Standard Operating Procedures Review and Update in Progress

These pages came from the original Well BluePrint documents that were in the Information Reservoir. In 2005 minor edits were made to delete inactive products and add some product replacements. Some

edits were made to the Lost Circulation section by a subject matter expert. Other than those edits, these topics have not been changed since 1997.

Contents

Anhydrite/Gypsum Drilling Barite Plugs Barite Sag Bit Balling Carbon Dioxide (CO2) Cement, Drilling Corrosion Depleted Sands/Differential Sticking DRIL-N Systems Filter Cake/Filtration Control Fluid Displacements Fractured Limestone, Drilling Gas Hydrates Gunk Squeezes Hole Cleaning Hole Stability Horizontal Drilling High Temperature Wells Hydrogen Sulfide (H2S) Lost Circulation Mechanical Sticking Permafrost, Drilling Quality Assurance Safety Salt Drilling Shale Drilling Sliding Slim Hole Drilling Solids Control Stuck Pipe Torque and Drag Well Control

Drilling Conditions

Anhydrite/Gypsum Drilling

1

SOP Code: DG Revision Date: 02/10/1997; Amended May 2005

Anhydrite/Gypsum Drilling

Introduction

Calcium sulfate occurs in nature as Gypsum (CaSO4 z H2O) or Anhydrite (CaSO4). It is found in thick sections, stringers, in make-up water, embedded in silts as in evaporite formations and sometimes in the caprock of a salt dome.

Causes of Anhydrite/Gypsum Contamination

Calcium sulfate causes aggregation and flocculation of a fresh water mud, resulting in thickening. The calcium sulfate causes an increase in apparent viscosity, yield point, gel strength and filtrate. The partially soluble calcium sulfate increases the hardness and sulfate content of the filtrate. If a calcium base mud is in use, the calcium sulfate contamination has little or no effect on the mud properties.

Preventing and Curing Anhydrite/Gypsum Contamination

A common method of drilling anhydrite or gypsum formations is to pre-treat the mud with thinners that works effectively in the presence of calcium and sulfates and alkali's. The contamination of the mud by the drilled calcium sulfate is nullified.If it is desired to maintain a fresh water mud after calcium sulfate contamination has occurred, it is necessary to treat out the ions that cause aggregation and flocculation. This may be done by adding soda ash (Na2CO3) or Barium carbonate (BaCO3).

Na2CO3 + CaSO4 = CaCO3 (precipitate) + Na2SO4

The calcium is precipitated as insoluble calcium carbonate (limestone). A general rule is to add 0.02 lb/bbl of soda ash for every epm of hardness. After adding the soda ash, a thinner is usually added to reduce the viscosity and gel strength. A difficulty is encountered if large amounts of soda ash are added. The soluble sodium sulfate tends to build up and cause "ash gels" which are indicated by high progressive gel strength.

Another method to treat out calcium sulfate contamination is to treat the thickening and filtration increase that has occurred and let the system become an aggregated-deflocculated one. This can be done by using a thinner, adjusting the pH and using a fluid loss controller. If a high pH is maintained, this too may result in "ash gels" due to the formation of sodium sulfate. If high sodium sulfate (Na2SO4) occurs, it will require water dilution and lime additions for alkalinity.

Drilling Conditions

Anhydrite/Gypsum Drilling

2

Contaminant Contaminant Compound/ ion

Contaminant Source

Method of Measure- ment

Possible Effect on Mud

Course of Action

Anhydrite/ CaSO4 Formation Ca+2 High Yield Point

Treat with Soda Ash

Gypsum CaSO4 + H2O Commercial titration High Fluid Loss

Ca+2(mg/L) x 0.00093 = lb/bbl Na2CO3

Ca+2 Gypsum High gels or

Thick filter cake

Ca+2 (epm) x 0.0188 = lb/bbl Na2CO3

Ca+2increase

pH decrease Break over to a gypsum mud

Materials and Systems

Mud systems to use if thick sections of Anhydrite/gypsum are expected:

POLYNOX GYPSUM MUD

Chemicals to treat out calcium sulfate contamination:

Soda Ash (CaCO3) Barium Carbonate (BaCO3) Caustic products

Products to condition mud after Calcium has been removed:

QUIK-THIN Thinner LIGNOX PLUS Thinner DEXTRID Filtration Control Agent PAC Filtration Control Agent

Drilling Conditions

Barite Plugs

1

SOP Code: BP Revision Date: 02/12/1997; Amended May 2005

Barite Plugs

Introduction

Barite plug use is normally limited to extreme or emergency conditions where it is imperative that some measures be taken to seal off the bottom section of the wellbore. This type of plug is applicable in several situations including:

Simultaneous kicking and lost circulation. Abandonment procedure allowing safe withdrawal of drill pipe to allow setting of cement plug. Withdrawal of drill pipe to either set casing or repair existing casing strings. Plugging drill pipe in emergency situations. High pressure salt water flows where required kill mud weight approaches or exceeds the formation

breakdown equivalent at some point in the open hole, usually the last casing shoe.

Objectives of Setting Barite Plugs

A barite plug is basically a slurry of barite that is pumped down the drill pipe and placed at the bottom of the wellbore. A successful Barite plug should accomplish two things:

Initially, the weight of the barite slurry should kill the well.

After a period of time, the settled barite plug should mechanically block any flow up the wellbore.

The well should be killed before a mechanical blockage is established in the wellbore.

Barite Plug Design

Designing a barite plug for killing a well is straightforward. The barite slurry pumped into the well must be heavy enough and fill enough of the wellbore to increase the bottomhole pressure to a level exceeding the formation pressure. Problems arise when formation pressure is unknown or when weight or volume of the required barite slurry become excessive.

Designing a barite plug to physically block the wellbore is somewhat more complicated. The generally accepted method is to mix a slurry so that the barite settles out from the slurry into a hard plug which will block the wellbore. The rate that barite will settle into a hard plug is usually slow and predictable. Fairly accurate field predictions may be made from an observation of the initial barite settling rate in a small container. The initial rate is constant and independent of the height of the slurry. The initial settling rate lasts for a short period of time, after which the settling rate decreases as fewer barite particles remain in suspension. In a container one foot high, the initial settling rate applies for approximately five minutes. In a field situation with 500 or more feet (150 or more meters) of barite slurry, the initial rate may apply for a day or longer. The amount of barite settling in a shorter period can be computed as the product of the initial rate times the waiting time.

Drilling Conditions

Barite Plugs

2

Field experience has shown that slurries of up to 20 lbs/gal (2.40 SG) are relatively easily prepared using only Base Oil, EZ MUL (Oil Wetting Agent), DRILTREAT and Barite for oil muds. Water, SAPP, caustic soda and barite are used for water-based muds.

Preparation

From a practical point of view, the following points should be considered:

Use of a cement unit is preferable. This requires that either bulk barite be fed directly to the cement unit surge tank or that sufficient stocks of sacked barite be available at the rigsite. Standard plugs can be mixed to the desired density with no problems of massive settling before displacement.

Oil Mud Application

Barite plug settling rates in oil muds are normally dependent on the density of the slurry and the type and concentration of oil wetting agents. Laboratory studies have shown that oil-based plugs have a tendency to settle, on average, more slowly than water-based slurries. At too low a concentration of EZ MUL and DRILTREAT the barite is insufficiently oil-wet and is not self-suspending. At too high a concentration the barite becomes extremely well suspended and the rate of settling is reduced. It is therefore very important to carefully select the optimum concentration of EZ MUL for the plug density required.

If a cement unit is not able to mix barite, use a slug pit or the reserve mud pits, depending on the total volume of slurry required. The length of the plug is a well site determination to be based on the severity of the situation. In most cases a plug in the range of 250 - 500 ft (75-150 m) is sufficient.

Oil-Based Mud Procedure

Oil-based mud slurries can be mixed as follows:

1. Transfer sufficient oil-based mud to the slug pit to maintain circulation through the mixing pump.

2. Fill pit to half its capacity with base oil and add approximately 4 lbs/bbl (11.4 kg/m3) EZ MUL and 4 lbs/bbl (11.4 kg/m3) DRILTREAT.

3. Weight up with barite to required density; the pit should then be nearly full.

4. If total capacity of the slug pit is insufficient for the required volume of plug, transfer the slurry already mixed to a reserve pit making sure that agitators are used constantly and another mixing pump put on to circulate that pit.

The Engineer on site should ensure that the following measures are also adhered to:

To avoid the chance of initiating rapid settling, excessive additions of base oil are not made at any stage.

Small additions of up to 1.5 lbs/gal (4.3 kg/m3) EZ MUL may be made to control viscosity increases noted during barite additions.

Barite addition rate is controlled to avoid excessive increases in viscosity or possibly initiating settling.

Drilling Conditions

Barite Plugs

3

Formulations for oil-base muds:

18.0 lbs/gal 19.0 lbs/gal 20.0 lbs/gal

Base Oil (bbls) 0.582 0.547 0.513

EZ MUL (lbs) 4 4 4

DRILTREAT (lbs) 4 4 4

Barite (lbs) 597 650 700

Water-Based Mud Application

The slurry is composed of barite, fresh water, sodium acid pyrophosphate (SAPP) and caustic soda. SAPP, a thinner, increases the barite settling rate by lowering the yield point and gel strength of the slurry, and the caustic soda is added to provide an alkaline environment (pH = 10).

