and tends to coagulate the water droplets which in turn accelerates water wetting of barytes and certain

other mud constituents .3. Salt also affect the oil –mud emulsion chemistry .4. Lower viscosity .5. HT HP fluid loss may increase ,and water show up in the filtrate .Treatment :1. Add emulsifiers which ensure that the oil emulsion show a good resistance to salt contamination.I.E : Higher levels of E MUL and E TON may be required and attention should be paid to removal of salt crystals by screening .2. If a brine flow is encountered the O/W ratio should be restored by addition of diesel oil and further emulsifiers .3. Lime additions may be required to counter the acidity of the brines .Cementing / Cement Contamination : Can only be a problem if lot of wet cement is drilled.Effects :1. Viscosity (PV & YP) increases .2. Water wetting .Treatment :Addition of E MUL + E TON + E WET .

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Cementing Procedures :Cementing with an oil mud in the hole requires special precautions as the mixing oil mud and cement slurries can produce a highly gelling un pumpable mass .This problem necessitates a neat separation of these two systems , and that is done by an effective spacer which has two main properties :a. separate completely between OBM and cement .b. Remove the oil film on the casing and convert the surface to a water wet state, and thus improving the cement bond . The soccer can be mixed from fresh ,sea, or brine . The viscosity can be adjusted to produce a turbulent flow if required . The cement should be replaced at the maximum possible pump rate (regardless of whether turbulent floe can be achieved ).

Reciprocating and rotation of the casing will also significantly improve the displacement efficiency .H2S contamination : An oil base fluid is normally suited to accept invasion of H2S .In water base fluids . Such invasion creates a problem due to hydrogen sulfide embrihelmentof steel work and drastically changes to chemistry of the fluid due to reaction of alkalis .In OBM the steel work is protected by the continuos oil phase and H2S dissolve in oil phase(to be removed by degaser) .Side Effect :1. Darkening of the mud .2. Decrease alkalinity due to the acidic nature of H2S and its reaction with lime .3. Possible decrease emulsion stability .

Treatment :Addition of lime to maintain alkalinity above 2 cc .CO2 Contamination : (acidic gas)Effect :1. Decrease in alkalinity .2. Decrease emulsion stability .3. Continuos intrusion will increase viscosity (YP & Gel strength) .Treatment :Addition of lime to maintain alkalinity in the optimum range .

Gas Cutting :Effect :1. Settling of barytes .2. Weakening of the emulsion stability .Treatment :1. Addition of E MUL + E CON .2. Addition of E TON .3. Addition of E WET .4. Replace by degaser .NB : Overtreating with surf-cote can destroy viscosity beyond repair. Prior to treatment pilot testing is imperative .

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Problem Indications Cause Treatment

1. Low emulsion stability

Dull grainy appearance to mud. High HTHP fluid loss. Free H2O in HTHP filtrate. Barite settling out. Blinding of shaker screens. Extreme cases can cause water wetting of solids

1. Low emulsifier.

2. Super-saturated with CaCl2.

3. Water flows

4. Mixing mud at mixing plant

1. Add CARBO-MUL. Add CARBO-TEC and lime if CARBO-TEC system2. Dilute back with fresh H2O and add CARBO-MUL.

3. Add CARBO-MUL. Can also add CARBO-TEC and lime if CARBO-TEC system.4. Maximize shear. Check electrolyte content(the higher the content, the harder the emulsion is to form)

2. Water wetting of solids.

Flocculation of barite on sand – content test. Sticky cuttings. Blinding of shaker screens. Settling of barite. Dull, grainy appearance of mud. Low ES. Free H2O in HTHP filtrate.

1. inadequate emulsifier2.Water-base mud contamination.3. Super-saturated with CaCl2.

1. Add CARBO-MUL and SURF-COTE, and diesel

2. Same as 1.

3. Dilute with H2O and add CARBO-MUL.

3. H2O contamination

Weight drop, change in O/W ratio

Add diesel, CARBO-MUL HT, barite.

High filtration High HTHP filtrate with increasing free H2O. low ES. Fill on connections and trips. Sloughing shale.

1. Low emulsifier content2. Low concentration of fluid loss control additives.3. High bottom hole temperature

1. Add CARBO-MUL. Add CARBO-TEC and lime if a CARBO-TEC system2. Add CARBO-TROL A-9 and/or CARBO-TROL.

3. Add more CARBO-MUL. Add CARBO-TEC and lime. Convert to CARBO-TEC system. Add more CARBO-TROL A-9 and CARBO-TROL.

4. High viscosity

High PV, high YP, increasing funnel viscosity. Increasing retort solids. Increase in water content.

1. Low emulsifier content2. Water contamination.3. Over treatment with emulsifiers, especially CARBO-TEC.

1. Dilute with oil, maximize solid control equipment .

2. Add emulsifiers. If severe, also add SURF-COTE.

3. Dilute with oil.

5. High solids Retort analysis, calculations 1. Reduce of shaker screens, dilute with diesel

6. Oil separation

Oil on surface 1. Agitation, add CARBO-GEL or CARBO-VIS

7. Emulsion breaking

Water in filtrate, low electrical stability.

1. Add CARBO-MUL, CARBO-MUL HT, lime.

8. Low alkalinity

Low stability, CO2 & H2S intrusion

1. Maintain 5-7 lb./bbl lime.

9. Sloughing shale

Fill on connections and trips. Torque and drag. Increase of cuttings across shaker.

