TYPES OF COMPLETION / WORKOVER FLUID

Prepared by:Ajesh Trivedi: 11BPE054Bharatsai Alla: 11BPE057Saurabh Pancholi: 11BPE064Neha Patel: 11BPE053Deepak Dalal: 11BPE007Pankil Patel: 11BPE033Bharat Baghel: 10BPE045

INTRODUCTION• The commonly used workover/ completion fluids can be grouped under following broad categories:

1. Water based fluids A. Clean, solids-free brines B. Viscosified Brines C. Conventional water base muds D. Clear-water fluids2. Oil3. Oil base fluids

• Clean, solids-free brines can be further classified as: 1. Clean solid-free single salt brine 2. Clean solid-free multiple salt brine

WATER BASE FLUIDSA.1. Clean solid free-single salt brine

• These brines are true solutions, meaning that they contain only water and dissolved salts (ions), with no un-dissolved solids.

• They may be used as single-salt brines or mixture of two or three different salt compounds.• These brines are made with fresh water and one salt.

• Advantages: 1. Solids-free2. Inhibitive

3. Available in a wide density range. 4. Capable of being reclaimed for reuse.

•DIFFERENT TYPES OF SALTS USED ARE:1. Ammonium Chloride (NH4Cl)• It can formulate clear fluids to a density of 9.0 lb/gal.• Used as a clay and shale stabilizer in gravel pack and acidizing operations where its compatibility with

hydrofluoric acid is a benefit.

2. Potassium Chloride (KCl)• Excellent completion fluid for water sensitive formations.• Clear fluids up to a density of 9.7 lb/gal can be prepared.• Corrosion rates are reasonably low and can be reduced even more by maintaining the pH between 7-

10 and using a corrosion inhibitor.

3. Sodium Chloride (NaCl)• Maximum density possible is 10 ppg.• The most commonly used brine.

4. Sodium Formate (NaCOOH)• Density up to 11.0 lb/gal can be achieved• Better HSE characteristics than chloride and bromide brines.

5. Calcium Chloride (CaCl2)• Used to prepare clear fluids up to a density of 11.8 lb/gal. • Dry salt must be added very slowly to prevent boiling.• Care should be taken to ensure compatibility with reservoir fluids due to the divalent calcium.• The corrosivity is comparable to KCl brine and require a corrosion inhibitor.

6. Sodium Bromide (NaBr)• Used for density up to 12.8 lb/gal.• Used as an alternative to calcium base brines when formation waters contain high

concentrations of bicarbonate and sulphate ions.

7. Potassium Formate (KCOOH)• It can give density up to 13.2 lb/gal.• Show excellent thermal stabilization effects on natural polymers and the potassium ion

provides excellent clay stabilization and swelling inhibition of shales.

8. Calcium Bromide (CaBr2)• Calcium bromide solutions can be prepared to a density of 15.5 lb/gal.• Like calcium chloride, calcium bromide generates heat when dissolved in water, similar

precautions should be observed.

9. Cesium Formate (CsCOOH)• Cesium formate is being produced as a 19.7-lb/ga liquid. • Cesium formate also produces excellent thermal stabilization effects in natural polymers, and

provides clay stabilization and inhibits swelling of shales. • Formate-base brines have better Health, Safety and Environmental (HSE) characteristics in

comparison to chloride and bromide brines.

A.2. CLEAN SOLID-FREE MULTIPLE SALT BRINE• When the brine densities greater that 11.6 ppg are required, the use of two or more salts is usually preferred

instead of single salt due to economics.

1. Calcium Chloride/ Calcium Bromide:• Most common two salt brine .• The base ingredients of CaCl2/CaBr2 brine are a calcium bromide solution of about 14.1 to 14.3 ppg. The pH

range is 7.0 – 7.5.

2. Zinc Bromide/Calcium Bromide• Available as stock liquid weighing 19.2 lb/gal. • It is very expensive and is frequently blended with additional calcium bromide or calcium chloride for greater

flexibility and economics. • The maximum density for zinc bromide blends is 20.5 lb/gal.• The discharge of zinc to the environment is often restricted. • Due to the high concentration of dissolved salts and the low pH, zinc bromide brines must be handled with

maximum safety precaution.

