Unit -7, Work Over Operations

UNIT -7 WORK OVER OPERATIONS

TUBING AND DRILLING PIPE HANDLING 1.0 HANDLING OF TUBULARS Tubing and drill pipes are major equipment in work over operations. It is very important to know its material and physical properties.  The following API standards pertain to tubulars.:API specification 5A --casing, tubing and drill pipes API specification 5B --- Restricted yield strength of casing and tubing. API specification 5AX– High strength casing ,tubing and drill pipe API Bulletin 5C2 -- Performance properties of casing and tubing API Bulletin 5 C1 --- Care and use of casing and tubing  Steel Grades The normal API steel grades for tubing are : 5A -- H-40, J-55 , K-55 , N-80 5 AC --- C-75 , L-do , C-95 5 AX --- P-105 ( now it is P-110) C-75 and L-80 are suitable for H2 S service . L-80 grade is further has hardness restriction of not exceeding 23 RC.  Colour codes J-55 -- Green band K-55 -- two green C-75 -- Blue L-80 --- Red with brown band N-80 --- Red C-95 --- Brown P-105 --- white

1.1 Tubing Connections: • Standard API Couplings API Non Upset ( NUE) a. !0 round threads b. Less strength than pipe body API External Upset (EUE) a. 8 round threads b. Joints have greater strength than pipe body • Extra clearance coupling a. without loss of joint strength b. have greater clearance for critical applications • Internal joint connections a. have greater clearance b.there is no separate coupling  Premium Joints a. have metal to metal seals, much higher pressure ratings than API joints b. suitable for high pressure /corrosive environments c. There are many manufacturers ,like Vam , Hydrill , Nippon kokkan , Atlas Bradford , TDS-Mannesman, Baker Hughes, Siderca TDS-T6 d. These threads provide gas tight seals e. Costlier than API grade tubing

 1.2 Care and handling of tubular 1.21 Tubing • All tubing whether new ,used, or reconditioned with always be handled and stored with thread protectors. • Tubing tongs which will not crush the tubing should be used . • Connect the tubular vertically and after stabbing, start screwing by regular or power tubing tongs . Try to use torque turn equipment to screw and measure the recommended make up torque. • Breaking the tubing during pulling out should be carefully. Do not hammer the coupling to break the joints. Disengage all the threads before lifting up. Do not jump the tubing out of the coupling. • Tubing stacked in the derrick should be set on a firm wooden platform and without thread protectors. Protestors are not designed to support the load of the tubing (in doubles) , it will damage the threads.Drill Pipes 1.22 Drill Pipe • Drill pipes are used to transmit power rotary motion rig floor level to to the bottom of the hole for drilling. • Convey flushing fluids to the cutting face of the bit so as to circulate out the drilled rock cuttings. • API recommended practice API RP 76 gives guielines for Drill pipe classes. • Drill pipes are available in following ranges Range Length(ft) 1 18-22 2 27-30 3 38-40 Handling of Drill pipes  Use only rotary table slips in order to prevent circumferencial cuts .  Kelly must be kept straight at all times  Box and pin connections should be made up to the right torque. In case of releaasing stuck up, be sure that weight indicator is in working order.

PRODUCTION TUBING 1.0 PRODUCTION TUBING 1.1 FUNCTIONS OF TUBING :  It is essentially for well killing, circulation, workover  Tubing provides optimized flow conduit to produce at efficient rate from a well.  Tubing is used to isolate casing from high pressure effect,high temperature effect and effect from corrosive fluid.  It facilitates well completion and control of a well in a multiple completion  It facilitates all through tubing wireline or cable logging (PLT), thru tubing perforations `1.1 SELECTION OF TUBING  The tubing size for a well is selected to a. to handle present well production rate b.to be suitable for any future artificial lift completion and production rate  Special functions and fluid handling conditions must be clearly spelt out  While selecting the tubing size ,the reservoir performance like pressure , drive mechanism, future production performance with type of lift, the type of workover jobs anticipated should be evaluated  All the projected operating conditions analyzed using IPR and tubing intake curves (TIC)  All through tubing jobs like wire line , coiled tubing, logging must be evaluated .  The clearance between casing I.D and coupling O.D should be sufficient to allow pasasge of all completion and A/L equipment. As general rule this clearance should not be less than 8 mm. In case sand production is anticipated ,then the clearance should be over 12 mm keeping in view wash over operations.  The drift dia of the tubing should be sufficient to allow passage of all down hole tools, As a general rule ,it should be kept 5 mm  The joint tension strength at the top should be less than should be less than 80% of the tensile strength.  The safety factors for the tubing should meet the API prescribed safety factor Collapse ---0.85 –1.125 , Burst 1.0 ---1.1 tension 1.6 –1.8  The performance properties of the tubular should be checked anticipating high pressure stimulation , high temperature and fishing jobs possibility. The performance properties of the tubing should meet the collapse pressure, burst pressure and tensile load capability during the producing life of the well, The grade and type of tubing should be properly selected keeping in view anticipated future requirement.

 In case of high pressure gas wells or corrosive gas production well completion, premium tubing should be used.

1.2 TUBING STRETCH CALCULATION • When subjected to axial load ( not exceeding elastic limit) , the stretch can be calculated from

∆ Lt = 12x F x Lp E x Am Where ∆ Lt

•

= Axial stretch

( inch.) F = Super imposed tension load ( lbs ) Lp = Length of tubing ( ft.) E = Young modulus of elasticity for steel ( 30x 106 psi ) Am = Cross sectional metal area of pipe ( inch2 ) = 3.14x (O.d2 - I.d2 ) 4 Weight effect on its own weight Under its own weight , tubing string lengthens . The weight of the hole string is exerted entirely at the top of the tubing but it is nil at the bottom

∆L=

. The integration shows that tubing weight exerted is entirely half of the tubing length.

L W

(Hooke’s Law )

2 E As

Where L W

= length of string in , ft = weight of the tubing string in fluids. lbs

E = Young modulus ( for steel ,E -= 30x 106 Psi As = Tubing cross sectional area , sq. inch and since W = ẞ x ℓs x AS x Lv (lbs )

ℓs =

specific gravity of steel ,Psi /ft

ẞ = Buoyancy factor = 1 – ( MW/7.85 ) LV = Vertical length of tubing (ft) Then ∆ L

=ẞ

ℓs x AS x Lv xL

2 E AS In case of a vertical well ∆L =

ẞ ℓs L2 2E

where MW = mud wt.( gm/cc) 7.85 = S.G of steel

Wire Ropes  1.3 CARE AND MAINTENANCE OF WIRE ROPE

• Wire ropes are made up of number of strands laid helically around a core. It consists of three basic components namely the core, the multi –wire strands and the individual wires that formed the strands. Core is in the Centre of wire rope and may consist of fibre–natural or synthetic, stranded wire or a complete “Independent Wire Rope Core”.Classification of wire rope :• Wire rope is usually described by type of core and number of individual wires per strand. The lay of the wire rope describes the direction of the strands wrapped around the core and the direction of the wire rope within the strands. The strands can be right or left lay.

• Right Lay

Left Lay

Right Lay

Left Lay

• Regular Lay

Regular Lay

Lang Lay

Lang Lay

• Regular Lay • The wires are laid in one direction and the strands in other so that the visible wires appear running parallel to the rope axis. • Lang’s Lay • In Lang’s lay the wires and strands are laid in the same direction so that visible wires run at an angle of about 30 degree to the rope axis.

• Direction of Lay • The direction of lay or rotation of the strands is normally right hand but the wire ropes also are of left hand lay. • Lay Length • It is the length of rope in which one strand makes one helical revolution round the core. This may be expressed as X mm or as X x rope diameter. A short lay rope has more elasticity than a long lay rope and the lay length is dictated by the application for which the rope is intended.