1. Drilling under-balanced.2. Excessive filtrate.

1. Increase mud weight.

2. Add emulsifiers. Add CARBO-TROL A-9 and/or CARBO-TROL.

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3. Inadequate hole cleaning.4. Activity too low

3. Add CARBO-GEL to increase YP.

4. Adjust CaCl2 content of internal phase so match formation activity.

10. Barite settling

Low YP and gels. Settling of barite in heating cup or viscosity cup.

1. Poor oil wetting of barite.2. Inadequate suspension.3. Low ES, high HTHP.

1. Add emulsifiers and/or wetting agents. Slow addition of barite.2. Add CARBO-GEL or viscosifing polymer.

3. Add emulsifier.(i.e.; CARBO-GEL, CARBO-VIS or water )

11. Drilled solids appear gummy

Shale cuttings absorbing water by hydration forces

1. Increase salinity to 350000 PPM with CaCl2.

12. Un-dissolved CaCl2 or NaCl

Drop in ES, high Cl content in H2O phase.

1. Add H2O to dissolve Salt, then add CARBO-MUL + CARBO-MUL HT + lime. New mud without salt in H2O phase may be blended.

13. Lost circulation

Pit volume decrease, loss of returns.

1. Hydrostatic pressure is greater formation pressure

1. Add mica or plug. Never add fibrous or Phenolic-resin materials. If possible, reduce mud weight. Add MILFIBER, or calcium carbonate.

14. problem mixing mud at mixing plant

Poor emulsions stability. Barite settling. Dull, grainy appearance to mud. Mud very thin with no yield or gel strengths.

1. Inadequate shear2. Very cold3. Poor wetting of barite4. High electrolyte content. Normally greater than 350000 PPM.5. Surface contamination possible if using CaCl2 brine that has been used as completion or work over fluid

1. Maximize shear2. Lengthen mixing time3. Slow additions of barite. Add CARBO-MUL if severe, add small amount of SURF-COTE.4. Dilute back with fresh H2O. once emulsifier is formed, can add additional CaCl2 to obtain desired activity .

5. Pilot test with known CaCl2 brine to determine if problem does exist.

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Lost Circulation :Lost Circulation material like mica or nut plug (fibbers in the worst case)can be added directly to the mud. Lost circulation materials weaken the emulsion and cause water wetting tendencies . Therefor it is required to add a sufficient of

emulsifiers (E MUL + E CON) and oil wetting agent (E TON) to a system containing lost circulation materials .Diesel M plug :prepare slurry of 50-60 bbls (8-10 m3) with flowing materials .A. Diesel M barite plug : Mixing order is as follows; Diesel, Diesel M, Barytes, and E TON (SG of barites 4.25) .

TABLEB. Diesel M-Siderite plug : Consideration concerning the pay zones , may require an acid soluble weighting material, a siderite (Fe CO3) .The mixing order is as follows;Diesel oil, Diesel M, I Dwate and E MUL +E CON .In both system s, ensure that adequate mixing has taken place before either weighting agent is added .

Spotting the Pill :1. Determine the thief zone .2. The pipe should be pulled to the casing while mixing the pill if possible.3. The pill is mixed to the desired weight .4. The slurry is pumped into the open hole or above the thief zone .5. Allow a setting time for pill .6. The blow out presenters are closed and a slight squeeze press is applied [200-400 PSI (13.5-25 atm)] .7. By pumping slowly and hesitating for press build-ups and bleed-off a successful squeeze can be accomplished .8. After a back pressure sufficient to withstand proposed mud wt is obtained and held for 2-4 hours .9. Drilling can be resumed , circulation should be restored with a very slow pump rate after getting back to bottom .NB : This technique is used where partial or complete losses are occurring to induced fractures . Blow Out / Flow :Setting of a Barytes in oil plug :This technique is used in oil mud against underground blow outs or to plug the bottom of a hole quickly without cement .1. Calculate the volume(bbls or m3) for 300 ft or 100 m receptively of settled barite in the oil plug including estimated hole wash

outs .2. If it is flowing down hole use E MUL + ECON as oil wetting dispersants .3. Barytes is added to increase the weight of oil plug up to 21 PPG (2,52kg/l)Preparation of an oil plug slurry :In bbls :E MUL Oil wetting agent Barite Slurry volume (Lb.) (lbs.) (lbs.) (bbls) 2 2 1060 1.52

In m3 : E MUL Oil wetting agent Barite Slurry volume (Lb.) (lbs.) (kg) (m3) 5 5 3025.24 1.52

CHEMICAL ANALYSIS OF OBM :Whole Mud Alkalinity :1. Add 100 cm3 of 50/50 xylene /IPA solvent to a 400 cm3 beaker or titration vessel.2. Fill a 5 cm3 syringe with whole mud past the 3 cm3 mark .3. Displace 2 cm3of whole mud into the titration vessel .4. Swirl the mixture until it is homogenous .5. Add 200 cm3disttled water .6. Add 15 drop Ph Ph indicator solution .7. While stirring rapidly , slowly Titrate with O.I.N sulfuric acid until pink color just disappears . continue stirring and if no pink

color reappears within one minute , stop stirring .8. Let the sample stand for five minutes. If no pink color reappears , the end point has been reached . Record the volume of acid

used. If oink color returns , Titrate with acid a second time .If a pink color returns after the second titration , Titrate with acid a third time and call a total volume of acid used for all three titrations the end point .

9. Calculate the whole mud alkalinity :

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Pom =0.1 N sulfuric acid, cm3 / mud sample cm3

= 0.1 N sulfuric acid, cm3 / 2 cm3

To convert this volume to lb./bbl , Ca (OH)2 lime multiply by 1.295 .If CaO (quick lime) is used to activate the emulsifier, the conversion factor to lb./bbl is 0.98 .