B. VISCOSIFIED BRINESViscosified brines are used where additional parameters like bridging, suspension, fluid loss control etc are required.

Specially designed brine/polymer systems can be classified into three major types:1. Acid-soluble brine/polymer systems, usually sized calcium carbonates.2. Water-soluble brine/polymer systems, usually sized salt.3. Oil-soluble resin brine/polymer systems.

1. BRIDGING / WEIGHTING AGENTSDifferent types of bridging/Weighting agents used are:

High purity acid-soluble calcium carbonate • Available in three standard particulate sizes: Fine (F), Medium (M) and Coarse (C). • They are used for fluid-loss control in brine-polymer systems.• A proper blend of all three grades helps in excellent fluid loss control.• It has good temperature stability, non-toxic, non-corrosive.• It is least damaging, if size of particles is suitably chosen and the pill is placed properly. • It is insoluble in formations fluids and can be completely dissolved by 15 % HCI.

Oil soluble resins and sized Sodium chloride salt • Wells with formation temperatures bellow 162 deg C (resin softening point) and producing either

aromatic crude or condensate, sized resin bridging particles should be considered because of the assured self removal by dissolution.

Sodium chloride (NaCl) • It has more versatility than either calcium carbonate or resins but its use in low pressured formation is

limited by its high saturation density (1200 kg/m3).• Sodium chloride (sp. gr. 2.18) as bridging particle is truly non- damaging. Sized salt particles have same

thermal stability as calcium carbonate.

Micro sized cellulose fibres • They have good sealing characteristic and effectively stop fluid loss.• Length of these fibres is normally 2-200 micron and diameter 20 micron and is used for seepage and

whole fluid loss control. • Lack of acid solubility restricts their use, as complete removal of fibres is not ensured. • The use of these fibres is restricted in producing formations because of their general lack of acid

solubility.

2. VISCOSIFYING AGENTS• Brines have a natural viscosity that depends on the concentration and types of salts in the blend.• The Yield Points (YP) of clear brines is very low. This reduces their ability to carry or suspend solids.• Viscosifying agents or polymers and high annular velocity are used to overcome the low carrying

capacity of brines and to control fluid losses to the formation.• Once the brine is circulated back to the surface, it can be processed and filtered before being

pumped back down the hole.• The most common polymers used as Viscosifying agents are:

I. HECII. GUARIII. XC PolymerIV. CMCV. Starch and VI. PAC

3. MIXING OF POLYMER• When a water-soluble polymer is added to water, part of the polymer gets partially hydrated

and becomes semisolid called “fish eyes”. • The size may vary from few microns to several centimetres.• Depending upon the process of addition of polymer powder to brine, fish eyes of sizes from

several microns to several centimetres are formed,• The fish eye formation can be avoided by following two methods.

1) Prepare thick paste of HEC powder in a medium in which hydration of HEC does not take place like alcohols, glycol, hydrocarbons etc. and then add to brine.

2) Adjust PH of the brine to 5.5 - 6.0 by adding HCL or Citric acid. Add HEC and mix for 15 minutes. After HEC powder is properly dispersed in brine, raise pH of the of brine to 8.0 - 8.5 by adding sodium hydroxide at shear rate of 100/sec.

C. CONVENTIONAL WATER- BASE MUDS• Using conventional water-base drilling mud for completions or workover operations is not advisable unless we are sure

that they will not damage the formation.• Clays, weighting material and other additives present in these muds can cause severe and permanent damage to

producing formation.• However in recent years the non damaging fluids grouped under “Drill in Fluids” have been designed and used for

drilling and completion of reservoir sections. The use of these fluids as workover fluids may prevent formation damage.

D. CLEAR-WATER FLUIDS• Low salinity water such as seawater or produced brines are occasionally used as workover and completion fluid. • Many a times formation water contains fine solids, paraffin, asphaltene or scale which, if not controlled, may cause

serious formation damage.• The water should be filtered before use.• Seawater, which is frequently used in coastal areas due to its easy availability, usually contain potentially damaging solids

or multivalent ions, such as Ca2+ , Mg2+ and Fe3+ , microorganisms (Bacteria), high conc. of sulphates and hence need processing prior to use as workover fluids.