Formulation for one barrel of a 20 lbs/gal barite slurry is:

Material Amounts

Fresh water 0.56 bbls

Caustic soda 0.25 lbs

Barite 656 lbs

SAPP 0.7 lbs

Or

Material Amounts

Fresh water 0.56 bbls

Caustic soda 1.0 lbs

Barite 656 lbs

QUIK-THIN Thinner 8 lbs

Displacement

Displacement techniques are the same as in cementing; i.e., the slurry should be under displaced so that the height of the slurry in the drill pipe is 2 bbls greater than in the annulus. This allows the drill pipe to be withdrawn with a natural slugging action and will minimize movement of the slurry in the hole, reducing contamination.

Drilling Conditions

Barite Plugs

4

Because of the high density of these slurries, high differential pressures can be created by under or over displacement. Care must be taken when calculating volumes.

After the plug is spotted in place, tripping out of the hole should be done as quickly as possible and the plug allowed to settle for several hours. The well should be observed to ensure there is no flow. When tripping back into the hole, "feeling" for the plug should begin near the theoretical top of the plug.

Operations can then be started to set a cement plug above the barite, and the well can be safely secured.

Drilling Conditions

Barite Sag

1

SOP Code: BS Revision Date: 02/10/1997; Amended May 2005

Barite Sag

Introduction

When weighted muds are used in highly deviated wells, there is the tendency for barite to settle towards the low side of the hole, creating a stratification of lighter mud on top and heavier mud on bottom. The heavier layer then begins to migrate downwards along the length of the hole due to the gravitational pull. This continuous movement of the mud prevents the development of more substantial gel strengths, compounding the settling problem. Variations in hydrostatic head can cause formation fracturing with accompanying loss of circulation, possibly leading to an influx of formation fluids.

Barite sag can be troublesome and time consuming to correct, and therefore, very expensive. While sag is more of a problem in angled wells, it has also been observed in vertical wells.

Causes

Incidents of barite sag have been reported on highly extended or deviated wells numerous occasions since the mid 1980's. Sag can occur in either dynamic or static conditions, and may be indicated by variations in mud weight when circulating.

Hole conditions which may influence sag tendency are:

Temperature - Higher temperatures increase sag tendency. Hole angle - Sag tendency is increased in deviations >30.

Static time - Although sag can occur under dynamic conditions, its effects are usually not apparent until the mud system has been static for a considerable period of time - after tripping, logging or running casing.

Semi-Static conditions - Minor movements which break gels, such as tripping pipe or running wireline logs increase sag tendency. Slow circulation rates can create conditions likely conducive to sag. Hydrocarbon influxes can affect mud rheological properties

Mud properties which influence sag tendency are:

Rheology, Surface vs. Downhole - Sag occurs even when traditional rheology measurements taken under surface conditions (high PV, YP and Gels) indicate that it should not. When measured under downhole temperature and pressure conditions on a FANN 70 viscometer, muds which exhibit sagging behavior in the well usually demonstrate different rheology and suspension characteristics than their normal surface measurements. The degree of variance between surface and downhole rheology is to some extent a measure of the stability of the mud system. The less variance the more stable the mud system. A key factor that effects the variance in rheological behavior in an invert emulsion mud system is the type of base oil used. The base oil's viscosity versus temperature behavior is critical.

Mud weight - Variations in density will be more pronounced at higher mud weights.

Drilling Conditions

Barite Sag

2

Preventing and Curing Barite Sag

Rheology

The Hershel-Bulkley/Yield-Power Law model better correlates with lab measured sag coefficients, since it more accurately describes fluid behavior at low shear rate. A fluid Tau0 (yield stress) of 7 to 8 lbs/100 sq ft will normally be enough to reduce the static sag in field muds to acceptable levels.

Check the mud rheology at elevated temperatures (e.g. 120F) to obtain an indication of downhole rheology. Use FANN 70 testing before the well to optimize mud product concentration for stable downhole mud rheological properties. Testing with special apparatus called the High Angle Sag Tester (HAST) simulates downhole conditions and shows whether a fluid requires special additive treatments to improve suspension properties. Additions of DURATONE have been shown to reduce sag tendency.

Mud Weight

Maximum and minimum mud weights should be recorded when circulating bottoms up after trips in deviated wells, especially after logging. It is important to maintain uniform mud weight throughout the circulating system. Efforts should be made to treat and equalize any imbalance as quickly as possible. If the equivalent circulating density (ECD) is close to the fracture gradient, this could require circulating until density is homogeneous prior to resuming drilling operations.

Note: When using invert emulsion muds in high temperature wells, it is important to measure the temperature at which the mud weight is recorded to avoid misinterpretations between barite sag and thermal expansion/contraction effects.

Oil/Water Ratio

HAST tests have shown that decreasing the oil/water ratio decreases sag tendency.

Materials and Systems

The best treatment to prevent barite sag is to ensure sufficient gels and low end rheology. In water-based muds this can be achieved with several products, including AQUAGEL and AQUAGEL GOLD SEAL, and polymers such as BARAZAN PLUS.

In oil-based and synthetic muds the use of low end rheological modifiers such as RM-63 in conjunction with GELTONE and SUSPENTONE (a suspension agent for invert emulsions) have been used successfully to prevent barite sag.

Drilling Conditions

Bit Balling

1

SOP Code: BB Revision Date: 02/10/1997; Amended May 2005

Bit Balling

Introduction

Balling occurs when clay based drilled solids adhere together and cling to the metal surfaces of the bit and pipe. Bit balling usually occurs while drilling shale. Clay adhesion is a function of the electrochemical attraction of clay to clay solids and clay to metal (surface tension). The reaction begins when clay solids become wet and hydration/dispersion of the clay occurs. Adhesion magnitude is determined by the degree of clay hydration, the chemical properties of the clay, chemical composition of the mud's aqueous phase, and the proximity between reactive solids or the solids concentration. Massive concentrations of reactive solids can overwhelm most mud systems. Balling will normally slow down the rate of penetration (ROP). ROP will not respond to rotary RPM increases or weight on the bit, this may result in pulling a bit before it is due to be replaced.

Causes

Balling can occur with any hydratable clay. Clays particles can adhere to each other or metal surfaces, given the right water and solids ratio. Therefore, reduction of adhesion and/or balling can be achieved by controlling hydration and/or solids concentration. Bit balling is more of a problem when using water-based muds. When invert emulsions are used, bit or bottom hole assembly (BHA) balling normally does not occur.

For bit and or BHA balling to take place two or more of these conditions must exist:

A reactive clay formation must be present. Water must be available for the clays to become hydrated. Cuttings are compressed - causing adhesion. Sufficient concentrations of electrochemically attractive clays. Inadequate bit cleaning due to poor hydraulics. Electrochemical attraction of clay to metal.

Procedures to Prevent Balling

It is important to limit the concentration of cuttings in the annulus. When large volumes of dispersible solids or cuttings are generated into a specific volume of drilling mud, an infinite amount of surface area is created. If these cuttings are not quickly removed from the area of the bit, the electrochemical attraction of the clays for metal will cause these cuttings to adhere to the bit. The following procedures can aid in cuttings removal.

Control ROP vs Flow Rate

High concentrations of mud solids and drilled solids lead to bit balling. This is a function of mud composition and ROP vs flow rate. Excessive penetration rates relative to flow rates can create a massive concentration of reactive solids in the annulus. Therefore, when drilling "clay type"

Drilling Conditions

Bit Balling

2

formations, the low gravity solids concentration in the mud should be maintained as low as possible (5% by volume or less). In addition, the cuttings concentration in the annulus should be limited to 4% by volume by coordinating the flow rate and ROP. This may require controlling instantaneous rates of penetration.

Sweeps

Depending on hole deviation, high viscosity and/or low viscosity sweeps can be used to effectively remove cuttings from the wellbore. The turbulence of the low viscosity sweep stirs the cuttings bed and the high viscosity fluid carries the solids to the surface. Use BARAZAN PLUS and N-VIS (instead of commercial bentonite) to increase viscosity and avoid increasing the clay content of the mud system.

Bit Type and Hydraulics

Fluid dynamics such as velocity and turbulence are critical for cleaning the bit and preventing balling. Create high velocity and a high degree of turbulence. Flow rates alone are not the key. Fluid viscosity and/or turbulence at the bit are functions of fluid composition and velocity. Solids surface area is the limiting factor for a drilling fluid to shear thin. Therefore, optimizing solids concentration is critical for effective fluid dynamics at the bit.

Hydraulic horsepower at the bit must be optimized. Bit design can contribute to bit balling. Anti-Balling (AB) coated bits are recommended.

Hole Wiping

Frequent short trips in directional wells are very beneficial for reducing the buildup of cuttings beds. The cuttings bed is disturbed by the bit so it can be removed by annular flow, after circulation is resumed. This technique will also help reduce pack-off and gumbo attacks.

Balling Reduction by Mud Composition

Solids adhesion can be reduced by neutralizing the attractive charges on clays by ionic satisfaction, i.e., sodium, calcium, potassium, cationic and anionic polymers, and surface active agents (surfactants).