Main application of wire rope include :• Casing lines for lifting loads ( fast line/dead line) • Hoisting of mast ( generally work over rigs ) • Safety line (from monkey board to the ground level) • Guy ropes for derrick or mast • Slings for lifting the lines .Wire ropes are made of cold drawn carbon steel of various grades depending on the strength required. 1. Extra improved plow steel (EIPS) 2. Improved plow steel (IPS) 3.Plow steel (PS) 4. Mild plow steel (MPS) Wire ropes are described by type of core , number of strands wrapped around the core . And direction of the wire rope with strands . The strands can be right lay or left lay. Factor of safety is determined by the following formula :Factor of safety= B /W B= nominal breaking strength of the wire rope in Lbs, W= Calculated total static load minimum safety factor (Refer API 9B) Sand Line 3 Hoisting services other than drilling 3

• Specification of Wire Ropes • Example - 1” X 5000’, 6 X19 S PRY RRL IMPS IWRC • Where • (a) 1 “ - Diameter of line in inches .(b) 5000’ - Length of line in feet © 6 - Number of strands per line (d) 19 - Number of wires per strand

• (e) S - Seale pattern (f) PRY - Pre formed strands (g) RRL - Right Regular Lay (h )IMPS - Improved plow steel (i)IWRC - Independent Wire Rope Core

• WIRE ROPE • General practice followed in ONGC Workover operations for cut off is that the wearing points of every casing line shall be moved by cutting off at least thirty metres of the casing line after every 3000 tonne-kilometres or at shorter intervals, where necessary so as to prevent excessive wear of the casing line

•

Correct method of attaching clips to the wire rope

2.0 COMPLETION FLUIDS The fluids used for completion / recompletion are of following types • Drilling Fluids • Packer fluids • Work over fluids • Special fluids (fracturing , acid treatments, well completion)  2.1 The principal functions of drilling fluid include • Transport cuttings to the surface • Cool and clean the bit • Reduce friction between drill string and sides of well bore/casing • Maintain stability of uncased hole • Prevent inflow of fluid into well bore • Form low permeability filter cake against permeable zone • Information from drill cuttings, cores , logs • Avoid formation damage • Transmit pressure to the bit  Packer fluids should have the following properties :• Remain stable to prevent settling of solids on packer • Be chemically stable so that gel strength do not increase • Be able to seal any leaks in the completion • Not cause corrosion • Not cause formation damage  Work over fluids (used during remedial operations) • Balance formation pressure • No formation damage( due to loss in formation) • Transport sand, metal cuttings, cement during circulation or well cleaning ( proper gel strength, viscosity) • Be chemically stable / not corrosive

 2.1 Special Fluids • Special purpose fluid are used as cushions in limited quantities for treating formation or during perforation • Used to avoid formation damage during these jobs:I. Perforating fluids II. Fracturing and gravel pack fluids III. Acidizing fluids IV. Solvents for [paraffinic /Asphaltines problems  Work Over Fluid System • Fluids used during work over range from l;ow density gases to high density muds • Work over fluids can be classified as: 1. Brine based fluid 2. Oil based fluid 3. Gas , foam, mist The work over fluid can be classified as ( generally it should be solid free suspension fluid)  Formation salt water  Sea water  Prepared salt water ( called brine)  Single salt brines are made with fresh water and salts. Density is adjusted by adding salt or water I. Potassium Chloride (KCL) II. Sodium Chloride (Nacl) III. Calcium Chloride Cacl2) IV. Calcium Bromide (CaBr2)

2.2 Completion/ work over fluid

It is seen that fresh water having minimum sa;lt content may hydrate , swell and disperse several types of clays found in Rservoir. This can impair the productivity severely. Brines of the following concentration should be normally inhibited by suitable chemicals to prevent clay swelling. Brine

Concentration for clay inhibition (%)

Sodium Chloride Calcium chloride Potassium chloride

5 to 10 % 1 to 3 % 1 to 3 %

Maximum Densities of fluids possible with Brines ( excluding addition of Calcium carbonate as weighing material) Brine Density at 60ᵒ F NaCl 1.00 – 1.17 CaCl2 1.00 –1.39 NaCl and Cacl2 1.20 –1.40 KCl 1.00 –1.16 CaCl2 and CaBr2 1.40 –1.81 ZnBr2 and Cacl2 and Cabr2 1.82—2.30 When heavy A = Pf -Pi -Where pf = Ph =

brine is diluted or heavy brine is added to increase the density , the fraction of loghter fluid id given by:ph Ph final density P l = density of lighter fluid

density of heavy liquid

A = fraction of lighter fluid

1-A = fraction of heavy fluid

•

COMPLETION AND WORKOVER FLUIDS

•

workover/ completion can be grouped under following broad categories:-

•

• Water based fluids

•

o Clean, solids-free brines

•

o Viscosified Brines

•

o Conventional water base muds

•

o Clear-water fluids

•

• Oil

•

• Oil base fluids

•

4.0 WATER BASE FLUIDS

•

4.1 Clean, Solid-Free Brines

•

They are the most commonly used fluids in completion and workover operations. These brines are true solutions, meaning that they contain only water and dissolved salts (ions), with no un-dissolved solids. Salt when dissolved in water, yields clear brine — as long as it is below saturation. They cay be used as single-salt brines or mixture of two or three different salt compounds. Advantages of clear brines solution are; • Solids-free

•

• Inhibitive

•

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

•

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

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 addit 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. •

Clear-water fluids

• • Low salinity water such as seawater or produced brines are occasionally used as workover and completion fluid. Water is inexpensive, relatively accessible in most areas, and requires few special additives. • • 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. • • The primary disadvantage that often negates its use is the clay hydration type of formation damage that readily occurs. The primary disadvantage that often negates its use is the clay hydration type of formation damage that readily occurs with fresh water filtrates

•

A) Single Salt Brine

•

These brines are made with fresh water and one salt.

•

􀀹 Ammonium Chloride (NH4Cl)

•

• It can formulate clear fluids to a density of 9.0 lb/gal.

•

• It is most often used (at 2 to 7%) in other clear-water completion fluids, such as seawater, as a clay and shale stabilizer in gravel pack and acidizing operations here its compatibility with hydrofluoric acid is a benefit.

•

􀀹 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.

•

􀀹 Sodium Chloride (NaCl)

•

• The most commonly used brine.

•

• Maximum density possible is 10 ppg.

•

Sodium Formate (NaCOOH)

•

. • Alternative to chloride brines.

•

• Density up to 11.0 lb/gal can be achieved

•

• Better HSE characteristics than chloride and bromide brines.

•

􀀹 Calcium Chloride (CaCl2)

•

• Used to prepare clear fluids up to a density of 11.8 lb/gal.

•

However at higher densities there may be operating problem in winter because of freezing of the solution. At a density of 11.6 ppg the freezing point of CaCl2 brine is 44

•

• Have better Health, Safety and Environmental (HSE) characteristics compared to chloride and bromide brines.

•

• Show excellent thermal stabilization effects on natural polymers and the potassium ion provides excellent clay stabilization and swelling inhibition of shales.

•

􀀹 Calcium Bromide (CaBr2)

•

• Calcium bromide solutions can be prepared to a density of 15.5 lb/gal

•

• The 14.2 lb/gal CaBr2 has a TCT around 0°F (-18°C).

•

• Like calcium chloride, calcium bromide generates heat when dissolved in water, similar precautions should be observed.

•

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

•

B) Mixed 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.

•

􀀹 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.

•

􀀹 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 to the environment is often restricted. Due to the high concentration f dissolved salts and the low pH, zinc bromide brines must be handled with maximum safety precaution.

•

• Alternative to chloride brines.

•

• Density up to 11.0 lb/gal can be achieved

•

• Better HSE characteristics than chloride and bromide brines.

•

􀀹 Calcium Chloride (CaCl2)

•

• Used to prepare clear fluids up to a density of 11.8 lb/gal.However at higher densities there may be operating problem in winter because of freezing of the olution. At a density of 11.6 ppg the freezing point of CaCl2 brine is 44 deg F.