• It may be necessary to add 3-4 % KCl or NH4Cl to avoid clay swelling.

2. OIL

• In most producing areas, oil is plentiful and makes it economical to use as workover /completion fluid. It is usually non-corrosive and does not cause clay swelling in producing zones. It weighs about 7 ppg, which is excellent for low pressure oil field.

• It has lots of disadvantages:

• Usually contains wax, fine particles of sand, solid or asphalts that can damage the formation.• It is corrosive if H2S or CO2 is present.• It is a fire hazard and difficult to handle• Oil may not be compatible with the reservoir oil if it is obtained elsewhere in the field.

3. OIL BASE FLUIDS

• Oil-base invert emulsions fluids are sometimes used as completion and workover fluids. In these generally the Calcium Chloride brine is emulsified in oil, so that the oil is the external or continuous phase.

• Oil-base fluids are often formulated with acid-soluble bridging/weighting agents so that any residual filter cake or solids can be acidized for removal.

Advantages Disadvantages

• Relatively low cost and wide availability.• High-temperature stability.• Wide density range.• Low corrosion.• Handling and disposal issues• Be restricted for environmental reasons• Change the wettability of the formation.• Maximum inhibition.• Minimum filtrate invasion• Resistant to contamination• Cause emulsion blocks.• Damage dry gas sands.• Increase safety concerns.

4. BRINE BASED WORKOVER FLUIDSelection criteria:

• The brine based fluids are most favoured as completion and workover fluids. • Addition of various salts to fresh water has several beneficial effects. Salt will increase the density of the fluid for

greater hydrostatic pressure control without increasing the solid concentration.• In addition, salt in fresh water creates an inhibited fluid that minimizes clay hydration and results in less formation

damage.

To select brine based workover/ completion fluid, following parameters should essentially be considered:• Fluid density• Wellbore temperature.• Crystallization temperature.• Formation compatibility• Corrosion control.• Health, Safety and Environmental (HSE) characteristics.• Economics.• Suspended Solid

Fluid density

• The primary criterion for fluid selection.• Should be equal or higher than the formation pressure except for underbalanced pressure situations,

where it should be enough only to control the underbalanced portion of reservoir pressure.• Commonly used overbalance levels are 200 psi for oil wells and 300 psi for gas wells and are sufficient

to control the entry of formation fluid under swabbing situations.• Balanced or underbalanced workover operations are ideal for prevention of formation damage but

should be performed with proper equipment.

Wellbore Temperature

• The density of a brine decreases as the temperature increases. Hence bottom-hole temperature, both static and circulating, is an important factor in selection of brine.

• Correction in density for temperature and pressure must be made for avoiding well control problems.• Temperature and the exposure time affects the stability of various additives, corrosion rate etc. and

may dictate the choice of additives and corrosion inhibitors.

Crystallization temperature.

• Crystallization point is the temperature at which salt crystals will begin to fall out of solution given sufficient time and proper nucleating conditions.

• The precipitation of insoluble salts can cause a number of problems like drop in fluid density, choking of lines and seizing of pump.

• Unlike water, brines do not expand during crystallization. Therefore, fluid lines, valves or pump heads will not rupture as they can when water freezes.

• Several salt blends can be formulated for a particular density, each having a different crystallization temperature.

Formation compatibility

• The compatibility of brines with the formation is another important issue for selection of brine as incompatibility will lead to formation damage resulting in loss of productivity. The filtrate characteristics should be tailored to minimize formation damage considering

• Clay swelling• Clay dispersion/fine migration• Wettability change• Emulsion formation• Sludge formation• Scaling tendencies

Compatibility with the rock

• Brine should have compatibility with formation rocks so as to prevent swelling, deflocculating and/or migration of formation clays, especially in “tight” high-clay sandstone.• Some salts are better clay stabilizers than others, and can prevent clay swelling and

migration. NH4Cl (3%) or KCl (3%) are the two inhibitive salts frequently used in seawater for workover operation.