Whole Mud Chloride :1. Using the same sample that used for the alkalinity, procedure, make sure the mixture is acidic by adding 1-2 or more 0.1 N

sulfuric acid.2. Add 10-15 drops of potassium chromate indicator solution .3. While stirring rapidly , slowly Titrate with o.282 N silver nitrate until a salmon pink color remains stable for at least one minute.

If a question exists as to if the end point has been reached , it may be necessary to stop the stirring and allow separation of the two phases to occur .

4. Calculate the whole mud chloride using the volume of 0.282 N AgNO3 :Clom =10,000(0.282 N AgNO3 , cm3) / oil mud sample, cm3 . = 10,000(0.282 N AgNO3 , cm3) / 2 .

Whole Mud Calcium:

1. Add 100 cm3 of 50/50 xylene /IPA solvent to a titration vessel.2. Fill a new 5 cm3syringe with whole mud past the 3 cm3 marsh .3. Displace 2 cm3 oil mud into titration vessel .4. Cap the jar tightly and shake vigorously by hand for one minute .5. Add 200 cm3 distilled or deionized water to the jar .6. Add 3 cm3 1N sodium hydroxide buffer solution .7. Add oil to 0.25 g calver 2 to indicator powder .8. Recap the jar tightly, shake vigoursouly again for two minutes, set jar a side few seconds . If a reddish color appears in the

aqueous phase (lower) calcium is present. Continue the test.9. Begin stirring without mixing upper and lower phases .10. Titrate slowly by adding EDTA (versenate). When a distinct color change from reddish color to blue-green color occurs , the end

point is reached. Read the volume of EDTA titrated.11. Calculate the whole mud calcium using the volume of EDTA :Caom = 4,000(0.1 M EDTA cm3) / oil mud sample cm3. = 4,000(0.1 M EDTA cm3) / 2 cm3

A) WHOLE MUD CALCULATIONS

THE WHOLE MUD ALKALINITY 0.1N sulfuric acid, cm3 0.1N sulfuric acid, cm3

Po m = = (1) Mud sample cm3 2 cm3

THE WHOLE MUD CHLORIDE

10000 (0.282 N silver nitrate, cm3)Clo m = (2) Oil mud sample

10000 (0.282 N silver nitrate, cm3)Clo m = 2.0 cm3

THE WHOLE MUD CALCIUM 4000 (0.1 M EDTA cm3)

Ca o m = (3)

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Oil sample, cm3

4000 (0.1 M EDTA cm3)

Ca o m = 2.0 cm3

1. Total lime content:The total lime content represented as lime hydrate , Ca (OH)2, is :Lime lb./bbl = 1.295 (Po m) (4)If quick lime, is CaO is used to activate the emulsifier, the total quick lime is:Lime lb./bbl = 0.98 (Po m) (4a)

2. Total calcium content:The total calcium content is:Ca o m = 4000 (VEDTA) (5)Where

Ca o m = mg Ca++/ L VEDTA = cm3 0.1 Molar EDTA/cm3 of mud.3. Total chloride content:

The total chloride content is:Clo m = 10000 (VSN) (6)WhereClo m = mg Cl-/L

VSN = cm3 0.282N silver nitrate/cm3 of mud.4. Total CaCl2 and NaCl content:

The chloride ion associated with CaCl2 based upon the Cao m analysis is:Cl CaCL2 = 1.77 (Cao m) (7)WhereCl CaCL2 = mg Cl/L of mud from CaCl2

NOTE: If CaCl2 ≥ Clo m then assume that only CaCl2 is present in the mud and no NaCl is present, proceed to Eqn. 13 and skip Eqn. 8 through 12.

CaCl2 o m =2.774 (Cao m) (8)Where

CaCl2 o m = mg CaCl2/L of mud CaCl2 salt = 9.17 X 10-4 Cao m (9) Where

CaCl2 salt = lb. calcium chloride per barrel of mud ClNaCl = Clo m – ClCaCl2 (10) Where ClNaCl = mg Cl/L of mud from NaCl. NaClo m = 1.65 (ClNaCl) (11) Where NaClo m = mg NaCl/L of mud

NaClsalt = 3.5 X 10-4 (NaClo m) (12)Where

NaClsalt = lb. sodium chloride per bbl of mud. Omit Eqns. 13& 14

If the test Eqn. 7 indicates that all of the chloride ions generated from CaCl2 , the following equations are used:

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CaCl2o m = 1.57 (Clo m) (13)Where CaCl2o m = mg CaCl2 / L of mud.CaCl2 salt = 3.5 X 10-4 (CaCl2 o m) (14)Where CaCl2 salt = lb. CaCl2 per bbl of mud.

B) AQUEOUS PHASE SALT CALCULATIONSAccurate salt calculations prevent the super saturation of the brine with CaCl2, which can lead to severe water wetting. The percent by volume solids, as determined by the distillation retort, should be adjusted for the calculated salt volume which will be retained in the retort assembly. This correction can be accomplished with simple calculations, assuming that accurate chloride and reading data are used.The following equations are designed to calculate the quantity of NaCl and CaCl2 in the aqueous phase of the CARBO-DRILL Systems.