•

• Dissolution in water gives high heat and the amount of calcium chloride required to obtain the desired density should be determined prior to preparing the solution or density measurement must be made after cooling. 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.

•

􀀹 Sodium Bromide (NaBr)

•

• Used for density up to 12.8 lb/gal

•

Sodium Bromide (NaBr)

•

• Used for density up to 12.8 lb/gal

•

• More expensive and used as an alternative to calcium base

•

brines when formation waters contain high concentrations of

•

bicarbonate and sulphate ions.

•

􀀹 Potassium Formate (KCOOH)

•

• It can give density up to 13.2 lb/gal.

•

• Alternative to chloride or bromide brines.

 2.3 Fluid Additives o For increasing density of the fluid ,Cacl2 is generally used (S.G 2.7) . It has good bridging property and is completely degradable with 15% HCl. o Polymers are used as viscofiers in both drilling and workover fluid. The most [opular polymers are CMC ( Carboxy Meyhyl cellulose) , HEC ( hydroxyl Ethyl Cellulose), guar gum etc.  Fluid loss control agents o Fluid loss control agents should have bridging particles and prevent movement of colloids into formation pore space. Should be able to form a stable ,low permeability bridge quickly, should be acid degradable. Fluid loss into formation in high solid systems is controlled with several Chemicals . o These include: 1. Lignites 2. tannins 3. lignosulfonates 2.4 NITROGEN WORKOVER: • Nitrogen has many applications during workover and completion due to :1. inertness 2. No damage to rubber tools 3. No formation damage 4. non combustible 5. colourless, odorless , Boiling point -32ᵒ F • Nitrogen is now used for following operations 1. Activation 2. Propant transport agent during fracturing 3. sand washing 4. Drill stem Testing 5.Packer setting

WORK OVER RIG

Raising the Derrick

Work Maintenance Services WORK MAINTENANCE OPERATIONS 3.0 WELL MAINTENANCE SERVICES  Routine checking and Maintenance of self flowing wells  Recording of well head pressure I) Tubing head pressure (THP) II) Flow line pressure after the Bean III) Casing head Pressure (CHP) Increase in THP may be due to the following reasons: 1.Well bore restrictions are removed 2. Increase in GOR 3. Restriction in flow line 4.Resrictions in Bean Decrease in THP indicate the following : 1.Increase in water cut 2. restriction in Tubing due to paraffin /sand 3.Scale formation in tubing /formation 4. Bean Gas/sand cut  Measurement of oil/gas flow rate and Bottom sediment & Water (BSW) will confirm the exact change in well behavior. Remedial operations are carried out in wells to maintain the desired level of production. These operations include: 1. Bean cleaning 2. tubing scraping 3. Flow line flushing 4. Oil circulation 5. steam circulation 6.Nitrogen application 7.Scale inhibition CTU also might be needed to clean the restrictions in tubing like scales of salts of Stransium/Barium or other miscellaneous jobs. 3.1 Well Steaming:  Steaming is done for the removal of paraffin from tubing and flow lines.  Steaming of wells Mobile steam Unit is taken to the well site. Proper safety devices should be fitted As per IBR Act on the steam boiler. Boiler operator must be holding the valid IBR certificate. Steaming of wells is done to remove remove paraffins deposited on inside walls of the tubing. Steam heating the tubing softens the scale which is removed later by oil circulation or sraping.. Steaming of wells is done where there is no Packer down the hole otherwise communication should be established by wireline before taking up steam treatment. CTU may be used to circulate hot oil / hot water to soften the wax . If wax is not removed then the Nitrogen application be done to break and remove the wax.  Steaming the flow lines Do not close he well while steaming. Keep the unit at a safe distance of about 30 mtrs from the well. Lay the steam line to the wel with a NRV. In case of long lines , steam injection is carried out at multiple points (provided in the flow line). Steaming should be started fro the process station side and continue moving towards the well site ( after completing injections at each points) in stages. This should be followed by oil circulation if wax is still hard ,otherwise not. Fire fighting equipment should be kept handy while doing hot oil circulation

Planning work over jobs 4.0 PLANNING AND DEPLOYMENT OF RIG  Once a well is put on production /injection, at some stage of its operation , it may produce fluids below its capacity /or cease to flow . The problem may be mechanical or reservoir related or both.  4.1 Mechanical problems of sickness of well include o Bad cement bond and channeling may lead to : I. Production of water or gas or undesirable material to other layers due to cross flow 2.Loss of HC from the main producing layer o Casing /well head failures 1. failure of well head seal causing pressure communication in the adjoing outer annulus. 2, Casing leakage o Perforation problems 1. Insufficient perforation 2. Plugging if perforation o Well problem problems 1. production of sand, paraffin, scale in flow string /well bore bottom 2. failure of completion equipment or A/L equipment  4.2 Reservoir /well bore problems can be classified into :o Reservoir problems 1. Low permeability 2. Low reservoir pressure 3. Small productive pay zone o Fluid problems 1. Gas coning 2. water coning/preferential mobility 3. Precipitating of scale in the formation or heavy viscous formation fluid.

Planning Work Over Jobs o Problems around the well bore • Accumulation of formation fines • Poor perforation • Sand production from loose compacted formation 4.3 The above well sickness/ repair can be classified as below  Periodic well maintenance which do not require deployment of a rig. 1. Well scraping 2.Steaming 3.sand or bottom washing 4. Hot/normal oil circulation 5.Paraffin/scale inhibition 6. well stimulation a) surfactant treatment b) acid wash c) Matrix acidization 7. water unloading  Some of the above operations /problems can be handled by wire line operations.  Normal work over operations are well defined and consume less rig time . Normal rig operations include :1. Removal / replacement of defective down hole equipment I) Packers II) Sucker rods ,pumps II) gas lift valves IV) ESP pumps ,motors power cable 2. Removal of bottom hole deposits II) additional perforations  Capital work over operations are complicated and time consuming :1. Drilling and milling of packers , bridge plug , 2. Secondary cementation to repair the cement bond / channeling behind casing 3. Repair of casing damage or recompletion 4.Fishing and removal of stickups of tubing,packers ,and other down hole tolls 5. Testing of wells and recompletion.

Planning of work over jobs 4.5 Planning work over and rig type selection Work over time is very important and it is essential to identify the correct well problem and actual repairs to be taken .  4.5.1 Information required before actual deployment of rig :o o o o o o o  o o o o o

Information from GTO like drilling and cementation history, Geodetic survey report Log interpretation of various logs Production history, bottom hole studies report, Build up survey report Well completion report Establish economic feasibility ,cost and payout period IPR and well tests report, Nodal analysis report, report of earlier PLT logs , Pressure and temperature gradient survey Availability of resources during WORKOVER 4.5.2 Work over plan is therefore made based on specific well details such as :X-Mas tree type and well head type ,make and operating pressure, Casing and tubing size, grade ,ppf, depth, cement rise behind casing, performance properties Cement plug/bridge plug detail Complete completion detail and tubing tally. Pervious Well work over history including well production history

 4.5.3 PRIMARY CHECKS BEFORE DEPLOYMENT OF RIG 1. Foundation for the Rig at site 2. Availability of chemicals for completion/workover fluid, 3. Confirmatory investigation of well problem and investigation is complete . 4. Work over job plan with minimum ambiguity. 5. Availability of tubular, completion and A/L equipment , BOP Stack , Handling and fishing tools,