Balling severity is reduced by limiting the "specific surface area" of reactive solids within the fluid. This process is partially accomplished by preventing hydration and dispersion of drilled solids with inhibitive drilling fluids. Among the basic fluids for consideration are those that contain chloride, calcium, potassium, cationic additives, surfactants, oil, esters, formates, silicates, glycols, and the multiple combinations of these basic ingredients.

Effective mud systems include:

INVERMUL CLAYSEAL PETROFREE BARASILC CAT-I GEM EZ-MUD POLYNOX

Drilling Conditions

Bit Balling

3

pH control is an important consideration since the hydroxyl ion is dispersive. First, hydroxyl ions promote hydrogen bonding of water molecules to the steel surfaces. Second when the hydroxyl ion is hydrated, its large volume of associated water forces clay platelets and layers apart. This dispersive action increases as the pH is increased. pH ranges should be adjusted to coincide with the inhibitive nature of the mud system being used.

Minimizing the clay concentration by solids removal equipment and dilution of reactive solids also reduces the "specific surface area" available for adhesion and balling. Commercial bentonite can aggravate the problem, it should be added very cautiously. When balling is a potential problem, low gravity solids should be maintained at 5% or less by volume and the equivalent bentonite concentration should be 20 lbs/bbl (57 kg/m3) or less, determined by the methylene blue test.

Encapsulate cuttings with EZ-MUD to prevent dispersion and mechanical degradation. Coating solids with EZ-MUD will have two beneficial effects. It binds a solid to prevent dispersion and, it provides lubricious film that allows solids to slide past one another thus preventing mechanical disintegration.

Adding DRIL-N-SLIDE will reduce electrochemical attraction of clay to metal.

Treatments Associated with Cleaning Balled Bits and Assemblies

These pills can be spotted or circulated through the bit and annulus, to help eliminate balling problems. Hydrostatic pressures must be maintained when utilizing these pills. The appropriate pill will depend on the mud type being used, materials available on the rig, formation sensitivity, and safety/environmental concerns.

Caustic Pill

A caustic pill can be spotted or circulated through the bit. Caustic can be mixed in freshwater or seawater to accelerate the hydration and dispersion of a reactive clay. Greater turbulence and a jetting action is formed in the balled area, when pumping water.

CON DET Pill (Detergent)

This pill is usually made up of whole (active) mud with 3 - 20% CON DET. This also can be done with fresh water and circulated through the bit. CON DET performs by reducing surface tension, increasing lubricity, and reducing the sticking tendency of the clay. If using whole mud, mud weights can be maintained.

Note: Detergents may effect several aspects of a drilling fluid system i.e., foaming, environmental concerns.

WALL-NUT Pill

This pill is made up of whole (active) mud. WALL-NUT comes in three available sizes; fine, medium, and coarse. WALL-NUT can be mixed from 5 to 60 lbs/bbl (14 to 171 kg/m3) depending on the mud type and mud weight. This pill is pumped down and through the bit with high pump rates to physically erode the ball of clay adhering to the bit or drill string.

Drilling Conditions

Bit Balling

4

SAPP or QUIK-THIN Pill (Dispersant)

A highly concentrated dispersive pill can be mixed in water or whole mud. This pill is designed to disperse balled up bits and assemblies. High pH ranges can also aid in dispersing clays. QUIK-THIN Thinner may be used up to 20 lbs/bbl (57 kg/m3). SAPP may be added from 1 to 3 lbs/bbl (2.85 to 8.5 kg/m3). Do not use SAPP in high Calcium environments.

Note: These pills are highly dispersive and can cause wellbore washout.

Surfactant Pill

Highly concentrated blends of surface active agents can be added directly to the suction pit, dumped down the drill pipe on connections or sprayed directly on the bottom hole assembly. These blends will lower the surface tension of the water and help neutralize the surface charges of the clays, minimizing hydratable clay adhesiveness.

EZ-MUD/CLAYSEAL

Slugging the pipe on connections with neat EZ-MUD or CLAYSEAL.

Drilling Conditions

Carbon Dioxide (CO2)

1

SOP Code: CO2 Revision Date: 01/02/1998; Amended May 2005

Carbon Dioxide (CO2)

Introduction

Carbon dioxide (CO2) is a common constituent of natural gases and is present in most types of formation fluids. Carbon dioxide dissolves in water, forming carbonic acid that lowers the pH. This lowers the alkalinity of water-based muds changing hydroxyl ions (OH-) to bicarbonates (HCO3-) and carbonates (CO3-2) ions. Carbonates can be introduced into water-based muds from:

Carbon dioxide from drilled gases and formations. Carbonates associated with drilling mud products i.e., barite, bentonite, lignite, etc. Sodium carbonate and sodium bicarbonate overtreatments Organic thermal degradation Causes and Symptoms of CO2/Carbonate Problems

The effect of CO2 contamination on any drilling fluid mud can be severe if corrective treatments are not made. Carbon dioxide can also cause severe corrosion problems if not treated. CO2 contamination (carbonates) can adversely affect drilling fluid properties. Gel strengths become progressive and the yield point increases as the drilling fluid becomes flocculated. The mud may have a dull/flat appearance, and the funnel viscosity is higher at the flowline than the viscosity at the suction pit. The drilling fluid may become extremely thick on bottoms up after periods of static condition, such as a long or short trip. Water-based drilling fluids contaminated with CO2 can have decreases in pH, Pm, or Pf .

CO2 contamination can create a condition where the Pf , pH and solids may all be in the desired range, but, due to the lack of hydroxyl ions the rheological and filtration values do not respond to treatments. Deflocculants such as QUIK-THIN thinner require hydroxyl ions to perform properly. These conditions can create problems downhole, such as increasing the:

Equivalent circulating density (ECD) of the drilling fluids

Surge and swab pressures Chances of becoming stuck Potential for lost circulation

Preventing/Curing a CO2/Carbonate Contamination Problem

If the contamination is from a CO2 influx, increase mud weight to stop further influx, if possible, then treat out the carbon dioxide. Even high density fluids contaminated with CO2 can be controlled satisfactorily provided the fluid contains low concentrations of bentonite and reactive drilled solids.

Pretreat the system with BARACOR 95 (a highly active inhibitor that is stable up to 350F [177C]) if high levels of carbon dioxide are anticipated. BARACOR 95 has proven to be an effective tool in eliminating the flocculation effects seen with large CO2 influxes. BARACOR 95

Drilling Conditions

Carbon Dioxide (CO2)

2

does not eliminate the CO2, it scavenges the gas downhole to form a BARACOR 95CO2 complex, rendering it inert. Traditional lime additions at the surface liberates the CO2 from the BARACOR 95. The CO2 then reacts with lime to form insoluble calcium carbonate. This process re-activates the BARACOR 95 without consuming it. BARACOR 95 does not replace surface lime additions as it is the two-step process that efficiently removes the CO2.

Testing for CO2/Carbonate Contamination

The presence and quantity of CO2 in the filtrate may be determined by two different methods, Garrett Gas Train and back titration. The Garrett Gas Train will indicate the total amount of carbonates in the filtrate. Back titration will determine the amounts of carbonates, bicarbonates and hydroxides in the filtrate.

Treating CO2/Carbonate Contamination

After accurate testing for alkalinity changes, a treatment plan can be made and verified through pilot test and hot rolling. Treatments should begin as soon as CO2 contamination has been verified.

CO2 can be removed effectively by treating with caustic soda (sodium hydroxide, NaOH) and lime (calcium hydroxide, Ca(OH)2). Lime treatments are preferable because contaminant are removed from solution, as shown in the reactions below. All reactions shown are reversible, dependent on the pH of the fluid and lime or caustic soda concentration.

CO2 + H2O H2CO3 Carbon Water Carbonic Dioxide Acid

H2CO3 + 2NaOH Na2CO3 + 2H2O Carbonic Sodium Sodium Water Acid Hydroxide Carbonate

H2CO3 + Ca(OH)2 CaCO3 \ + 2H2O Carbonic Calcium Calcium Water Acid Hydroxide Carbonate

(Precipitate)

Lime is the most commonly used product and should be added at a rate of 0.0130 lbs/bbl (0.037 kg/m3) lime per epm of carbonates. Thinners may be needed to deflocculate the system after the carbonates have been treated, but the over use of thinners can itself be a problem. BARAFILM (a filming agent) is recommended in cases of severe contamination to minimize or reduce corrosion problems by laying a protective film on the drill pipe.

Maintain 200 mg/L calcium in the filtrate to buffer the contamination. Avoid overtreatments of soda ash or sodium bicarbonate when drilling cement.

Drilling Conditions

Cement, Drilling

1

SOP Code: CD Revision Date: 03/05/1997; Amended May 2005

Cement, Drilling

Introduction

From a mud viewpoint, drilling cement introduces two main contaminants. The major contaminant is calcium ion and the second contaminant which compounds the problem is hydroxide ions. Invert muds are largely unaffected by the flocculating effects of increased calcium content, pH and solids increases. However green cement will reduce base fluid - water ratios and in turn emulsion stability. Whenever possible, drill out cement with seawater or expendable water-base mud prior to displacing to invert muds. water-base muds however can experience severe complications if precautions are not taken. Freshwater systems with a high bentonite content or EZ-MUD systems are considered the most sensitive to cement contamination. Generally, the rheological properties, filtration properties and pH will show a dramatic increase as clay particles and polymers are flocculated by the calcium in combination with the high pH. EZ-MUD systems will liberate NH3 as the PHPA breaks down. At high temperature (>250oF), severely contaminated bentonite based muds can solidify.