100 (CaCl2 o m)Wc = (15) CaCl2 o m +NaClo m + 10000 (Vw)

WhereWc = wt % CaCl2 in brine.Vw = volume % retort water.CaCl2 PPM = 10000 (Wc) (15a)

100 (NaClo m)WN = (16) CaCl2 o m +NaClo m + 10000 (Vw)

Where WN = wt % NaCl in brine.NaClPPM = 10000 (WN) (16a)Check mutual solubility of NaCl and CaCl2 or use Figure 2.WN max = 26.432 – 1.0472 (Wc) + 7.98191 (10-3) (Wc)2 + 5.2238 (10-5) (Wc)3 (16b) Where WN max = maximum wt % NaCl in CaCl2/ NaCl brine at 25C (77F)

1. MUTUAL SOLUBILITYCheck figure 2 or Eqn 16b to determine the weight percent of sodium chloride, WN, that is totally soluble in the CaCl2 /NaCl brine solution at 25 C (77F). if the calculated WN is not totally, the results a portion of the NaCl is a solid in the oil base fluid.Also, if the WN is not totally soluble. The results of the Eqn 15 and 16 are not correct. They must be recalculated using a fraction of WN as the NaCl o m , until the ratio of WNmax / WN is greater than 0.95. the following steps are used to determine more accurate salt solubilities .Calculate the NaCl ratio to determine the accuracy of WN : WN max

NaCl ratio = (16c) WN

Where NaCl ratio = the ratio of the maximum wt % NaCl to the calculated wt % NaCl in the brine.

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If NaCl ratio is greater than 0.95 proceed to Eqn. 17. Otherwise, the value for Wc (Eqns. 15 & 15a), WN (Eqns. 16 & 16a). and WN max (Eqn. 16b) must be recalculated using the value NaClo m as a new value calculated by:NaClo m n = NaCl ratio (NaClo m) (16d)Where NaClo m n = the new NaCl o m to be used in Eqns. 15 through 16b.After substituting the new NaClo m n in Eqns. 15 through 16b, recalculate the NaCl ratio (Eqn. 16c) using the new values. If NaCl ratio is still less than 0.95 the above procedure must be repeated, as shown in the example on page 334.Use only the soluble NaCl portion from the graph or equation iterations as the value of WN in future equations. The remaining salt will be calculated as a solid in the following analysis:PB = 0.99707 + 6.504 (10-3) (WN) + 7.923 (10-3) (Wc) + 8.334 (10-5) (WN) (Wc) + 4.395 (10-5) (WN)2 + 4.964 (10-5) (Wc)2 (17)WherePB = brine density, g/cm3.NOTE:The density of single -salt brine can be found using the values or equations found in the engineering data chapter, section 4 (salt tables)a. mg/L salt weight percent units are based upon the density of the brine, as well as the salt content. The salt concentration , expressed as mg/L is:CaCl2mg/L = 10000 (Wc) (PB) (18)NaCl mg.L = 10000 (WN) (PB) (19)**************************************FIGURE*******************************************C) SOLID CALCULATIONSAs mentioned previously, the solids content, measured from the retort distillation procedure, must be corrected for the salt content of the brine that remains in the retort assembly.The corrected volume % brine is: 100 (VW)VB = (20) PB [ 100 – (WN + Wc)Where VB = volume % brineThe corrected volume % solids are:Vs = 100 – (VO + VB) (21)Where VS = volume percent % corrected solids.VO = volume retorted oil.

The solids in CARBO-DRILL Systems consist of low density solids, usually drill solids, and high density solids, generally MIL-BAR or DENSIMIX.

[ 100 (MW)] – [(VO) (PO) ] – [ (VB) (8.345) ]PS = (22) 8.345 (VS)Where PS = average density of solids, g/cm3

PO = oil density, lb./bblMW = drilling fluid density, lb./gal.The average density of suspended solids can be divided into the volume and weight of high density and low-density solids.The volume % high-density solids are:

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PS - PLDS

VHDS = X VS (23) PHDS – P LDS

Where VHDS = volume % high density solids.PHDS = destiny of high solids, g/cm3

P LDS = density of low-density solids, g/cm3

The concentration of high density is:

MHDS = 3.5 (PHDS) (VHDS) (24)WhereMHDS = high density solids lb./bblThe volume of low-density solids is:

V LDS = VS - VHDS (25)Where V LDS = volume percent of low density solids.The concentration of low-density solids is:M LDS = 3.5 (P LDS) (V LDS) (26)WhereM LDS = low-density solids, lb./bbl.

D) OIL/WATER RATIO CALCULATIONSThe oil/water ratio relates the oil and fresh water fractions as a percent of the liquid retort fraction. The oil/brine (salt-content corrected water) ratio relates the liquid fraction of the mud as ratio of oil and brine fractions. The oil/brine ratio is the most meaningful ratio. Since it relates more closely the liquid fractions of the drilling fluid. Oil/brine ratio is important when engineering most CARBO-DRILL Systems, in that it can have a major effect on viscosity and/or filtrate loss.The oil/water ratio is calculated as follows:

100 (Vw)WR = (27) VO +Vw

WhereWR = water % in the ratio.OR = 100 – WR (27a)Where OR = oil % in the ratio.The more accurate and useful ratio is the oil/brine ratio . the oil/brine ratio is calculated as follows:

100 (VB)BR = (28) VO +VB

WhereBR = brine % in the ratio.OR = 100 – BR (28a)

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1. Changing Oil/Brine Ratio:it may be necessary, at some time , to change the oil/brine ratio of the CARBO-DRILL System. The simplest calculation to make is increasing the oil/brine ratio , since only oil is added.To increase the oil/brine ratio with additions of oil:

RO [ VO + VB ] - VO

100FO = X Volsys (29) RB

WhereFO = volume of oil, bbl.RO = required oil ratio.RB = required brine ratio.Volsys = system volume.To decrease oil/brine ratio with the addition of brine:

RB [ VO + VB ] - VB

100FB = X Volsys (30) RO

WhereFB = volume of brine, bbl.