Compatibility with formation water

• Brine should have compatibility with formation water. A incompatible brine may result in the formation of scale.• Scales are deposits of inorganic minerals and can form due to mixing incompatible waters,

solubility changes with temperature, solubility changes with pressure and water evaporation.• Most common cations responsible for scaling are multivalent cations such as calcium (Ca2+),

magnesium (Mg2+) and iron (Fe3+).

Compatibility with hydrocarbon

• Any incompatibility between brine and hydrocarbon may result in formation of oil/water emulsions and/or sludge, both of which cause severe formation damage by blocking pores.

• Brine/crude incompatibility is especially important when lowpH, heavy brines are used. Natural gas if rich in CO2 may cause calcium carbonate to precipitate if mixed with a high pH brine that contains calcium.

Corrosion control

• The brine should not cause much corrosion to tubular and down hole equipment.• Salt solutions are often highly corrosive. Dissolved oxygen is the primary corrosive agent in sodium,

potassium, calcium, chloride or bromide-brine base completion fluids.• The solubility of oxygen in these brines decreases as saturation with the salt is approached.• High-density zinc bromide blends are used in very high-pressure situations for well control. These brines

have a low pH. Raising the pH would be detrimental, causing precipitation. The acidity of the zinc can cause severe corrosion, unless proper protection is provided with an appropriate corrosion inhibitor.

• Most oilfield zinc bromide completion brines contain a thiocyanate (or other sulphur-base) corrosion inhibitor that forms a protective film on the surface of steel.

Health, Safety and Environmental (HSE) characteristics.

• If brine comes into contact with eyes or skin, or if ingestion or inhalation is suspected, take the following first-aid measures:

• Eyes: Flush eyes promptly with plenty of water • Skin: Flush skin with plenty of water with soap.• Ingestion: Consult the material safety data sheet for response information and get medical attention.

Economics

• The brine which is most economical, easily available and meets the above requirements should be considered for use. The Reuse, Recover, Recycle of these brines further improves the economics.

Suspended Solids

• It is also critical to minimize the level of total suspended solids in the completion/ workover fluid to minimize formation damage from suspended solids.

• This damage is caused by plugging of pore channels by suspended solids in the completion or work over fluid.• This can be avoided by filtering the brine through very fine filters.

WORKOVER FLUID FOR SUB-HYDROSTATIC WELLSThere are two types of fluids:

1. Circulating Fluids 2. Non Circulating Fluids (Pills)

1. CIRCULATING FLUID

1.1 Oil / oil based fluids

• Circulating fluid either oil (petroleum or petroleum product) or oil based (emulsion) can be formulated in the range of sp gr between 0.9 to 1.0 or more.

• But lower sp gravity fluids are difficult to formulate. Use of oil and oil-based fluid is limited due to difficult handling and disposal.

• They have risk of fire and explosion.• The criteria that govern their use, as workover fluid is high flash point and/ or low vapour pressure at operating conditions. • Diesel oil is the most commonly used oil phase.• The advantage to use diesel to workover well is that it is less damaging to the productive formation than any other oil.

1.2 Gas fluid

• Gas can be used as completion and workover fluid in some low-pressure reservoir. • During operation, flow from the well is controlled only by surface backpressure. Nitrogen gas is

commonly used in operations such as hole cleaning by foam, well activating, proppant transportation, DST, dry perforation and nitrified acidization etc.

1.3 Foam Fluids

• Foam acts like a pseudo plastic fluid and its stability is hardly affected as long as it is in the dynamic state.

• Foam can be used for sand washing, re-completions and CTU jobs.• Foam has low density, high effective viscosity and high carrying capacity making it a very good

workover medium• Foam can be used as completion and workover fluid to deal with low-pressure gas wells as it does

not invade the formation in underbalanced condition and hence avoid formation damage.• Air foam has a risk of fire/explosion also.

1.4 Viscosified brines

• Use of viscosified brines does not completely control loss of fluid in the formation and continuous loss of fluid takes place at reduced rates.