Precautions

Proper planning and pretreatment will serve to minimize problems associated with high flocculation, plugged flowlines and cement contaminated surface equipment. The following precautions should be made if it is planned to drill cement, particularly when there is a risk that the cement is green.

If it is possible, drill out as much of the cement with seawater if a ready supply is available.

Pretreat water-base muds with sodium bicarbonate 0.25-0.50 lb/bbl (0.70 - 1.50 kg/m3).

Closely monitor mud returns at the shale shakers and immediately dump any green cement or badly contaminated water-base mud.

If large cement sections have to be drilled and treatments are not sufficient to counter the effects of the cement, convert to a lime-based system that tolerates high cement levels such as POLYNOX.

Normal Treatments

Under normal conditions, if the cement was displaced with a spacer and treated mud, the quantity of cement to be drilled will be manageable. A pretreatment with bicarbonate at 0.75 ppb (2.1 kg/m3) for 20" casing or 0.25-0.5 lb/bbl (0.70 - 1.50 kg/m3) for 13" or 9" casing will be sufficient. SAPP in very low concentration can also be used to effectively deflocculate the mud to reduce flocculation from the cement. Mud returns should be closely monitored to adjust further treatments with additional bicarbonate and water.

Conversion to a lime-based system

Should it be necessary to convert to a lime-based system, the conversion can be carried out while drilling cement. The first step is to reduce the solids and MBT below 17.5 lb/bbl (50 kg/m3) with heavy dilution, followed by a treatment of 2 ppb (5.7 kg/m3) caustic soda and 3 ppb (8.55

Drilling Conditions

Cement, Drilling

2

kg/m3) CARBONOX. The increased pH of the filtrate will suppress calcium solubility and retard the solidification of the fluid. During the breakover to a lime system, it is possible to experience a "viscosity hump". Lime and caustic additions must be made to continue going over the hump. If the pH is allowed to drop, the conditions will become worse and the mud will remain viscous. A lime mud can be checked for a full breakover by adding more lime. If the fluid takes the lime without a viscosity increase, the mud is considered broken over. (Refer to the Baroid Handbook for guidelines in running lime-base muds)

Summary

When drilling cement with or without WBM, it is critical to be fully aware of the potential problems. It is prudent to pretreat and be prepared for the worst conditions than attempt to treat after the problem comes to surface. Nothing is certain when preparing to drill cement because of uncontrollable variables such as channeling of cement, varying hardnesses and varying degrees of interface. In many cases, economics will dictate the treatment. It may be more economical to discharge large quantities of contaminated mud and cement than to treat and risk contaminating / recirculating cement through the surface system. Many days have been lost cleaning cement from the bottom of mud pits. The key is preparation and planning for the worst case.

Drilling Conditions

Corrosion

1

SOP Code: C Revision Date: 02/10/1997; Amended May 2005

Corrosion

Introduction

The process of corrosion encompasses several phenomena which can be defined as the decomposition of iron or steel - the primary metallic component of drilling equipment. Corrosion is inevitable, but it can be controlled so that it does not happen as rapidly, or does not concentrate in any one area. Corrosion monitoring and treatments for corrosion control will depend to some extent on the type of drilling fluid being used and the causes of corrosion. Preventive treatment should always be considered, a drill string or casing failure can be extremely expensive.

Causes

Corrosion may be defined as the destruction of metal through electrochemical and mechanical action between the metal and its environment. Corrosion can be accelerated by physical stresses that change the crystalline structure of steel and by the chemical composition of the environment; i.e., drilling fluid. Severe pipe failures are generally caused by a combination of both. The major contributors of chemical corrosion in a drilling operation are:

Oxygen Hydrogen sulfide Carbon dioxide Salts Mineral scale

Oxygen

Oxygen is present in every drilling operation and causes a major portion of damage to drilling equipment. Oxygen in the presence of hydrogen sulfide, salts or carbon dioxide, even in small quantities, has a more severe effect. Sources of oxygen in drilling fluids are water additions and air entrapment. Oxygen corrosion can be severe when air drilling or when using aerated drilling fluids.

Carbon Dioxide

Carbon dioxide is generally present in significant quantities due to degradation of organic additives and from formations which contain a carbon dioxide source. Carbon dioxide acts in several ways, as a catalyst to oxygen, as an acid/corrosive agent (carbonic acid) and as a scale producer, reacting to form carbonates.

Drilling Conditions

Corrosion

2

Hydrogen Sulfide

Hydrogen sulfide is an extremely toxic and dangerous contaminant that enters the drilling fluid from the formation. Sulfide reducing bacteria present in the drilling mud system can also be a source of hydrogen sulfide. It is extremely corrosive because it is acidic when it is in solution. Hydrogen sulfide corrosion (hydrogen embrittlement or sulfide stress cracking) has a significant corrosive effect on metal.

Salts

Salts added to the mud system for inhibition may cause some corrosion problems, because they provide a strong electrolytic environment, which accelerates the passage of ions through the drilling fluid.

Mineral Scale

Mineral scale deposits set up conditions for local corrosion cell activity.

Minimizing Corrosion

Several steps can be taken to minimize corrosion. These range from proper fluid engineering, avoidance of air entrapment and foaming, maintenance of adequate pH, and the use of specialty products designed to either eliminate the contaminant or to reduce the effects of corrosion. Corrosion prevention products include scavengers that neutralize the corrosive agents, filming agents that protect the metal surfaces, and scale removers.

Drill pipe corrosion coupons can be used to monitor type and rate of corrosion. These coupons may be sent to Baroid's laboratory for analysis where the coupon corrosion rate is determined by weight loss and exposure time calculations.

Materials and Systems

Oxygen

Since the prime source of oxygen contamination is from the atmosphere, rheologies should be maintained to minimize air entrapment and defoamers should be available at the rig site. BARASCAV D or BARASCAV L (oxygen scavengers) can be used to tie up the active oxygen. BARACOR 700 is designed to prevent oxygen corrosion in water-based drilling fluids, specifically in mist, air or foam applications. BARACOR 1635 can also be used in mist, air or foam operations. If drill pipe is to be exposed to air for a long period of time, the use of a filming amine, BARAFILM, is recommended.

Carbon Dioxide

Lime can be used as a scavenger for treating low levels of carbon dioxide contamination. BARACOR 95 is a highly active inhibitor which combats the effects caused by carbon dioxide and carbonate contamination in water-based muds at bottomhole temperatures up to 350F (177C). Use BARAFILM (a filming amine) to precoat drill pipe and casing in cases of severe contamination.

Drilling Conditions

Corrosion

3

Hydrogen Sulfide

Raising the pH of the system whenever hydrogen sulfide is expected or encountered will reduce the corrosion effects, but not solve them. Maintaining the pH above 10.5 allows the H2S to be soluble in the fluid, thus minimizing its embrittlement effects when the H2S physically works into the steel. This does not remove the contaminant from the system. The use of scavengers is recommended. NO-SULF and BARACOR 44 can be used in water and oil-based muds. Again in case of severe contamination, precoating drill pipe and casing with BARAFILM is recommended.

Salts

The system should be pre-treated with the filming agent, BARAFILM. BARAFILM is physically and chemically attracted to a metal surface to form a protective barrier between the metal and its environment. BARACOR 700 can also reduce corrosion caused by salts.

Mineral Scale

STABILITE, an organic phosphonate, at low levels (2-5 ppm) will prevent scale build up.

Drilling Conditions

Depleted Sands/Differential Sticking

1

SOP Code: DSK Revision Date: 02/10/1997; Amended May 2005

Depleted Sands/Differential Sticking

Introduction

Many incidents of stuck pipe are caused by differential pressure effects. Excessive differential pressures across lower-pressure permeable zones can cause the drill string, or casing, to push into the filter cake and wellbore where it becomes stuck.

Differential Sticking should be properly addressed in the pre-planning stage and proper preventive measures should be taken to avoid substantial cost penalties. Preventive measures include pre-treatment to prevent sticking, and a pre-agreed action plan should sticking occur. Experience has shown that differential sticking can occur with a minimum overbalance and should always be considered a hazard when drilling permeable formations such as sandstone.

Causes of Differential Sticking

A major cause of differential sticking is excessive overbalance in a permeable zone. The overbalance may be necessary because of an open hole section containing reactive, pressurized shales that require a high mud weight to impart stability. This may be further complicated where wells are deviated, requiring higher mud weights (compared to vertical wells) to stabilize the shales combined with an increase in equivalent circulating density (ECD) and in most cases a lower fracture gradient. Differential sticking may result when the specific requirements for casing design expose sands to excessive overbalance, e.g. deep high temperature - high pressure (HTHP) wells or development wells where the formation changes from shales to reservoir sands. A pressure reversal or depleted zones may cause differential sticking. Excessive overbalance can be a result of poor hole cleaning and/or excessive rates of penetration (ROP) resulting in an increase of annular mud weight.