Addition of fresh water will increase the controlled activity of the system . if brine is not available , CaCl2 salt should be added to the drilling fluid when decreasing the oil/water ratio with fresh water . the quantity of calcium chloride necessary to maintain a constant activity when adding fresh water is as follows:

H2O, gal/bbl X FB

FW = (31) 42

CaCl2 add = CaCl2, lb./bbl X FB (31a)Where FW =volume of water, bbl.H2O, gal/bbl = water gal/bbl for given %CaCl2 (see calcium chloride table in the engineering data chapter, section 4)

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CaCl2 add = additions of CaCl2 to system volume.CaCl2, lb./bbl = CaCl2 concentration of wt % from the calcium chloride table in the engineering data chapter , section 4

Important Equations Used For Mud Calculations :1. Volume =[(diameter)2 * depth] / 1029.415 .2. Lag stks = volume / POP.3. Lag time = lag stks / SPM .4. Flow rate (GPM)= POP * SPM *42 .5. Fluid velocity (ft / min) a. In pipe :

V = 24.51 GPM / d2 .b. In annulus :

V = 24.51 GPM / dh2 – dp2 .OR = POP (bbl/min) / annular volume (bbl/ft) . = ft/min .

6. Critical velocity (ft/min) .a. In pipe :

V = [64.57PV + 64.57 { (PV)2 +12.3d2 YP W}] / Wd .b. In annulus :

V =[64.57 PV + 64.57 { (PV)2 + 9.26(dh-db)2 YP W}] / W (dh-db) .7. Slip velocity Vs (ft/min) :a. Laminar flow = [3210(Wc-W) * D2V2] /339YP(dh-db) + PV V .b. Turbulent flow = 60 { D(Wc-W) /W }Where :V =fluid velocity (ft/min) .GPM = gallon per minute . d = internal diameter (in) .dh = hole diameter (IN) .dp = pipe diameter (IN) .D = cutting diameter (IN) (average diameter of sieve) .Wc = cutting density (PPG) .L = section length (ft) .W = mud weight (PPG) .Vc = critical velocity (ft/min) .PV = plastic viscosity (cp) .YP = yield point .TVD = total vertical depth .SIDP = shut in drill pipe pressure .KMW = kill mud weight (PPG) .

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OMW = initial mud weight (PPG) .KRP = kill rate pressure (psi) .F = fanning friction factor dimensionless .Pd = pressure loss .8. pressure gradient = D * PPG*0.0519 .

Density of fresh H2O = 8.33 PPG = 0.433 psi/ft .Density of salt H2O = 8.6 PPG .Density of over saturated H2O = 8.9 PPG =0.465 psi/ft .

9. Equivalent mud wt :We = Wo + P / 0.0519 * D .We =equivalent mud weight .Wo = actual mud weight .P = surface pressure .D = total vertical depth .

10. Maximum allowed mud weight (PPG)= leak of pressure(psi) /0.0519 [TVD(ft)*(test mud weight) .

11. Kill mud weight (KMW)Mud weight needed to balance a kick = W1 + [SIDP / 0.0519*depth]W1 = initial mud weight (lb./gal) .

# Initial circulation pressure (psi) = SIDPP + KRP .# Final circulation pressure (psi) = (KMW /OMW) * KRP .12. pressure drop (psi) = [(L*YP / 225*D)] + [PV (L*V) / 1500 D2]L = length of string .V = velocity of mud (ft/sec)D = diameter of hole – OD of drill string (in)YP =yield point .PV = plastic viscosity .13. Pressure Loss :a. In laminar flow V Vc . IN pipe pd =[(PV * LV) / 90,000d2] + YP L / 225 d. In annulus = (PV * LV) / 60,000(dh-db)2] + YP L / 200(dh-db) .b. In turbulent flow V > Vc . In pipe pd = FLWV2 / 92880 d . In annulus = FLWV2 / 92880 (dh-dp) .14. Equivalent circulation density

We = = W + [pd(annulus) / o.o519* L(TVD)] .15. Reynolds number :a. In drill pipe: Nr = 15.46 dvw / PV .b. In annulus : Nr = 15.46(dh-db) Vw / PV .

Oil Mud Calculations :If you want to raise the percent of diesel from 3% to 8% without reducing the mud weight how many sacks of barite are to be added in order to maintain the same mud weight ?1. Calculate how many bbls of diesel oil equivalent to 5% difference to be increased .EG: System volume = 1,000 bbl .M.wt = 9.5 PPG .X(bbls of diesel) = V(E2- E1) / 1-E2 = 1,000*(0.08-0.03) / 1-0.08 = 50 / 0.95 = 52 bbls of diesel.E1 = 3/100 fraction of % of diesel present .E2 = 8/100 fraction of % of diesel required .2. Adding 52 bbls diesel to system will reduce the M.wt ,so calculate the new M.wt after adding 52 bbls of diesel ?

V1W1 + V2W2 = (V1 +V2) W3

(1,000*9.5) + (52*7) = (1,000+52) W3

W3 = 9.3943 PPG .V1 = volume of system before adding diesel .W1 = M.wt before adding diesel .V2 = volume of diesel added .W2 = wt of diesel added .