Selection of Rig type  5.0 SELECTION OF RIG TYPE IS DONE ON THE BASIS OF :• depth of the well , Casing size • Hoisting capacity of the rig : It should take care of maximum load for carrying operations like cement drilling, stuck up, fishing, milling, single or dual completion planned • previous rig type used, pumping system requirement, Drill pipe to be used , Space for BOP below the rig floor, Derrick height, Rotary table  5.1 TYPE OF UNITS • Drilling rig being used as workover Rig • Conventional workover rig Russian Make :Bakintez Rug ( tractor type) , A-50 Trailer mounted Rumanian Make P-50 /T-50 trailer mounted USA Make U-34 , U-36 trailer mounted Canadian Make : Cardwell rig , Trailer mounted ( now used in most of the onshore fields) • Coiled tubing unit CTU ( non conventional unit used for some specific jobs (excluding running in and pulling out of tubular) • Hydraulic snubbing Unit Snubbing unit can perform work over job similar to conventional workover rig with added advantage of handling a live well. The unit is mounted directly on well head . Hydraulic cylinders do the tubular tripping operation. Rotary motion is accomplished with in built Hydraulic motor. Workover operations cab carried out w/out killing the well. It can handle tubing from 2-3/8’ to 3-1/2 “. There are potential hazards while handling this unit . The hiring cost/day of this unit is very high. DERRICK LOAD CALCULATION : o DL

=

SL x (LS +2) LS

(Ton)

where SL = Weight of suspended load (ton) DL = Derrick Load LS = Lines strung

( Ton)

Rig Building  5.1 RIG BUILDING

• During rig building, rig remains idle and therefore best efforts should be made to complete all the activities in a shortest possible. Rig building operations are very critical and require time bound fool proof planning while ensuring safety in each operations/ activities. •

Rig building operations involves following activities.

• A. Site Preparations

• B. Route Survey • C. Rig Release / Rigging Down • D. Load Handling, Transportation of Rig and Rig Equipment • E. Rigging Up

• 5.1.2 SITE PREPARATION (BEFORE RIG RELEASE) • 1) Once decision is taken to deploy a rig on a well, all statutory and regulatory clearances should be obtained, wherever it is necessary • 2) It should be seen that no overhead electrical line passes through well site area (at least 30 mts away from well mouth). • 3) An area of 110 m x 110 m size should normally be available /acquired for safe operation of a workover rig. 4) Based on the type of rig, the well site must be prepared for proper placement of rig and associated equipment. The land around the well site should be cleared, graded & levelled. • 5) Surrounding area of all equipment foundation should be hardened to bear the load of heavy transport vehicles. Hard surfacing of the well site should be done for movement and proper handling of equipment during rigging up.

RIG BUILDING OPERATION • 6) Rig foundation should be prepared as per the rig manufacturer design and design should be based on load bearing capacity of soil. Check the level of the base foundation. Unevenness of the foundation may cause problems in rig centring. Foundation level should be maintained for sub base structure and for the auxiliary equipments.

• 7) Rig foundation can be made new or by modifying the existing foundation of drilling rig. However, levelling and load bearing capacity of the rig foundation must be assured. • 8) For auxiliary equipment placement, levelled foundation strips should be made. If concrete slabs or wooden logs are used as foundation for auxiliary equipment or workover fluid tanks, then all the slabs should be at the same level and ground should be strong enough to support the load.

• 9) If necessary, approach roads/ bridges/ culverts etc should be repaired and appropriate areas around the rig should be surfaced to facilitate the transportation of rig equipment. • 10) Anchors for top man escape device, wind guy ropes etc. should be grouted properly as per the recommendations of the rig manufacturer/API. If old anchors are to be used, they should be inspected for rust, damage, general condition, load bearing capacity etc. To ensure they don’t fail during rig operation. In the absence of mast manufacturer’s recommendations or where mast manufacturer’s recommendations cannot be utilized because of obstructions at the well site location (such as roads, pits, energized power lines, etc.), then the values shown in API RP-4G: • 12) Entire drill site area should be fenced with barbed wire and there should be only one entry point. • 13) X-mass tree of old wells in cluster location should be caged and nearby wells should be checked for any leakage. • 14) Security personnel should be posted at new location before commencement of transportation.

RIGGING UP • 5.1.3 RIGGING UP • 1) Ensure all equipment reaches at new location in good working condition. • 2) Align sub-base structure to the centre of the well. Assemble the sub-structure. Place the rig on foundation and level the rig. • 3) All hoisting lines, casing and sand lines should be inspected thoroughly for broken wires, corrosion, incidental damage etc. • 4) Fix the casing line guide roller on the mast wherever it is applicable. • 5) Reeve the travelling block, fix fast end, spool the casing line on drum and tighten the dead end properly. • 6) Check functioning of clutch and brake. • 7) Check mast members for corrosion, cracks and bends etc before lifting., • 8) Grease all the pins before fitting and fit all the safety clips in all pins. • 9) Observe casing line of tackle system for any obstruction with monkey board while lifting of mast. • 10) Before raising mast to vertical position :a. Level the rig from side to side. b. Get the mast free and ready to raise (hoses, cables, lines, etc.). • c. Unwanted lines like tong hanging lines, cat lines etc. Should be tied to the side of the mast to avoid entangling during lifting of mast.

• d. Check the hydraulic fluid level. • e. Bleed the air out of all erect cylinders by circulating the hydraulic oil. ( one complete cycle). • f. Make sure derrick and guy lines will not come within close proximity to power lines. • g. Park automobiles out of fall lines.

• 5.1.4 PROCEDURE FOR RAISING AND LOWERING OF MAST • As procedure for lowering and raising the mast may differ from rig to rig procedure as recommended by the manufacturer in operation manual should strictly be followed. The recommended practices described above are general in nature based on experience and should be followed to inbuilt safety in operations. Further, following checks should be performed and recorded before initiating the rigging up or own operations; • a. The well has been killed/ closed and is in inactive condition. • b. Hydraulic and pneumatic pressure lines functioning and sealing. • c. Test pneumatic system of rig at a pressure 1.5 times the working pressure but not less than 3 atmosphere above the working pressure. • d. Check brakes, pins and shoes (if necessary burn brakes in case there is oil on the same). • e. Lubrication of all necessary parts. f. Locking device functioning properly. • g. Briefing of all operating crews and defining signaling procedures. • h. Do away with the jerks while lowering and raising the mast.

• i. Emergency plan drawn up and briefed to the operating crews. • j. Raising and lowering of mast should be done in daylight • k. Guy lines, sub lines and such other lines shall not be installed within six metres of any electric overhead transmission lines. • l. All normal checks, as per the instructions of manufacturer, during positioning, rigging and de-rigging should be made and recorded.

• 11) While mast is raising : • a. Unwanted crew members, not involved in operation of • raising mast, should be at safe distance from the rig carrier rig floor and mast. • b. No employees should be allowed in derrick before mast is engaged. • c. Keep block positioned in its cradle during this operation. • d. Keep all lines free while mast is being raised. • e. Raise the mast with slowest possible speed while observing the lifting mechanism sheaves for any hindrance in rotation. • f. Keep a watch on hydraulic oil pressure. If it exceed the normal operating pressure, stop the operation and check the system before proceeding further. • g. Keep a watch on sequence of ram opening during mast raising operation. If any abnormality observed, stop the operation and check the system before proceeding further. • 12) While Telescoping the mast:

• a. Check again to insure that all wire lines stay clear. • b. Secure mast properly to the base section with bolts. • c. Operator should keep the travelling block close to the floor at all times during the operation • d. Move ram stabilizers into place and properly secure the telescoping ram cylinder.

• e. Bleed out air from the cylinders by circulating the hydraulic oil. ( one complete cycle).

• g. Keep a watch on sequence of ram opening during mast raising operation. If any abnormality observed, stop the operation and check the system before proceeding further. • 13) After mast is up : • a. Climb the derrick (with a ladder climbing safety device) to visually inspect load latches are engaged and properly locked. • b. Operator should crack control valve to “lower position to b. Operator should crack control valve to “lower position to relieve pressure on telescoping cylinder.

• c. Tighten load guys with equal tension. • d. Space out crown wind guys according to manufacturer’s specifications. • e. The guy wires should never be turned back over small radius eyes when making an end termination. Wire rope thimbles or appropriately sized sheaves should be used to turn back the guy wire ends. • f. Guy wire hardware such as shackles, turnbuckles, walking boomers, chain come-a-longs, load binders, etc., that remain in the live guy wire system should have safe working load capacities. • g. The use of grab hooks or open hooks on guy wire terminations is not recommended. • h. Lock mast erection control valve in neutral. • i. Align block and hook with well centre. • j. Inspect guy lines for the required number of clamps.