Other causes include poor quality filter cake, excessive fluid loss, poor hydraulics and rheology resulting in high ECDs. Bad drilling practices, such as leaving drill string stationary in a permeable zone and excessive ROPs that lead to high annular mud weights can lead to differential sticking.

Preventing and Curing Differential Sticking

Bridging Materials

Using a high quality properly sized bridging material will effectively bridge across porous sands minimizing filtrate and whole mud invasion, filter cake build up, seepage loss, differential sticking and formation damage.

Bridging material type and optimum concentration should be determined through testing with the Particle Plugging Apparatus and FANN 90 to determine the combination of products that will provide the lowest spurt and fluid loss. It is important to bridge and seal pore spaces with the initial loss of filtrate. This minimizes filtrate loss and filter cake build up.

Drilling Conditions

Depleted Sands/Differential Sticking

2

Dynamic filtration can be evaluated in the laboratory under a variety of conditions. These include various shear rates, pressures, temperatures and filter medium permeability. The lab requires details about the size and permeability of sand to be drilled. Ideally, the tests should be completed far enough in advance so the treatment can be implemented and the active system tested to confirm the lab results prior to drilling the sands.

Filter Cake Quality

To minimize undergauge hole, the filter cake must be thin and to help in avoiding stuck pipe it must have some lubricity. In addition, the cake must be erodible as the filtration process is converted from static back to dynamic. These properties require that the filtration products be properly sized, deformable, lubricious and shearable. Hydrated solids such as commercial bentonite and polymers meet these requirements; however drilled solids do not and should be minimized at all times.

Reducing Overbalance

Mud weights, fluid rheologies and pump rates can be manipulated to reduce any overbalance. Measures to minimize cuttings in the wellbore and keep the weight in the annulus to a minimum include pumping and circulating sweeps prior to drilling sands. Seepage losses are an indication of overbalance in a permeable formation.

Drilling Practices

Good drilling and tripping practices are vital in avoiding differential sticking. It is very important not to allow the drill pipe to remain motionless for any period of time and to ream any undergauge sections. Communication between all drilling personnel is very important while drilling overbalanced in a permeable zone. A drilling jar and spiral drill collars should be included in the bottom hole assembly.

Materials and Systems

Preventing Differentially Stuck Pipe

BARACARB, acid soluble, pure ground marble (calcium carbonate) is a superior bridging agent compared to normal limestone. The marble grains resist attrition from shear/dynamic conditions downhole and are available for bridging against the wellbore instead of breaking into smaller particles and penetrating the formation, making removal and acidizing more difficult. BARACARB is available in many grades giving excellent flexibility in particle size distribution. Extensive research on differential sticking has shown that BARACARB can reduce the force required to free differentially stuck pipe by 30%, and reduce filter cake thickness by 33%.

BAROFIBRE can also be used to help prevent differential sticking when drilling through reservoir sections which exhibit low formation pressure. Additions of BAROFIBRE can reduce the permeability of the formation at the wellbore face, minimizing the cake build up and the potential for differential sticking. Spotting a pill containing BAROFIBRE prior to coming out to run casing will aid in the prevention of stuck casing in depleted sands. Some starches such as IMPERMEX, DEXTRID and FILTER-CHEK have proven very effective at bridging.

Drilling Conditions

Depleted Sands/Differential Sticking

3

STEELSEAL, BXR, BXR L, BARO-TROL PLUS and in non reservoir sections, MICATEX, may be used in conjunction with BARACARB and BAROFIBRE for some applications. Cloud point glycols such as GEM GP and GEM CP have also been used successfully in the field.

STICK-LESS 20 glass beads can be used to reduce the chances of sticking and increase filter cake lubricity.

Due to their inherent lubricity, oil or synthetic muds are the best choice for drilling significantly overbalanced through depleted sands, however due to environmental regulations they are not always acceptable. Whenever the differential pressure is greater than 2000 psi, an invert emulsion mud should always be considered.

CMO 568 has been proven to be beneficial in increasing filter cake lubricity in oil and synthetic muds in the North Sea.

Freeing Differentially Stuck Pipe

When differentially stuck pipe cannot be worked or pulled free within the safe allowable tension limits, there are two techniques that are commonly used to free differentially stuck pipe.

Reduction of Differential Pressure/U-Tubing Spotting Fluids

Reduction of Differential Pressure

The reduction of differential pressure by mud weight reduction or U-Tubing techniques has been used to free differentially stuck pipe. It can, however, cause further problems and all factors should be considered before using these techniques. Reducing hydrostatic pressure can cause certain formations, usually shales, to become unstable. Often this leads to packing off and further stuck pipe problems. Reduction of hydrostatic pressure can lead to well control problems. For these reasons many operators will use spotting fluids as their first option to free stuck pipe.

Spotting Fluids

When differential sticking occurs, spotting fluids can be used to free the pipe.

Note: It is critical to have the fluid readily available on the rig and apply it within six hours of the stuck pipe occurrence. Spotting fluids are designed to penetrate and break up the filter cake.

EZ SPOT is a good all purpose, oil-based spotting fluid, suitable for use in many different regions.

QUIK-FREE is a spotting system developed for freeing pipe in water-base muds in environmentally sensitive areas where oil-based spotting fluids cannot be used. It is highly effective and can increase lubricity as much as 35%.

Mutual solvent pills have been successfully applied in invert emulsion fluids that contain BARACARB in the North Sea. These pills are built in calcium chloride brine and contain EGMBE an organic solvent and acetic acid. The solvent removes the oil coating from the BARACARB, allowing the acetic acid to breakdown the filter cake.

Drilling Conditions

DRIL-N Systems

1

SOP Code: DN Revision Date: 05/03/1999; Amended May 2005

DRIL-N Systems

Baroid, in response to the needs of our customers developed seven (7) drilling fluid systems designed to drill production intervals when minimizing formation damage is of primary importance. With the advent of Baroid's DRIL-N line of systems, Baroid can furnish all the various drilling fluid systems needed for drilling operations, brines of all types for completion/workover operations and filtration equipment for the brines, all of which culminates in affording you the best possible protection against formation damage.

The primary focus for a drill in fluid is to be essentially non-damaging to the producing formation, provide superior hole cleaning, allow easy clean-up and be cost effective. These fluids address the wide range of problems encountered in horizontal drilling, completion and workover operations.

Baroid's DRIL-N systems are specifically designed to provide the lowest filtration rate possible in order to minimize or prevent formation damage. In order to accomplish this fluid loss control the use of specially selected polymers and bridging particles are incorporated into our DRIL-N systems. Additionally, tremendous amount of testing and research has gone into the selection process to determine the best polymers and their optimum concentrations for our DRIL-N systems. Through this research and testing, specific bridging particles have been selected and sized to provide the best possible bridging results which result in low filtration rates and thin, ultra low permeability filter cakes.

After determining the best components to use in a DRIL-N system, a fluid is then prepared with the desired rheological properties as well to produce a thin, ultra low permeability filter cake. The bridging particles used to provide good filtration and this thin filter cake are BARAPLUG (sized salt) and BARACARB (sized calcium carbonate). As important as the filtration control and filter cakes are to the various systems, the ability to effectively remove these filter cakes requires special technical attention. Through proper displacements and clean-up procedures this cake is removed, thus, reestablishing the initial return permeability of the formation and enhancing the production of the zone of interest.

Again, to accomplish excellent production results and minimize formation damage, one of Baroid's seven DRIL-N systems should be your system of choice.

SYSTEMS DESCRIPTION

BARADRIL-N Sized calcium carbonate system

BRINEDRIL-N High density brine based system

COREDRIL-N All oil drilling / coring system

MAXDRIL-N Mixed metal silicate system

QUIKDRIL-N Modified polymer system with LSRV

SHEARDRIL-N Clay free, modified polymer system

SOLUDRIL-N Sized salt system

Drilling Conditions

DRIL-N Systems

2

OVERVIEW OF SYSTEMS

BARADRIL-N

The BARADRIL-N system provides acid soluble drilling, completion and workover fluid compositions. The BARADRIL-N system is designed for non-damaging drilling when fluid loss and formation stability are of primary concern. Return permeabilities are excellent with the BARADRIL-N system and filter cake is easily removed by treating with hydrochloric acid.

BRINEDRIL-N

BRINEDRIL-N is a high density brine system specially designed for drilling, completion, and workover operations. A blend of microfibrous cellulose and polimeric fluid loss control materials provides exceptional rheological, suspension, and fluid loss characteristics in a non-formation damaging, thermally stable fluid. Correctly sized calcium carbonate can be added to promote a thin, low permeability filter cake for drilling permeable formations.

COREDRIL-N

COREDRIL-N fluids are 100% oil/synthetic drilling fluids that have been developed to control the formation damage that could be caused by conventional drilling operations. The COREDRIL-N system contains an optimum concentration of BARACARB (sized calcium carbonate) or BARAPLUG (sized sodium chloride) designed to bridge rock pores, thus providing low filtration rates - minimizing fluid invasion into potential pay zones. COREDRIL-N fluids use passive emulsifiers which reduce the risk of creating emulsion blockage and preserve the wettability of the reservoir rocks.