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W3 = wt reaching after adding diesel .3. How many sacks of barite needed to get back M.wt up to 9.5 PPG ? X = 1490 (W2-W1) /( 35.5-W2) = 1490(9.5-9.3943) / (35.5-9.5) X = sax / 100 bbl . Total no of sax = (X*1052) / 100 .Oil-Water Ratio :% of oil in liquid phase =[ % oil by volume / (% oil by volume +% H2O by volume)]*100.% of H2O in liquid phase =[% H2O by volume(from retort) / (% of H2O by volume + % of oil by volume)] * 100EG: M.wt = 18.1 PPG % of oil by volume % from retort = 52 % % of H2O by volume % from retort = 10 % % of solids = 38 %% of oil in liquid phase =[52 /(52+10)]*100 = 84 % .% of H2O in liquid phase = [10 / (10+52)]*100 = 16 %.O/W ratio = 84 / 16 .1. To increase the O/W ratio to 90/10 :O/w =% oil(retort) + X / % H2O (retort) .90/10 = (52 + X) / 10X = 38 bbls diesel / 100 bbl of mud = 0.38 bbl diesel / one bbl of mudResulting volume = original volume + new volume = 1 bbl + 0.38 = 1.38 bbl2. To convert to one bbl volume

1 (bbl of mud) / 1.38 (resulting volume) = 0.725 bbl mud .0.38 (bbl diesel) / 1.38 (resulting volume) = 0.275 bbl diesel needed to be added to the system .

I.E: Add 0.275 bbl diesel to every 0.725 bbl mud(of O/W ratio 84/16) to get mud of O/W ratio90/10 .3. Increase M.wt up to 18.6 .

(Vm Dm +Vo Do) X + 35 (1-X) = Vf Df .Vm = volume of mud .Dm =density of original mud .Vo = density of oil .Vf = final volume .Df = final density .X = unknown .Let Vf = 1 bbl .[(0.725*18.1) +(0.275*7)]X + 35(1-X) = (1) (18.6)X = 0.822bbls of liquid .1-X = 0.178 bbls of solids to be added to increase mud weight .

EG: Active system Wt = 18.6 PPG . 10 % H2O by retort 48 % oil by retort 42 % solids .3. On adding certain volume of mud with a 90/10 O/w ratio on active system and need to get O/W ratio 85/15 for both and present

mud .The final volume should be 1300 bbls(O/W)1 X + (O/W2) (1-X) = (O/W3) VfLet Vf = one bbl(83/17) X + (90/10) (1-X) = (85/15) (1)

4.882X + 9-9X = 5.667 (1) 4.882X – 9X = 5.667 – 9 4.118X = 3.333 X =0.809 bbl from (83/17) 1-X = 0.191 bbl from (90/10)For1300 bbls the needed volume from each mud to be mixed together to get the (85/15) mud are:0.809 *1300 = 1052 bbl of 83/17 O/W .o.191 * 1300 = 248 bbl of 90/10 O/W / 1300 bbl of 85/15 of O/W.Begin blending the mud in the active system by transferring 248 bbl of the active system to a reserve pit and add evenly the 248 bbl of 90/10 mud to the active system . The final bbls of new mud in the active system is composed of ;(0.822) (0.725) = 0.596 bbl mud .

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(o.822) (0.275) = 0.226 bbl diesel = 0.178 bbl So o.178 (1490) = 265.22 lb. To be added .# To change O/W ratio from 85/15 to 80/20 , water must be added.(% H2O + X) / % oil = O/Wthen substitute Xo with Vw and Do with Dw in previous equation . Vw =volume of water .Dw = density of H2O . OR : % of oil to be added:% of H2O by vol. From retort /% of oil (retort) +% of H2O(retort) + vol. Of oil to be added] = new H2O by fraction # Needed to cut M.wt 13.3 PPG to 12.3 without affecting volume .vol. = 1425 bbl . fresh mud = 8.4 PPG W1 V1 + W2 V2 = W3 V3 .

13.3(1425- V2) + 8.4 V2 = 1425 *12.3V2 = 290 bbl .Add 290 bbl on one complete cycle and at the same time dump another 290 bbl of the mud .V3/POP = 1425/0.138 = 10326.086 stk. .Result / SPM = 10326.086 /75 = 138 min .Added vol. / 138 = 2.1 bbl/min .

HYDRAULICS: GENERAL HYDRAULICS:

1. Unit of pressure = psi = pound per in2.2. PPG psi * 0.0519.3. Weight of 1 gallon of fresh water = 8.33 PPG = 0.433 psi/ft.4. Weight of 1 gallon of oversaturated water = 8.9 PPG = 0.465 psi/ft.5. Hydrostatic pressure = Wt(PPG) * 0.0519 * depth.6. Unit of density = gm/cm3.7. Density = psi/ft * 0.434.8. Density = PPG * 8.33.9. Hydrostatic head (psi) = PPG * 0.0519 * TVD.10. Weight of sea water = 8.5 PPG.11. Weight of diesel = 7 PPG.12. Total pressure = hydrostatic pressure + surface pressure.13. Pressure gradient: this is the change of hydrostatic pressure with depth for any given unit of the fluid weight

= P/D = 0.0519 * W.14. Equivalent mud weight: is that mud weight which the hydrostatic pressure equal to the sum of the imposed

pressure and the hydrostatic pressure We = Wo + [ P/ (0.0519 * TVD)].Where:We = equivalent mud weight.Wo = actual mud weight.P = surface pressure.

15. Maximum allowed mud weight(PPG): = Leak off pressure (psi) / [0.0519 (TVD + test mud weight).16. Mud weight needed to balance a kick = W1 + [ SIDP / (0.0519 * depth) ].W1 = initial mud weight .SIDP = shut in drill pipe pressure.17. Pressure drop (psi) = {L*YP/225 D}+{PV(L*V)/1500 D2.