• 5.1.5 X-MAS TREE AND TUBING HANGER REMOVAL • Christmas tree and tubing hanger removal requires careful planning. All procedures should be well defined, reviewed and clearly understood by

• rig crew and service personnel involved in the job. Once the job has been planned and preliminary steps, like well killing, taken, work can begin for • X-mas tree and tubing hanger removal. •

X-mas Tree Removal

• 1. Hold x-mas tree by tying it with a sling of proper load capacity. • 2. Unscrew the nut-bolts of lower master valve of Christmas tree. • 3. Lift the X-mas tree and place it at a proper safe distance from the well head. • 4. Inspect the nut-bolts, rings and ring groove. Lubricate and service them, if required and keep them at a place (may be in store) from where these can be available readily while installing the x-mas tree. • Tubing Hanger Removal • 1. Inspect and lubricate tubing hanger lift threads. These may be corroded and may not be able to support the string weight. • 2. Pick up to pull out of seals (or release packer) and remove tubing hanger.

• 3. Stack tubing hanger at proper place. • 4. Wells completed with packer and Tubing Hanger flange, ensure that all T/H flange studs’ bottom nuts are removed so that T/H flange can be lifted up and string can be put on spider slip for unscrewing of T/H flange. BOP stack can be installed before releasing the packer

• 5.1.6 Tubing Hanger Removal • 1. Inspect and lubricate tubing hanger lift threads. These may be corroded and may not be able to support the string weight. • 2. Pick up to pull out of seals (or release packer) and remove tubing hanger. • 3. Stack tubing hanger at proper place. • 4. Wells completed with packer and Tubing Hanger flange, ensure that all T/H flange studs’ bottom nuts are removed so that T/H flange can be lifted up and string can be put on spider slip for unscrewing of T/H flange. BOP stack can be installed before releasing the packer • 5.1.7 SUBDUING/ KILLING THE WELL

• 1. Observe the well before subduing operation. Record shut in • pressure in tubing and annuluses of the well. • 2. Before opening a well by removing x-mas tree / tubing hanger, the formation pressure must be balanced by hydrostatic pressure of workover fluid of desired density with minimum overbalance pressure (5-10%). Workover fluid is pumped in the well by forward (tubing to casing) or reverse circulation (casing to tubing) • 3. Well subduing procedure and workover fluid should be designed based on well type, well completion, formation pressure, formation temperature, compatibility with formation / formation fluid etc. • 4. The line shall be tested 1-1/2 times the anticipated STHP or rated working pressure which ever is less. No hammering shall be done on pressurized line5. Monitor pump pressure during subduing. Monitor and check the

• parameter of return fluid during circulation till well is properly • conditioned and stabilized. • 6. If no pressure is observed, undertake flow test. If flow test is negative, removal of X-mas tree / tubing hanger can be undertaken.

• 7. If there is pressure in tubing and /or annulus, the well is allowed to bleed of the gas. And as soon as liquid is observed, well should be closed. Subsequently, the well is circulated with suitable work over fluid to stabilise and condition the well. Again flow test is to be performed. If flow test is negative removal of X-mas tree / tubing hanger can be undertaken. However, if the flow test is positive, well is showing pressure, it means that trapped pressure is still in the well, which may require another one or two cycles of circulation of kill fluid to stabilise the well. • 8. Successful subduing of the well will be reflected by zero static tubing and annulus pressure. To ensure that well is completely dead, well should be open to pit / tank for 30 – 60 minutes to check the activity of the well. If no activity, further operation for removing the x-mas tree/ tubing hanger should be initiated. • 9. Till flow test is negative, no attempt should be made to open the well by removing X-mas tree/ Tubing hanger. • 10. In SRP wells (tubing and insert pumps), circulation is established only after lifting the polished rod by 4-5 ft, so that pump is out of the catcher and providing path for circulation. • 11. In other artificial lift completion wells / other type of completions, subduing procedure should be designed accordingly. • 12. There are number of kill procedure available (namely forward circulation, reverse circulation, Bullheading, deploying CTU, lubricate and bleed etc.). Depending upon the circumstances that prevails such as tubing and casing integrity, ability to circulate theu fluid from tubing to annulus or from annulus to tubing, formation pressure, type of well fluid in the well etc, kill procedure should be selected. • 13. Bull heading is recommended where it causes no damage to the formation. • 14. Check for short circulation or quick pressure build-up during subduing operation. • 15. While subduing a well, the return line should be connected to the Group Gathering Station (GGS)/ kill tank at well site. During subduing, return line is onnected to GGS to avoid oil accumulation at well site. Usually the distance between the GGS and the well is sometimes 2 to 3 kms. or even more. A significant amount of pressure drop is experienced in flow lines of the well leading to GGS that may cause additional back pressure to the well and may create a fluid loss situation. It is best practice to kill the well at well site in kill tank and then pumping of produced oil/fluid in the well flow line that is connected to the GGS

WORK OVER JOBS

WORK OVER JOBS  6.0 WORK OVER JOBSS

• • • • • •

6.1 1.Work over jobs include I). Well servicing for restoring production: Self flow wells , SRP wells , Gas lift wells , PCP wells , Other wells II) Detection and repair of chanelling behind casing III) testing and transfer of zones IV) Fishing , milling and stuck-up removal. V) detection and repair casing damage VI) water and Gas shut off VII) Sand production control VIII) Well Stimulation Work over begins with I) Rig foundation II) closing the flow and disconnecting the X-Mas tree from flow arm III) Killing of the well , circulation to condition the brine /mud, IV) Rig positioning and raising of the mast V) Install the BPV in the tubing hanger VI) Removal of X-Mas tree VII) Installation of BOP 6.1.1 Well servicing for restoring production Release of packer if any Tripping out of all down hole equipment including A/L equipment Scraping the well up to perforation and going down to clear the sump .Clear the sump by circulation Servicing and replacement/redressing defective down hole equipment Remove BOP Install the X-Mas tree and Activate/restart the well

6.1.2 Detection and Repair of channeling • Thermo log/temperature gradient • Perforation and block cementation • Clearing hole and pay zone interval of any cementation • Reperforation of the pay zone (if necessary) • Recomplete the well as desired. 6.1.3 Testing and transfer to other object • Test the well for B.H.S , temperature and fluid production rates. If the production rates are not commercial viable , then object needs to be stimulated through acidization or surfactant treatment or Fracturing. if the rates are not commercially viable even after stimulation , then transfer to other objects are required. • Isolate the present pay zone by: I). Cement squeeze / cement plug II). Bridge plug • Perforate the desired pay zone • Test this new pay zone for pressure, temperature, fluid flow rates • Recomplete the new pay zone as desired. 6.1.4 Stuck up , Fishing tools and Fishing Refer to Drilling UNIT-III slides 29 to 54 6.1.5 Detection and repair of casing damage • Detection of leakage point by 1. Casi9ng collar log (CCL) 2. Caliper logs 2. Isotope survey ( precautions required because of pumping radioactive material) . Take it up if only required. 3. Try with pressure testing at various depths with single retrievable packer / or combination of hydraulic and retrievable packer.