MAXDRIL-N

The MAXDRIL-N is a mixed-metal silicate system (MMS) designed for drilling, milling and completion operations. MAXDRIL-N provides borehole stability and superior hole cleaning for milling casing and drilling highly deviated/horizontal sections. This fluid is especially effective when drilling in unconsolidated, unstable, stressed or faulted formations. MAXDRIL-N forms a low permeability filter cake that restricts solids and fluid invasions into the formation, thus reducing potential damage to the formation.

QUIKDRIL-N

QUIKDRIL-N systems are solids free systems utilizing modified polymers for viscosity and suspension. This system was specifically designed for Coil Tubing operations and Slim Hole drilling. Through modification of polymer concentrations, circulating pressures can be adjusted while still providing a drilling fluid system with excellent LSRV as well as superior hole cleaning. QUIKDRIL-N also provides for formation damage protection and is shown to have excellent return permeability results.

SHEARDRIL-N

SHEARDRIL-N systems are designed as a solids-free, modified polymer drilling fluid. SHEARDRIL-N provides maximum penetration rates while effectively minimizing potential formation damage.

SOLUDRIL-N

Drilling Conditions

DRIL-N Systems

3

SOLUDRIL-N fluids are designed for drilling, completion or workover operations in horizontal and vertical wells. SOLUDRIL-N fluids utilize BARAPLUG (sized sodium chloride) and a cross-linked polymer to provide superior rheological properties and filtration control. The SOLUDRIL-N filter cake is readily removed through the use of unsaturated brine.

Drilling Conditions

Filter Cake/Filtration Control

1

SOP Code: FC Revision Date: 02/10/1997; Amended May 2005

Filter Cake/Filtration Control

Introduction

Sealing permeable zones in the wellbore is a primary function of a drilling fluid. Filtration control represents a major portion of the mud cost. Traditionally, most of this cost has resulted from controlling the filtration rate as opposed to controlling filter cake quality. This is understandable since a definitive filtration rate is easier to quantify than a subjective evaluation of filter cake quality.

Filter cake quality is often difficult to define and communicate. Therefore, a review of some basic principles along with some new and old testing procedures will promote better communication, improved drilling fluid design, and proper product usage.

The primary objectives of filtration control are:

Minimize damage to production zones Reduce hydration of formation clays Optimize formation evaluation Avoid differential sticking of pipe Avoid undergauge hole due to thick filter cakes

These objectives are achieved by focusing on important design factors:

Compatibility of filtrate with formation Thin, impermeable, and deformable filter cakes. Lubricious and shearable filter cakes Design Factors for Filtration Control/Filter Cake

Filtrate Compatibility with Formation

The chemical composition of a drilling fluid is a key design factor that will facilitate the fluid's ability to maintain wellbore stability and minimize damage to productive zones. The specific filtration rate of a fluid is important, but it is just as important to minimize hydration and dispersion of clay solids.

Filtrate movement through microfractures in shale is often a capillary action. This spontaneous movement of fluid is not slowed by mere filtration reduction. However, viscosifying the filtrate, sealing the fractures, or adjusting the filtrate chemistry may reduce fluid movement in a fracture.

Drilling Conditions

Filter Cake/Filtration Control

2

Filter Cake Permeability

Filter cake permeability is determined by the fluid's solids concentration, particle size distribution, solids deformability, and the electrochemical properties of the solids. Permeability is reduced as solids are deposited on a filter medium. Permeability is also reduced by the bridging of particles of various sizes. Particle sizes one-third the diameter of the pore throat opening are required for bridging. In addition, permeability is reduced by solids that have the ability to deform and compact into void spaces.

The water associated with hydrated solids allows these solids to deform much like water balloons. AQUAGEL GOLD SEAL is such a solid. Polymeric materials like EZ-MUD, DEXTRID, THERMA-CHEK, and PAC products also hydrate. When these hydrated polymers are absorbed by other solids and/or contained in the filter cake, they bond solids together and seal pore spaces within the cake or formation surface.

Hydrated solids are also compressible under pressure. Compressibility is the ability to squeeze together, condense, shrink or reduce in size. As a solid is compressed, some of the outer layers of bound water are forced away from the solid thereby reducing its effective surface area. Compression also allows the electrochemical charges on clay surfaces to be placed at a closer proximity to the surfaces of other solids. This increases the adhesion of solids in the filter cake and is the reason why the filter cake nearest the wellbore or filter medium is dehydrated. In other words, filter cake is progressively drier depending on the pressure and temperature.

Most drilling fluids are designed to prevent hydration of clay solids. However, maintaining deformability with hydrated AQUAGEL GOLD SEAL is difficult in the presence of QUIK-THIN thinner, lime, gypsum, sea water, KCl, and other inhibitive chemicals. Even when prehydrated, AQUAGEL dehydrates in time and loses its effectiveness. Replacement becomes necessary, but when adding more AQUAGEL, care must be taken to prevent adverse effects on the fluid's solids content, rheology, and, in turn, mud stability.

Lubricious and Shearable Filter Cake

A drilling fluid is a "partly solid" lubricant designed to reduce the coefficient of friction between the pipe and the wellbore. This includes the depositing of lubricious solids as filter cake, thereby, reducing pipe drag across permeable sands. Liquid lubricants such as BARO-LUBE GOLD SEAL are used to reduce the coefficient of friction between surfaces. Polymers such as EZ-MUD function as boundary lubricants as they adhere to the surface of pipe and mud solids. These lubricity characteristics provide lower pipe drag and less adhesion between solids.

Toughness and durability have traditionally been desirable filter cake characteristic. However, tests have proven that stuck pipe is often freed as the filter cake shears apart as opposed to metal shearing apart from the cake. This indicates that the so called tough and durable filter cake can actually magnify the problem of stuck pipe.

A slick coating on the pipe and on solids within the cake can reduce stuck pipe frequencies by promoting lubrication between the metal and the cake itself.

Drilling Conditions

Filter Cake/Filtration Control

3

Controlling Filtration Rates/Cake Quality

Filtration Control Mechanisms

There are four basic mechanisms for controlling filtration rates and reducing filter cake permeability. Understanding these mechanisms along with how filtration control products function is important. Most products have primary and secondary functions. How a product affects other fluid properties must be considered as part of the product evaluation process.

Bridging

Bridging reduces filtration rates and permeability by plugging or blocking the pore spaces at the face of the filter medium. It generally requires solids about one-third the diameter of the pore throat opening to form a bridge. AQUAGEL, CARBONOX, BARANEX , DEXTRID, BARACARB, BAROFIBRE, STEELSEAL and other LC materials function as bridging materials.

Bonding

Bonding is the connecting or binding of solids together. THERMA-CHEK, PAC, CELLEX, and other high molecular weight polymers function as bonding materials. Secondarily, PAC and CELLEX function by viscosifying the filtrate, reducing its flowability.

Deflocculation

Deflocculants reduce the electrochemical attraction between solids, allowing solids to be filtered individually, as opposed to flocs. This reduces the void spaces in the cake created by those flocs. LIGNOX PLUS, CARBONOX, QUIK-THIN thinner, and other low molecular weight polymers function as deflocculants.

Viscosity

Fluid loss decreases proportionally to the increase in viscosity of the filtrate. Temperature alone may change the filtrate viscosity, making filtration control more difficult at high temperatures. Any soluble material added to the fluid will viscosify the filtrate. In most cases, this is a secondary affect of a product. Lignosulfonates and low molecular weight polymers increase the filtrate viscosity slightly while high molecular weight polymers and GEM's increase its viscosity to a greater extent.

Controlling Filter Cake Quality

Filter cake quality is influenced by the degree of hydration and flocculation of the filtered solids. The effectiveness in permeability reduction may be demonstrated by a ranking of clay solids according to their surface characteristics:

Dehydrated/Aggregated/Flocculated (high permeability)

Hydrated/Flocculated (medium permeability)

Hydrated/Deflocculated (low permeability)

Drilling Conditions

Filter Cake/Filtration Control

4

Since fluid loss and filter cake quality are important design factors, it is important to understand the predominant electrochemical state of the solids. Initially, cake permeability is reduced as prehydrated AQUAGEL GOLD SEAL is added to the system. When these clay particles become flocculated, they promote deformability and permeability reduction from increased pressure. With deflocculation, permeability is further decreased, as the voids created by the flocs are diminished.

During drilling operations, hydrated solids eventually become dehydrated as the solids content increases and/or the system is converted to an inhibitive fluid. At this point, a decision must be made on the basis of economic and operational objectives. More prehydrated AQUAGEL and/or other products may be added. These other products include CELLEX, PAC, DEXTRID, and FILTER-CHEK. The water content must be increased in conjunction with the additions to allow the products to hydrate and function properly.

Monitoring Cake Quality

Monitoring Permeability of Static Filter Cakes (API, HTHP)

Filter cake deformability is verifiable and can be monitored and recorded daily. Monitoring requires filtration rates at various times and pressures determined with a filter press. Test results are then evaluated based on standard filtration equations.

The first equation states that filtration rates through a fixed filter medium will change in proportion to the square root of time.