• Particulate (Calcium carbonate, resins, micronized cellulose fibres etc.) loaded viscosified brines are used as circulating fluids for temporary plugging of formation pore throats.

• The effectiveness of the system is a function of quick formation of a thin cake around the well bore.• However, they suffer setback of severe solid settling in well bore in static state. Due to this reason use

of such type of workover fluids is very limited.

2. NON CIRCULATING FLUIDPills (linear, cross linked gels and particulate) are used worldwide to control fluid loss in depleted/sub-hydrostatic wells. Pills are very cost effective and easy to prepare. The various non-circulating fluids are:

I. Polymer pillsII. Particulate pills

Polymer pills

• Various polymers commonly used are guar gum, CMC, Xanthan, HEC etc. Whether the linear or cross-linked gel will enter the formation or not is generally dependent on polymer type and concentration, pore throat sizes, over balance head and bottom hole temperature. Salient feature of polymer pill are:

• Pills (gels) can be removed from the throats of pores of formation by application of a breaker.• Longer break time may be achieved but is a risk as minor chemical variation may not allow a

total breakdown of the gel and hence permanent formation damage may be caused.• Success of linear or cross linked gels in controlling fluid loss is marginal because the polymer

molecules have a very high affinity for each other and their attraction for the formation grains is low.• Polymer/ pill may fill the well bore, their ability to form a low permeable plug is limited and

fluid passes between gel plug and the wall of the borehole in the formation.

Particulate pill

As the polymer gels do not completely stop the fluid loss in the formation, temporary plugging of pore throats by addition of sized solid particles in polymer gel becomes the choice of preference and such type of pill is called particulate pill.

Solids particles used for plugging/blocking formation are called bridging or blocking agent.Blocking agents act as inert particle in the pill and are least damaging, if properly sized.Blocking agents with polymer, forms a temporary thin plug like mud cake and seals formation pores.Temporary plug or bridge can be removed by washing or dissolved by chemical treatment.Besides restricting the flow of fluid near well bore, polymer in the pill consolidates bridging particles on

pore throats of formation.Guar gum, CMC, HEC, Xanthan etc are common polymer used.Bridging material are typically sized Calcium carbonates, Salts, Resins and Micronised cellulose fibres.A typical pill contains sized bridging material and polymer solution in brine (viscosified brines)

Mechanical fluid loss control systems

• Mechanical fluid loss control systems are essentially downhole equipment, installed in a well for either temporary or permanent blocking of fluid flow in the formation.

• They are expandable plug or sliding sleeve type of communication device installed for future application. • Elastomeric and metallic components of these devices must be compatible with formation fluid.• Such devices are glass disk assembly, frangible flappers, ball-dropper fluid loss device, tubing latched plug,

hydraulic reverse operated flapper, packer plug, tubing plug, acid soluble plugs etc.

Displacement of mud with brines during completion

• The displacement system is designed to maximize mud and solids cleanout in one pass through the wellbore.

• Certain displacement processes or procedures are common to any type of fluid displacement, be they OBM/SBM or WBM.

• The use of clean brine fluid alone does not guarantee success of job. • All the components involved in circulation, including storage tanks, solids removal equipment, manifolds,

pumps, discharge lines, return lines and the wellbore should also be free from solids.

Preparing the wellbore

• Having a well-conditioned drilling/ workover fluid is the single most significant factor in obtaining effective mud displacement.

• Thoroughly fluidize the mud before displacement. To further improve its mobility, the viscosity, YP and gels of the drilling fluid should be reduced, if possible, during the pre-job circulation period.

• Displace the completion fluid at the highest displacement rates and if possible under turbulent flow conditions.• The pipe movement (rotation or reciprocation) helps break up pockets of gelled mud and loosens cuttings. • This is more important in wells which are not truly verticals and where string is not positioned concentrically in

the hole. • Rotation also distributes the flow path of the displacement fluid across the entire hole section.• Mechanical scratchers or scrapers attached to the drill string can further enhance the beneficial effects of pipe

movement