WORK OVER JOBS • Select the repair job from the following 1. Cement squeeze job into leaking point within control of pressure 2. Reperforation and carry out block cementation 3. Always scrape the full casing after any cement job and circulate . This step need not be written every time. 4. Placement of casing patches . It will reduce the casing I.D . Think of all the pros and cons of reduction in casing I.D 5. Isolate the leakage with combination of packer and complete the well. This will be discussed in class in detail. 6.1.6 Sand production and control • Please refer to “Production Engg-1 Unit -6 relevant slides “ 6.1.7 Water and Gas shut off • In case of multiple zone completion : • 1. Carry out CBL and VDL ( if not available from the well record). Remedial cement job behind the casing may be required to prevent cross flow. 2. Bring the well back to production for PLT job. 3. Carry out PLT ( Production logging tool ). This is vey very useful log during the production life of the well which tells fluid production in different percentages at different depths , rate of fluids , records F.B.H.P. 4. This will identify the whether it is Gas shut off job or Water shut off job . 5.In both the cases zone of interest is to be shut off . But the entire production interval may not require to be shut off . Use packer isolation methods to know whether bottom half of the pay zone is the culprit or top half is to be shut off. • Block cement squeeze • Diesel cement squeeze • Chemical/polymer squeeze • Cement/bridge plug isolation (Bottom half isolation)

6.. In case of an inclined well , a separate approach needs for squeeze/ isolation job. To be discussed in the class. 7. Reperforate if required 8. Recomplete as desired 6.1.8 Well Stimulation ( This will be taught separately ) Stimulation methods are the following:1.Acid treatment 2. Hydraulic fracturing 3.Surfactant treatment 4.Other stimulation treatment • Heat treatment for bottom hole zones • Nuclear fracturing • Scale treatment

Pipe Spinner • The pipe spinner is used for screwing/unscrewing of tubular with a • specified torque, while the tongs are used for final tightening/ breaking • of joints.

Casing Failure -1 • 6.1.9 CASING FAILURE • Failure of casing is a matter of serious concern. Common type of casing failure and their reasons are as described below: • 6.1.9.1 Casing Leak • Casing leak is the most common failures and often occur in association with most other failures. The major causes for leaks are:• Improper make up during running. • • Drill pipe wear during drilling. • • Mechanical wear during fishing and specially milling. • • Corrosion and to a lesser extent erosion and mechanical wear during production life of the well. • 6.1.9.2 Casing Split or Burst Casing split or burst occurs from many reasons;. • • Applying excess internal pressure sometimes in combination with high tensile loading. • • Excess internal pressure may occur while testing liner top or testing casing before drill out. • • Some failures that cause casing leaks may also cause split or burst casing. • • Casing may split while hanging long, heavy liners. • • General causes include inadequate strength due to improper design, or worn casing at the point where liner setting tool slips engage the casing. • • Casings can also split due to high density perforation (especially in the higher strength steels). • • Casing may also split due to structural defects.

Casing Leaks -2/Casing repair • 6.1.9.3 PARTED CASING • These types of failures are caused mainly due to: • • Improper design. • • Operation or mechanical failures due to improper construction. • • Split or burst casing may also part due loss of structural integrity. • • Other causes can include excess wear and resulting loss of tensile strength, pulling hard while working stuck casing and bumping the plug too hard during cementation • 6.1.9.4COLLAPSED CASING

• Casing collapse due to various reasons • • Improper design. Wear reduces body strength so the external pressure may cause the casing to collapse. • • Anything that reduces wall thickness, including wear or corrosion increases susceptibility to collapse. • • Casing may collapse due to squeezing or treating below a packer set in the casing.

• • Worn or poorly designed production casing may collapse when the hydrostatic head is reduced by compressor / nitrogenCASING REPAIR • 6.1.9.5 FACTORS AFFECTING CASING REPAIRS • • Casing type, size & depth of failures. • • Whether the problem is in cemented or uncemented section.

• • Whether the option of using extra string of casing is available. • • Formation type, pressure, fluid in the formation & transition zone. • • Age of the well.

Casing repair-2 • • Current status of the well (drilling or production). • • Productivity from the well. • • Severity of failure. • • Cost of repair • • Time required for repair • 6.1.9.6CASING REPAIR METHODS • 1. Squeeze and clean out: Generally this is the simplest method of repairing a casing failure such as a leak. Squeeze the section and run a full gauge tool through to ensure that the hole is full gauge. • The disadvantage of this method is that it leaves a potentially weak section that must be considered during future operations.

• Squeezing of cement can be done through open end tubing or drill pipe, retrievable packer or cement retainer. • 2. Pack off the failure: Pack off the failure by isolating it. A damaged section can be isolated from the remaining well bore by running a packer on tubing. Alternately, run two packers on tubing separated by the length of damaged casing. Disadvantage • Disadvantage of this method is that it reduces the working inside diameter of hole and usually restricts operations below the failure.

• Nevertheless, it is the fastest and most economical type of repair. • 3. Patch off the failure: Various types of inside casing failure (usually a hole). Expand the sleeve by pulling the mandrel through it to form a sheet of metal inside the casing. Inside patch reduces the inside diameter of the casing by a small amount which can cause burst and collapse strength to reduce. Generally they include a ribbed or corrugated, thin wall steel cylinder. Run it into the cased hole and position it over thefailure (usually a hole) • 4.Repair parted casing in place: One of the best methods, where ever it is possible, is to establish circulation through the failed

Casing repair-3 • section and perform a primary cement job under a retrievable packer or cement retainer. Alternately, perforate below the failed section and perform a primary cement job in a similar manner. In case of a retrievable packer or open end tubing or drill pipe, take precautions to insure that this assembly does not get stuck in cement. • Pull the cementing assembly above the damaged section of casing and reverse out so that all excess cement is circulated out. Pressurize the casing to ensure that the cement does not flow back into the well. • Another method is to squeeze the section till it holds the desired pressure. Clean out with bit. • 5. Pull, repair, rerun and reconnect parted casing :• : This is one of the best casing repairs, but it is not applicable in many cases. Back off or cut the casing below the failed section and pull it. Replace the damaged section and either screw back into the lower section or connect it with an external casing patch. The external casing patch can be a lead seal or lead seal cementing type. • 6. Run another string of casing or stub casing or tie-back liner: • This method can be used : • (a) If the casing is large enough to run another casing or stub casing or liner.

• (b) If the failure is in the bottom of intermediate casing than by covering it by production casing. • (c) Repair of a failure at the bottom of the hole above a liner with a tie-back liner. If the failure creates an immediate hazard, it may be squeezed off and covered by casing or a liner. • 7. Failure in casing not cemented: When possible, pull the casing, replace it, run and reconnect in a way similar to parted casing.

• Otherwise try to cement the casing in place with a primary cement job. Running another string of smaller diameter casing or tie back or stub liner may be applicable.

FISHING/CEMENTING-1 •

7.0 STUCK UP AND FISHING

•

Fishing is any operation or procedure to release, remove or recover tubular or any undesirable material left in the well bore

•

Already covered in “ Drilling Engg , UNIT-III Well Control” Slides 28-54

•

8.1 CEMENTING

•

In an oil well, cementation of casing and liners is carried out to;

•

1. Restrict the fluid movement between permeable zones within a well.

•

2. Provide mechanical support for the casing/ liner.

•

3. Prevent corrosion of casing/ liner from sulphate rich formation water

•

4. Arrest unwanted flow of fluids, mainly water and gas, in multilayered wells.

•

The cementation of casing / liner soon after it is lowered is called primary cementation. Any subsequent cementation jobs carried out to improve the cement bond behind the casing are called secondary cementation

•

Secondary cementation is the operation performed to repair some segments in the well bore having poor cement in annulus. Secondary cementation jobs are mainly classified as plug cementing and squeeze cementing

•

8.1.1 PLUG CEMENTING

•

A column of cement of a specified length when placed across a selected interval in an open hole or a cased hole is called “Plug Cementing”.

•

Cement plug is placed in the well bore for various purposes;

•

o To stop loss circulation during drilling.

•

o Directional drilling and side tracking

•

o To support the GP assembly.

•

o To plug back a depleted zone.

•

o Isolation of zones in production testing

•

o Well abandonment

•

o To provide anchor for open hole test tool.