Equation:

Q2 = Q1

Where:

Q1 = Filtration rate at 7.5 minutes Q2 = Theoretical rate at 30 minutes T1 = 7.5 minutes T2 = 30 minutes (API)

This equation states that a fluid producing 5 cm3 of filtrate in 7-1/2 minutes will produce twice that value of 10 cm3 of filtrate in 30 minutes. However, if deformable solids are deposited with the initial spurt of filtrate, the filtration rate will be less than the calculated value. This means that the filter cake permeability is decreasing with time and pressure.

A second monitoring technique requires testing filtration rates at two different pressures and the results evaluated based on the equation below:

Equation:

Drilling Conditions

Filter Cake/Filtration Control

5

Where

Q1 = Known filtration rate Q2 = Calculated filtration rate P1 = Low pressure, 100 psi P2 = High pressure, 500 psi

In the equation above, filtration rates through a fixed filter medium change proportional to the square root of pressure. Therefore, a filtration rate of X at 100 psi would then be 2.2X at 500 psi. However, if the solids provide a deformable filter cake, the ratio of the filtration rates will be less than the calculated value. Permeability is then decreased when pressure increases.

Field muds with hydrated/flocculated solids may provide a 500/100 psi filtration ratio of 1.0 or less. A deflocculated fluid with deformable solids may provide a filtration rate of 1.2 or less.

The evaluation of filtration rates and filter cakes at varied times and pressures is more informative than the single data point reported on the standard API report form.

Monitoring Permeability of Static Filter Cakes (PPA)

Permeability under wellbore conditions is somewhat different from the conditions within the API HTHP test cell. However, the principles of filtration and permeability remain the same. The Particle Plugging Apparatus (PPA) simulates downhole conditions at pressures to 3,000 psi, temperature to 500F (260C), and varying permeability using aloxite disks that range from 100 md to 100 darcies.

To reduce permeability, some of the solids initially deposited at the face of a permeable zone must be of sufficient size to bridge pore throats. If not, whole mud will pass through. In addition to bridging, some solids must be deformable. They compact into void spaces to restrict fluid movement.

If the initial spurt loss of the PPA test includes solids or whole mud, the pore throats are not being bridged. This can result in high fluid loss and thick filter cake due to depositing of coarse solids on the filter medium.

An efficient filter cake, as defined by PPA, will have the following:

A low spurt loss with little or no solids in filtrate. Fluid loss values near equal at different pressures. Filter cake thickness near equal at different pressures.

Filtration products should be selected based on temperature stability, particle size, deformability, and bonding ability. A polymer may reduce fluid loss at low pressures; however, it may be blown through the pore space at high pressures. In this case, firm solids like BARACARB or STEELSEAL may be needed to bridge the pore spaces.

Drilling Conditions

Filter Cake/Filtration Control

6

Monitoring Permeability of Dynamic Filter Cakes (FANN 90)

When the drill bit penetrates a permeable zone, solids are filtered from the fluid as the filtrate is forced into the formation by the differential pressure. Some of these solids are washed or eroded from the face of the wellbore by the circulating action of the drilling fluid. When the rate of solids erosion and the rate of solids deposition reach equilibrium, the filtration rate and cake thickness become constant.

As with static filtration, it is important to bridge and seal pore throats with the initial loss of filtrate. This minimizes filtrate loss and filter cake build-up.

When the filtrate process is converted from dynamic to static, cake build-up increases and filtration rate decreases. The effectiveness of the initial filter cake will determine the magnitude of the cake build-up under static conditions.

To minimize "undergauge" hole, the filter cake must be thin. In addition, the cake must be erodible as the filtration process is converted from static back to dynamic. These properties require that the filtration products be properly sized, deformable, lubricious and shearable. Bound water in hydrated solids such as commercial bentonite and polymers gives these desirable characteristics. In most cases, the dynamic filtration rate will be lower after the static period than during the initial dynamic phase.

When solids have low water contents, the electrochemical charges on the surfaces of the solid are placed in a closer proximity to the charges on other solids. The electrical attraction between these solids along with the compaction under pressure makes them very difficult to separate. As a result, a thick and tough filter cake may be formed, resulting in an undergauge wellbore and stuck pipe potential.

Dynamic filtration can be evaluated in the laboratory using the FANN 90 under a variety of different conditions, including various shear rates, pressures, temperatures, and filter medium permeabilities. As with the PPA test, the object is to achieve fluid loss control with thin filter cakes while varying the test parameters.

It is important to know the composition of the fluid and the filtration characteristics of all the elements within a fluid to make a logical evaluation of the fluid and recommendations for adjusting filtration rates.

The maximum acceptable values for the dynamic filtration rate and cake deposition index (CDI) are shown in the table below.

Mud Weight lbs/gal Rate, ml/min CDI

9-14 0.16 22

14 or greater 0.12 16

Filtration Control Versus Stuck Pipe

Prevention of differential pressure sticking is a primary function of drilling fluids. The formula for differential pressure sticking is:

Drilling Conditions

Filter Cake/Filtration Control

7

Vertical Pull = (Differential Pressure, psi) (Area of Contact, in2) (Coefficient of Friction)

The differential pressure (psi) is the difference between the hydrostatic pressure of the mud column and the formation pressure. To be able to minimize differential pressure, the mud chemistry must have a stabilizing effect on the shale or wellbore. This prevents the need for excessive mud weights to maintain wellbore stability.

The area of contact (in2) is determined by pipe and hole diameters along with filter cake quality. Thick and soft filter cakes allow greater contact as the pipe embeds into the cake. As the area of contact increases, the total horizontal force increases as a product of the area of contact and the differential pressure. Effective solids control and a thin impermeable cake on the wellbore will minimize the area of contact.

The coefficient of friction defines a lubricity characteristic. As the lubricity of the fluid and cake improves, the vertical pull required to move pipe decreases as a product of the coefficient of friction and the horizontal force. Lubricants and/or lubricious solids allow the pipe to slide past permeable zones. Further, this allows the solids within the cake to shear apart more easily. This facilitates the prevention of stuck pipe as well as the freeing of pipe that has become stuck.

Drilling Conditions

Fluid Displacements

1

SOP Code: D Revision Date: 03/14/1997; Amended May 2005

Fluid Displacements

Introduction

When displacing fluid in a wellbore over from one type to another, the most important factor is to create a sharp interface between the two fluids to minimize contamination and waste. Steps must be taken to minimize channeling and ensure as complete a removal of the fluid being displaced as possible. Specially designed spacers are formulated to provide separation of the fluids whether the displacement is mud to mud, brine to mud, or mud to brine.

Displacement methods include direct and indirect. Direct displacement is used when the fluid is displaced directly with a displacement fluid. Indirect displacement uses large amounts of water to flush out the wellbore before circulating the displacement fluid.

When displacing in cased hole, the densities of the fluids should be considered to determine the best way to line the pumps up for maximum efficiency in displacement. If displacing a heavy fluid with a fluid of significantly lighter density, pump down the annulus and up the work string (reverse). If displacing a light fluid with a significantly heavier one, pump down the string and up the annulus (conventional). These displacement methods will minimize the interface between the fluids and unnecessary costs from fluid waste.

Mud to Mud

Adjust the rheological properties of the fluid being displaced out of the well to achieve the lowest practical yield point. Formulate a spacer of appropriate volume to provide a minimum of 500 ft of length of the annulus which will be compatible with both fluids and of the appropriate density. All fluids should be similar in rheological profile to minimize the potential for channeling. Flush and clean all surface lines, tanks, and manifolds that will contact the displacement fluid. Secure all water outlets to prevent dilution and/or contamination of the displacement fluid.

Displace by pumping down the drill pipe and up the annulus. Once displacement begins, do not stop the pumping operation. Rotate and reciprocate the drillpipe at least one joint every 15 minutes to minimize channeling in the annulus. Always monitor returns and pump strokes in order to confirm break through of the new fluid. After break through occurs, shut down pumping and perform a mud check on a flowline sample for confirmation.

Mud to Brine

Initial Rig Preparation

Cleanliness

Clean working practices and good housekeeping cannot be over-stressed when displacing to a completion fluid. All rig pits, ditches, and lines (including gun lines) should be scrupulously cleaned using degreasing solvents and detergents. They should be rinsed out and if possible squeegeed dry. If it is practical, lines should be opened to check for any mud solids that might have settled in them. All the pits, sandtraps, and under the shale shakers should be cleaned out

Drilling Conditions

Fluid Displacements

2

and washed down using high pressure cleaning equipment. In the pit room, all gratings should be cleaned, all the lights and beams should be washed down. If heavy brines will be used, all water hoses should be checked and if not necessary should be blanked off. All cleaning should be done well in advance wherever possible. It is far better to do a little bit of extra cleaning than to have a delayed operation due to dirty tanks. To clean pits and lines, 100 bbl (16 m3) of 2% BARAKLEAN NS PLUS should be mixed up and circulated through all lines, gun lines, mixing lines etc. This can also be used to clean the tank system initially.

Valves and Seals

All dump valves should have the seals and valve seats checked to ensure they are in good order. They should be greased to ensure a good seal and if possible should be manually guided and checked when being closed to ensure a perfect fit. All ditch gates should be sealed with silicon on each side of the gate. This will need to be replaced if the gate is opened. UNDER NO CIRCUMSTANCES SHOULD BARITE, BENTONITE OR POLYMERS BE USED TO SEAL ANYTHING.