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L = length of string . V = velocity of mud. (ft/sec). D = diameter of hole – OD of drill string (in). YP = yield point. PV = plastic viscosity.18. Pressure losses:NB: Maximum pressure is at flow line which is after pumps straight away part of this pressure is lost in flow line, another part in drill pipe, another at pit, another part in annulus until it reaches its minimum pressure at flow out line which is zero psi.The summation of this lost pressure is the pressure losses. c. Pressure in laminar flow:

In pipe (pd) Pd = (PV L V / 90000 d2) + (YP L / 225 d) In annulus = [PV L V / 60000(dh – dp)2] + [YP L / 200(dh – dp)].d. Pressure loss in turbulent flow: In pipe

= [FL W V2] / 92880 d2]. In annulus

= [FL W V2] / [92880(dh – dp).Where: V = fluid velocity. d = internal diameter (in) dh = hole diameter dp = pipe diameter. Wo = equivalent M.wt PV = plastic viscosity YP = yield point L = section length. W = mud weight.19. Effective Circulating Density (ECD): Is that equivalent mud weight for the summation of hydrostatic pressure and pressure loss in the annulus.NB: Pump pressure is affected by : Diameter of nozzles. Flow rate. SPM. Pump linear diameter

BIT HYDRAULICS :

Bit pressure drop ( P) = [flow(GPM) / {0.95{( A2+B2+C2)/642 TFA}] * (Mwt/12031).

Hydraulic horse power (energy expended on bit) (BH hP)BH hP = [bit pressure drop * flow rate] / 1714.BHhP/in2 = HhP / [bit diameter/2]2.

To clean out cutting from around bit this method though be used when Pbit = 65% from Ptotal. Jet Impact Force(lb.) (force expended by jets in the bottom of the hole).

= 0.0173 * flow rate(GPM) * (bit P * M.wt)And result/ (bit diameter/ 2)2 * .

Pbit should be = 48%.OR JIF = (M.wt * GPM * V)/ 1930.

To calculate total flow area of bit (TFA)= [nozzle size / (32/2)]2 = ?.

E.g1; [(7/32)2 / 2] = 0.0119628. Area = r2

= 3.14 * 0.0119628 = 0.0375.

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N.B: This is done for all nozzles I.E each one by its own so if three nozzles are of the same size * 3.In our E.g. *3 = 0.1125E.g 2:We can calculate nozzles size from TFA.Nozzle size for three nozzles = 0.1125

0.1125 / 3 = 0.03750.0375 / 3.14 = 0.01196 – r2

r = 0.01196 = 0.1094D = r * 2 = 0.1094 * 2 = 0.2188D * 32 = 0.2188 * 32 = 7

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AREA 0F JET NOZZLES (seq. in)

NO NOZZLE SIZE AREA OF ONE

1234567891011121314151617

7/328/329/3210/3211/3212/3213/3214/3215/3216/3218/3220/3222/3224/3226/3228/3230/32

0.035750.04910.062130.07670.09280.11040.129630.15030.172570.19630.24850.30680.371230.44180.60130.69030.7854

44 X FLOW RATE JET VELOCITY = 22 (A)2+(B)2+(C)2 448.8 X 7 (64)2

To calculate the neutral point : OR in other words the max WOB, so as the maximum WOB will represent 90 % by length of DC weight in mud , so as to keep neutral point within DC.

Max. WOB = length X weight X B.F X 0.9.B.F = Bouncy Factor = 1 – (M.wt /65.4).Weight DC in air = 2.67 X (OD2 – ID2).0.9 = 90 % by length of weight DC.

NB: The increase of WOB will lead that neutral point will rise up, after deciding the length and weight of DC versus maximum WOB to represent 90 % of DC weight (neutral point).

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Leak off Test

This test is done to determine the maximum pressure the formation can stands, and thus determine the maximum mud weight above which the formation will break down.(NB: differ from one area to another).Leak off test only recommended for exploration wells, not important for production wells.As the maximum mud weight for production areas are already known from exploration wells drilled before in that area.This is done as follows: Drill cement, wash pocket and then drill 10 m or 30 ft of new hole, circulate for a few minutes. Pull to shoe, circulate and condition mud. Make sure that the system is in balance and accurately measure

the mud weight, make sure that the hole is filled up. then close the pipe rams. Pump mud slowly, using the cementing unit until the pressure builds up. measure the volume pumped. Use a

calibrated pressure gauge for pressure. Pump ¼ or 1/8 bbls and wait for one minute or the time required for the pressure to stabilize. Plot on a graph, the commulative mud volume pumped to the final static pressure. Repeat this for each

volume increment. Continue the procedure until the plotted graph starts to bend off. Keep well closed to verify that a constant pressure has indeed been obtained. Bleed off at slow and constant rate, still plotting volumes and pressures, and establish volume of mud lost in the formation. Start circulation. Leak off pressure Maximum allowed M.wt(PPG) = = (PPG). 0.0519X [TVD(ft) X Test M.wt

Pressure (psi)

Pumped volume (bbl)

Pressure Integrity Test

This is a pressure test same as leak off test. But in this case we do not need to break formation .I.E: We test the maximum required mud weight we are intending to work with following the same steps as leak off test, and when reading this value we stop the test and do not continue until breaking formation. This required mud weight is determined from previous tests in the previous exploratory wells done in this area.