CEMENTING-2 (squeeze cementing-1) • 8.1.2 PLUG PLACEMENT METHODS • There are two plug placement methods:

• • Balance plug method • • Dump bailer method Squeeze cementing is useful/ necessary for many reasons • 8.1.3 SQUEEZE CEMENTING • Squeeze cementing is defined as the process of forcing cement slurry, under pressure, through holes or splits in the casing to well bore annular space and then allowing it to dehydrate by further application of pressure. • A basic fundamental of squeeze cementing is that regardless of the technique used during a squeeze job, the cement slurry is subject to a differential pressure against a filter of permeable rock. The resulting physical phenomena are filtration, filter-cake deposition and, in some cases, fracturing of the formation. The slurry, subject to a differential pressure, loses part of its water to the porous medium, and a cake of partially dehydrated cement is formed. As the filter cake builds, the pump in pressure increase until a squeeze pressure less than fracturing pressure is attained. Squeeze cementing is useful/ necessary for many reasons • Squeeze cementing is useful/ necessary for many reasons :•

1.To repair primary cement job that failed due to cement bypassing the mud (channelling) or insufficient cement height in the annulus.

• 2. To eliminate water or gas intrusion from above or below the hydrocarbons producing zone. Or to reduce producing gas oil ratio by isolating gas zones from the adjacent oil intervals.

• 3. To repair casing leak due to corrosion or split pipe. • 4. Plugging all or part of the zones in a multi-zone injection well so as to direct the injection into the desire intervals. • 5. Plug and abandoned a depleted or watered out producing zone

Cement Squeeze Cement squeeze methods (Braden head method)

Cementing Operations--Sketches Cement Squeeze method (Packer squeeze )

Cement Squeeze method (Block Squeeze)

Spacer

Mud

Cement

Spacer

Cement

CEMENTING-3 •

8.1.3.1Repair of primary cement job

•

The drilling mud, which the cement bypasses, may leave pockets or channels behind the casing. These channels are repaired by either low pressure or high pressure squeeze cementing.

•

8.1.3.2To eliminate water or gas intrusion/ or to reduce producing gas oil ratio.

•

The usual procedure is to plug all the perforations in the oil,water and gas zones and then re-perforate in the shorter oil producing interval.

•

8.1.3.3 Repair of casing leaks:

•

This squeeze operation usually performed at very low pressure in order not to extend the damage.

•

8.1,3.4 Plug and abandonment:

•

This job is done at low pressure to avoid damage to a zone, which may be economically explorable in the future.

•

8.1.3.5 Injectivity test prior to squeeze :

•

Prior to placement of cement slurry, conduct injectivity test against the squeeze interval to determine if and at what rate below the fracture gradient fluid can be placed against the formation. A rate sufficient to allow adequate time for cement placement must be reached before actually mixing the cement.

•

8.1.3.5 DESIGN OF CEMENT SLURRY FOR SQUEEZE JOB

•

The properties of cement slurry must be tailored according to the characteristics of the formation to be squeezed, and the technique to be used. Squeeze slurry should be designed to have the following general attributes

•

• Low viscosity: to allow the slurry to penetrate the small voids

•

• Low gel strength: a gelling system restricts slurry movement

•

• No free water

•

• Appropriate fluid loss control.

•

• Proper thickening time to safely meet the anticipated job time

CEMENTING-4 • Following factors may be considered in designing the cement slurry for any squeeze operation:

• i) Fluid Loss Control • The generally accepted API fluid loss rates are listed below:• Extremely low permeability formation - 200 ml/30min • Low permeability formation - 100 to 200ml/30min

• High permeability formation (>100md) - 35 to 100 ml/30min • ii) Thickening Time • Thickening time must be sufficient to assure slurry placement and reversing out of the excess cement slurry. • iii) Compressive Strength • High compressive strength although desirable but is not a primary concern for squeeze slurry design • iv) Slurry Volume • For a successful job, the appropriate cement slurry volume depends upon the length of interval, placement technique, the injection rate of a particular formation and pumping of excess sluThe slurry volume should not exceed the capacity of the running string and the volume should not be so great as to form a column that cannot be reversed out. • V) Squeeze pressure • Squeeze pressure is the pressure at the injection point. In most cases, if the cement can be placed at the proper point, a successful squeeze can be obtained with 500 to 1000 psi pressure above the injection pressure. The pressure should be hold for 10 to 15 minutes with no flow back. After a squeeze is obtained, the pressure should be bled off and the volume of fluid back flown is measured. The squeeze should then be repressured and the volume measured again. If the volumes are equal, this indicates that the squeeze has held and the volume of fluid pumped compensated for tubular expansion

CEMENTING-5 • 8.1.3.6 SQUEEZE TECHNIQUES • A) Braden head squeeze method

• 1) In this method open end drill pipe or tubing is lowered without packer up to the perforations. • 2) A predetermined amount of slurry is mixed, pumped and displaced to the specific height outside the tubing or drill pipe to make a balance plug. • 3) The tubing or drill pipe then pulled out of the slurry and BOP is closed at the surface. • 4) The displacing fluid is pump down the tubing / drill pipe until the desire squeeze pressure is reached or until a specific amount of the fluid has been pumped • B) Squeeze packer method • 1) This method uses retrieval or non-retrievable tool run on tubing to a position near the top of the zone to be squeezed. •

2) Before the cement is placed, a pressure test is conducted to determine the formation injectivity pressue.

• 3) When the desired squeeze pressure is obtained remaining slurry is reversed out. • Block Squeeze Cementing • 1.Consult a CBL / VDL log prior to squeeze job. • 1a..For achieving better intake perforate 2 sets of perforation i.e. above and below the cement retainer . For block squeeze perforate at least 6 to 8 Shots per foot .

• 2. If the poor bondage is continuous for a longer section, decide to carry out block squeeze using a cement retainer. • 3. Lower on tubing snap latch setting tool with seal assembly upto the top of C/R . Stab seal assembly into C/R •

4. Carry out Injectivity test. Maintain the down hole treating pressure below the formation fracture pressure when carrying out injectivity test or establishing circulation behind casing

.

4.a Stab out seal assembly from C/R

Cement Retainer and Bridge Plug Cement Retainer

Bridge Plug

• Scraper and junk sub tool

Cementing -6

• 5. Calculate slurry volume keeping into consideration the annular volume and slurry required below cement retainer.

• 6. Use spacers ahead and behind cement slurry for a minimum length of 50 to 75 m to avoid contamination. • 7. While displacement in progress, monitor free falling /U tubing of cement slurry by controlling through choke. Displace cement up to the tip of cement retainer so as to keep the cement inside the string and engage seal assembly to cement retainer, and squeeze to circulate out cement between the two perforations. Watch return of cement from top peforations. • 8. Disengage the string from retainer and balance the plug. Pull out the string above the top of perforations, reverse wash and squeeze cement in the upper perforation (optional) and keep the well under final squeeze pressure. • 9. WOC for 24 hrs. Scrape the casing , test the squeeze portion for any leakage ,with retrievable packer. •

c) Water/ Gas Shut Off Squeeze

• 1. For elimination of water intrusion or reduction of gas oil ratio this squeeze cementing is carried out to seal all the perforations and then re-perforate a selected interval. • 2. All procedures that of low pressure squeeze cementing are to be followed for placement of cement slurry against the perforated • interval. • 3. In case of good injectivity, squeeze calculated volume of slurry into the perforations leaving a cement plug inside the casing. Squeezing to be done by hesitation method, so that final squeeze pressure is achieved •

4. In case of no injectivity, squeeze cement slurry at the maximum permissible squeezing pressure and close the well under squeeze pressure for 4 hours.