Potential Leak Situation

All pump packing should be examined and if necessary replaced. One barrel of expensive brine buys a lot of pump packing and any suspect packing is best replaced ahead of time. Packing should be lubricated with grease. Water can all too easily leak into the system and can obscure brine leaks. Packing should be lubricated on a regular basis to ensure minimal losses.

Displacement

If the bond logs and casing strength data indicate that the casing will withstand a calculated pressure differential, an indirect displacement procedure should be used. This procedure uses large quantities of seawater to flush the well resulting in a clean, solids free displacement, reduced spacer costs and lower filtration costs. When applying the indirect method one has to ensure that the pumping pressure will not exceed the collapse or burst strength of the casing. If bond logs indicate that the casing will not withstand the differential pressure, the direct displacement procedure should be used. This method does not obtain a clean displacement and expensive filtering will be necessary. However, undesirable pressure situations are eliminated because the direct method maintains a more constant hydrostatic head.

Deviated/Horizontal Concerns

For deviated and horizontal wells, particular attention should be paid to the flow regime. The use of weighted push pills will minimize channeling and ensure good cleaning of the low side of the wellbore. The drill pipe should be rotated and reciprocated during the clean out. The push pills should be circulated through the deviated section at a pump rate that will ensure plug flow. When the push pills are out of the highly deviated sections, the pump rate should then be increased as the detergent and flocculant pills pass through the interval to ensure good hole cleaning and scouring/removal of mud adhering to the tubular goods.

Preparation of the Mud System

The rheological properties of the mud system should be adjusted, to achieve a yield point as low as is practical, before the displacement is started. If the well is deviated, care should be taken not to reduce the values too far as barite sag could then be a problem. With the mud system treated and the surface equipment prepared, the following sequence of pills should be mixed and

Drilling Conditions

Fluid Displacements

3

pumped. To achieve effective cleaning of the casing, this sequence of pills should be pumped and displaced using maximum pump rates, rotating and reciprocating the pipe whenever possible. It is advisable to have at least 500 ft (153 m) of pill/spacer or 3 mins contact time at the highest pump rates.

In detail, the sequence of pills should be as follows:

1. Weighted Push Pill

50 bbl (8 m3) BARAZAN PLUS/Barite/Seawater (or freshwater)

To push the mud out of the well, minimizing channeling and contamination.

Annular coverage 9 5/8" / 5" +/- 1,000 ft (350 m)

Time of coverage 8 mins

Make up: Add 2-3 ppb (8-10 kg/m3) XCD Polymer to seawater (or freshwater), weight up to 0.2 ppb (0.025 SG) greater than the active mud weight. Add 1 drum of BARAKLEAN NS to the pill.

2. Caustic Pill

35 bbl (5.6 m3) Caustic Pill

To remove mud from the casing walls.

Annular coverage 9 5/8" / 5" +/- 700 ft (215 m)

Time of coverage 4 mins

Make up: Add 3 to 4 ppb (8 to 10 kg/m3) of Caustic Soda to 35 bbls (5.6 m3) of sea water (or freshwater). Care should be taken when mixing this as the pill will have a very high pH. Any splashes must be washed off immediately. Full-face masks must be worn when mixing.

3. Solvent/Surfactant Pill

300 bbl (48 m3) BARAKLEAN NS pill

To clean and water wet Tubing and Casing

Annular coverage 9 5/8" / 5" 6,000 ft (1,830 m)

Drilling Conditions

Fluid Displacements

4

Time of coverage 10 bpm (1,600 ltr/min) 30 mins

Make up 8 drums of BARA KLEAN-NS mixed in 290 bbl (46 m3) of sea water (or freshwater).

4. Flocculating Pill

200 bbl (32 m3) BARAKLEAN NS pill

To flocculate remaining mud and solids and clean the casing

Annular coverage 9 5/8" / 5" 4,000 ft (1,220 m)

Time of coverage 10 bpm (1,600 ltr/min) 20 mins

Make up: 5 drums BARA KLEAN FL in 195 bbl (31 m3) of seawater water (or freshwater).

Flow rates should be as high as possible subject to pressure drop limitations, and 10 bpm (1,600 ltr/min) should be achievable.

Excessively high pump rates over 13 bpm should be used only when the concentration of chemicals is increased. There is a contact time required for the chemicals to work effectively, and one normally aims to have a minimum of 3 minutes at the maximum pump rates. These pills should be displaced from the well using the appropriate density brine in a direct displacement and seawater/water in an indirect displacement.

Pump strokes should be monitored to confirm the break through of the various pills and final completion fluid.

Only clean seawater / brine should be pumped into the well, that is to say, returns should not be pumped straight back down the well. They should be taken into one pit and then pumped via the filter unit into the section tank until returns from the well are to the required specification. When the returns have been recorded at the required standard of cleanliness for three consecutive readings with an interval of 15 minutes between each reading the sequence of operations can continue. If the seawater / brine does not clean up to the required standard, a further pill of 100 bbl (16 m3) seawater / water with 2 dms of BARA KLEAN NS should be pumped.

Displacement Procedure for Invert Emulsion Muds

Invert mud/base fluid should not be brought on board until rig containment measures have been fully discussed with all rig crews and implemented. All surface pits, sand traps and mud lines should be thoroughly cleaned and drained. The following rig modifications / considerations should be made:

Disconnect all water lines located near the surface mud system. Ensure all wash guns at the shakers are connected to a base fluid supply.

Drilling Conditions

Fluid Displacements

5

A drain box should be installed around the pipe stacking area. This box should have a connection going to the flowline or bell nipple.

Utilize a pipe wiper to keep the pipe dry and to salvage mud. If possible, use a flared bell nipple. Ensure that all elastomers in the circulating system are resistant to the base fluid being used.

This includes pump parts, pipe protectors, etc.

Prior to displacement, the water-based mud in the hole should be treated to reduce the yield point and gel strengths. This is particularly important if the mud has been used to drill cement. Generally, the cost to condition the water-based mud will be less than reconditioning the invert mud contaminated due to a poor displacement.

Prepare a spacer pill by treating 30-50 barrels of the invert mud with GELTONE to raise the yield point to 50+. This will provide a yield point at the interface great enough to exceed the critical yield needed to flush water mud from the annulus, even where the drill pipe is not concentric relative to the casing. Start displacement by pumping the spacer followed by the invert mud. Water-based returns should be directed from the flowline to a reserve tank if it is to be salvaged, otherwise it should be discarded over the shakers. Sufficient volume of invert mud will be required to displace the hole and enable drilling to proceed without the need to mix new volume. By having sufficient reserve volume of pre-mixed mud available, the mud engineer and the rig crew will be free to concentrate on the maintenance of the active.

Reserves of base fluid should be kept on board in storage for dilution, base fluid-water ratio adjustments and weight reductions. The mud should be displaced using normal flow rates for the section while rotating and reciprocating the pipe to reduce channeling. Reciprocate the drill pipe a length of one joint every 15 minutes. Pump rate during displacement should be normal, and continuous, until the displacement is complete.

When the spacer is observed at the flowline, returns should be diverted to a reserve pit for future reconditioning, and the invert mud should be diverted to the active system, completing the displacement. No invert mud should be discharged as waste.

The hole should be circulated to an even mud weight prior to conducting any shoe bond integrity tests. Invert mud properties are temperature variant. Until the invert mud has been sheared by the bit and its temperature increased, coarse screens should be used in the shale shakers (80 mesh). As it heats up and becomes less viscous, these should be changed towards the smallest size which can handle the cuttings and flow rates required.

Considerations for PETROFREE

Displacement procedures for PETROFREE will be the same as above with the following exceptions / considerations:

All active and reserve mud tanks along with all Ester storage tanks and lines must be thoroughly cleaned out to remove any trace of mineral oils or diesel.. Rubber valve seals and hoses should be checked and replaced if necessary to prevent mud loss or contamination.

Every effort should be made to eliminate surface losses of PETROFREE. Check the layout and operation of all solids control equipment prior to displacing to the PETROFREE. Special attention should be given to the centrifuge plumbing, etc. System maintenance costs for

Drilling Conditions

Fluid Displacements

6

PETROFREE will result from volume building due to new hole drilled and surface losses. Normal surface losses can be held to a minimum using the following techniques.

Use a mud saver sub. The use of this will reduce losses on connections. Use pipe wipers to remove oil mud from the drill pipe during trips. Install a catch pan on the top of the bell nipple. This must be large enough to extend beyond

the edges of the rotary table. This device will catch mud which falls through the table and will divert it into the drilling nipple.

Provide a racking pan for the drill pipe. A return line from this pan must be run to the flowline or into the catch pan as described above.

Use a mud box on trips. A mud box in good condition will prevent serious losses when pulling a wet string. The mud box should be connected to the flowline or catch pan.

As with displacing invert muds above, keep water hoses off of the rig floor and away from the mud tanks. Water additions to PETROFREE mud should be made only upon the recommendations of the fluid engineer.

PETROFREE, when initially mixed and unweighted, will have a low yield point (6-8 lb/100 ft2) until the mud has been sheared through the bit. The mud should be weighted to the desired density and circulated/sheared to help YP development.

Do Not add