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Stuck PipeA. Key-Seating.B. Caving.C. Under gauge hole.D. Differential stuck.A. Key-Seating:This usually occurs in deviated holes when the drill pipe wears into the wall of the hole. Since the drill pipe is the smallest diameter in the drill string, the larger diameter tool joints and drill collars can get stuck when making a trip.Key-Seating is recognized by the following characteristics:1. Still having circulation.2. Can rotate pipe.3. May be able to move drill pipe down. Solution:Once the Key-Seating has been formed, the smallest diameter portion of its configuration must be reamed out with some sort of reaming device.B. Caving in:Causes:1. Insufficient mud weight.2. Wetting shales causing sloughing.3. Insufficient carrying capacity of the drilling fluid.4. Tectonically stressed and brittle shales.Caving is recognized by the following characteristics:1. Can not circulate.2. Can not move the pipe(sometimes the pipe can be moved down words but not up.3. Can not rotate the pipe.Solution:1. Increase mud weight to balance formation pressure if possible.2. Use drilling fluid that will not wet or hydrate the shales and at the same time stabilize shales such as Kcl-

Polymer Mud.3. Increase the carrying capacity of the drilling fluid by increasing YP.C. Under gauge hole:Causes:1. Under gauge drilling assembly.2. Plastic following formations(such as salt or soft formations) caused by overburden pressures.3. Flocculated mud and aggregated mud causes thick filter cake.4. Wall cake build upon a porous formation in an already gauge hole.5. All of these can be complicated by additions of drilled solids to the drilling assembly, commonly refereed as

(Bit Balling).Solution:1. Check the gauge of the drilling assembly.2. Increase mud weight to control formation pressures.3. Reduce filtration to form a smaller wall cake.4. Reduce bit balling by : Change to inhibitive mud. Add surfactants (detergent). Slugs (having nut plug + caustic soda + spersene). Redicoat.NB: When bit is balled, getting high torque, no progress.D. Differential Sticking:

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Differential sticking is defined as the sticking of pipe at one side of hole against a permeable formation because the drilling fluid pressure exceeds the pore fluid pressure of the formation, which causes break of the formation, which by turn will cause a complete loss. And thus the tendency of sucking of drill string to any side of pore hole is possible. Differential sticking may occur in any area of drilling but mostly occurs where deep wells are drilled with high density mud.Differential sticking is characterized by:1. Drill with lowest mud weight practical.2. Maintain low filtration rate.3. Use lubricant.4. Do not allow the pipe to remain motionless for any period of time.5. Use square, hexagonal, or spherical drill collars.6. Change to INVERMUL.7. USE a spotting fluid (ENVIRO-SPOT).

ENVIRO-SPOT spotting fluid formation for 100 bbls

WEIGHT

(PPG)7.3 10 12 14 16 18

OIL

(BBL)65 58 54 49 51 44

ENVIRO-SPOT55 gal Drum

6 6 6 6 6 6

WATER(BBL)

28 26 22 21 11 10

BARITE100 lb. bag

_ 140 250 350 465 570

Start with required volume of oil, add ENVIRO-SPOT, water and barite in that order

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DRILL PIPE CORROSION

Corrosion is the destruction of metal by chemical or electrochemical action between the metal and its environment.I.E: Corrosion occurs as a result of interaction between iron steel of drill string and water base mud.Four conditions must be met ,however , before wet corrosion:1. Anode and cathode must exist.2. The anode and cathode must be immersed in electrolytic medium.3. A potential difference between anode and cathode exists.4. There must be a coupling to complete the electrical circuit. The anode and cathode exist on the drill pipe itself. The drilling mud may serve as electrolytic medium. The coupling is creating by the drill pipe steel . The potential difference is due to the crystalline structure and different metal used in the drilling pipe alloy.

Factors affecting corrosion rate:

1. Oxygen:Oxygen reacts with metal of drill string forming (Fe2O3 & Fe3O4), which accelerates corrosion on metal.Oxygen acts to remove protective films on drill string which accelerate corrosion action and increase pitting deposits ( reddish brown rust of Fe(OH)3 .Oxygen scavengers, passivating inhibitors and filming inhibitor treatments are used to mitigate oxygen corrosion attack.2. H2S:Fe + H2S FeS + 2H+ .The increase of H+ atoms in mud will result in retaining acidic medium which will increase corrosion effect.H2S, cause severe pitting embattlement and stress cracking also a black sulfide coating. Treat with sulfide scavenger as ZnO. Also Film-forming inhibitors are used. Keep pH between 8-9.3. CO2:CO2 is an acidic gas that results in pH reduction and thus increases corrosion effect and pitting attack.CO2 + + H2O H2CO3 (Carbonic acid).H2CO3 + Fe FeCO3 +H2.I.E: FeCO3 deposits indicate CO2 attack. Increase M.wt to stop gas influx . Keep pH between 8-9. Add filming amine4. Bacteria: the by-product of bacteria is CO2, H2S and SO4(leads to H2SO4). Microiobacids are use to control bacterial effect in drilling environments.5. Dissolved Salt:As salt concentration increases, conductivity between charge poles raises, also electrical resistance of drilling fluid decreases . also increase the solubility of corrosive by-products and thus increase corrosion effect.6. Velocity of Drilling Fluid:the higher the mud velocity the higher the rate of erosion of films around the drill string and thus the higher the rate of corrosion (Treat with oil mud , amines).7. Temperature:Rule of thumb : Corrosive rate doubles with every 55 ft increase. As the increase of temperature increases the solubility of corrosive gases(O2, H2S & CO2).8. Pressure:

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the increase of pressure causes an increase in trapping effect of gases in mud such as O2 and thus causes increase in corrosion effect.9. pH:Corrosive is much slower in alkaline medium than in acidic medium.So corrosive rate decreases as pH increases.NB: The best medium of pH to minimize corrosion rate is a pH between 8.5-10.10. Solids:Increase of abrasive solids in mud accelerates removal of protective film around drill string due to increase of friction action causing pipe washout.Also removal of protective film helps corrosive elements attack to drill string steel and thus accelerate corrosion rate.

See pages 7, 8, 9

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