Production Packer

1.0 PRODUCTION PACKER

A Packer is a part of completion equipment used in completion of oil/gas/injection wells to provide a seal between outside of tubing and inside of the casing . The packer isolates and contains the produced fluids and pressures within the well bore to protect casing & formations 1.1The basic functions of packer are : • Protects the production casing from pressure and corrosion effects • Provides an effective isolation of casing tubing annulus from produced fluids ,thus limiting the well control to the tubing at the surface. • Avoids degassing of produced fluid in the annulus thus use of total energy of the expanding gas. • Allows separate production from different reservoir • Provides selective well stimulation and cementation • prevent down hole movement of the tubing string • Support some of the weight of the tubing • Often improve well flow and production rate • Protect the annular casing from corrosion from produced fluids and high pressures • Provide a means of separation of multiple producing zones • Hold well-servicing fluid (kill fluids, packer fluids) in the casing annulus • • • • • •

Packer components Packers have four key features: Slip Cone Packing-element system Body or mandrel.

• The slip is a wedge-shaped device with wickers (or teeth) on its face, which penetrate and grip the casing wall when the packer is set. The cone is beveled to match the back of the slip and forms a ramp that drives the slip outward and into the casing wall when setting force is applied to the packer. Once the slips have anchored into the casing wall, additional applied setting force energizes the packing-element system and creates a seal between the packer body and the inside diameter of the casing.

1.2 A packer is basically defined by : • The setting mechanism in which cone driven behind a tapered slip, forces the slips to bite the casing wall and thus anchoring the packer. • The sealing mechanism in which packing elements are compressed against the casing wall. • The tubing –to- packer connection a. The tubing I fixed into the packer b. The tubing is landed inside the packer bore allowing tubing movement c. The tubing is stung inside the packer bore allowing no movement d. Packer setting and inbuilt releasing mechanism or by milling .

1.3 Types of Packer : • Retrievable packer a. Hydraulic pressure set b. Mechanical set c. tension set • Permanent packer 1.3.1Retrievable packers • The retrievable packer can be very basic for low pressure/low temperature (LP/LT) applications or very complex in high pressure/high temperature (HP/HT) applications. Because of this design complexity in high-end tools, a retrievable packer offering performance levels similar to those of a permanent packer will invariably cost more. However, the ease of removing the packer from the wellbore as well as features, such as resettability and being able to reuse the packer often, may outweigh the added cost. 1,3,1.1. Retrievable mechanical set packer  Weight set  Tension set  Rotation set

Advantages:  Can be released and re-set which avoids a rouind trip  Requires to just pick up the string weight and does not require extra pull to release the packer  Pressure differential can be equalized before releasing the packer.  Assembly and disassembly is simple and quick Limitations :  Pressure differential holding capability is low  Sticking of foreign material into the slips invite releasing prob;em  Not suitable for application at shallow depth due to less compressive set down weight on the packer.  Generally releasing requires left hand rotation which may cause unscrewing of tubing.  Not suitable to be used in deviated hole due to inability to transmit required set down weight on the packer.  1.3.1.2 Retrievable Hydraulic set packer A. Setting and releasing mechanism • Slips are located above and below the packing elemts. Packing elements are generally complosed of multiple packing elements of different hardness and are mostly made of Nitrile rubber which can be used upto down hole temperature of 2750 F .Back up rings are placed after each packing elements so as to prevent flowing over of the elements. The lower slips limit the downward movement of the packer once set and when the well becomes active and flowing under pressure ,then the upper slips in the hold down buttons get activated and restrict the upward movement of the packer. B. Setting Procedure • A landing nipple is connected below the packer and a pressure trip sub/pump out plug is attached below the the landing nipple. A suitable size ball is dropped inside the tubing which is pumped down very slowly to reach the bottom and sit on the pump out plug. • Once sealing the packer bottom , pressure is applied in the tubing which drives the cone behind the slips by a piston –cylinder mechanism . The slips bite the casing and are held in place by mechanical lock or entrapped pressure. The pressure is applied in the tubing as recommended over and above the differential pressure in the annulus.

Permanent C. Releasing procedure  Most of the packers are released by picking up the recommended pull above the tubing weight. Pick up is calculated based on number of tension brass shear pins in the packer.  Some of the packers are released by right hand rotation ( as mentioned in the technical manual.) D. Advantages • Suitable for deviated wells as no tubing movement is required to actuate the setting the mechanism. • It is safe because the setting of the packer is done when X/Mas tree is flanged up.. • Holds greater differential pressure ( in some type of packers) • It is used as a completion packer • Available in single bore, dual bore or even triple bore packer. E. Disadvantages  Multiple releasing and setting is not possible . It needs pulling out and redressed for any further use.  Wire line operations may b e required to plug the seating nipple in case pump out does not hold the pressure  Pulling out the packer may swab the well if packing elements are not fully retracted. 1.3.2 Permanent Packer  This type of packer once set becomes part of the casing and can be removed only by milling.  Tubing can be connected to it by locator seal assembly into bore of the packer , sealed into it and can be release from it. LTSA is landed on the top of the packer body tool. Locator seal assembly is designed with external seals which seal the thin annular space between seal assembly and polished packer bore. The LTSA is dressed with stack of two or three seal units . When LTSA is used ,then it is desirable that a seal bore extension be used between packer and packer catcher section. LTSA is free to move inside the packer bore . The contraction due to well shut in or water injection , stimulation jobs should be carefully calculated so ensure that the seals still remain inside the bore of the packer.  Another type of connection of the tubing to the packer bore is done with Anchor latch seal Assembly. This latch assembly is latched to the packer bore , enabling tubing to remain in tension which prevents , to some extent , effect of contraction of the tubing. If larger contraction is expected then an expansion joint id used above the packer . Anchor latch seal assembly can be released from the packer by shearing the latch threads in side the top of the packer bore. A packer milling extension sub is attached below the bore of the packer to provide space for the catch sleeve of the milling tool.

• Permanent packers can be set mechanically ,hydraulically or electrically on wireline  Advantages  If any long term completion is required.  High pressure differential is required (10,000 psi and above )  Large packer bore as compared to retrievable packer.  Can be set fast on electric line with precise control of depth • Disadvantages • available in single bore configuration • It requires packer to be milled • If no tubing movement , then seals may get stuck in the bore of the [packer • Setting procedure • These packers are run on tubing , set mechanically and also run , set on electric wireline • Wire line setting • The packer is lowered on pressure setting tool PST (E-10 or E-20). Wire line adapter kit is used to connect the PST to the packer When at desired setting depth ,electric current ignites the power charge within the setting tool . Gas pressure builds up and hydraulically activates the piston which mechanically sets the packer. The PST is released by shearing a release stud.

1.3.1.3 Guidelines for selecting a packer  Selection of packer depends on the properties of the well and the requirements revealed by the following studies :  Tubing stresses and movement ,corrosion-erosion, elastomer selection , completion and packer fluid properties, workover procedure , I.d requirement and setting mechanism. by comparing the above stresses with the specification of the packer in the manual , will allow a pre selection of packer type . These examinations must include : • Differential pressure limitation of the packer • Seal elements resistance to types of fluid in the well • Setting and Retrieval /milling procedure of the packer. • Packer metallurgy given by the manufacturer, • Internal diameter of the packer • Casing I.D • Setting range of the packer • Temperature limitations of the packing element Rig capacity to provide pull to release the packer • 1.3.1.4 ELASTOMER Elastomers are used as a sealing element in the all types of packer and seal assembly. An elastomer is defined as a compound which will not break up when 100% stretched and has a maximum 10% resilient deformation after a 100% stretch for 5 minutes. This compound is a mixture of polymers and additives. MAIN PRODUCTS A. Natural rubber. 1. Neoprene rubber Chloroprene Resists low temperature aromatic oil . Looses strength in hot water

ELASTOMERS 2. Nitrile rubber 3. Viton 4. Ethylene Propylene

5. Kalrez

Nitrile Butadiene It is the most common ,cheapest and toughest. Does not resist high temperature and H2S Flouro Carbon Satisfactory with H-C , but does not resist HCl EPDM It is not suitable for H-C but may be used with hot steam Perfluro Carbon It is the most universally used compound upto now. It is soft and is used with back up devices

B. Thermoaplastics 1. Teflon

2.

Polytetra Flouro ethylene It is a medium hardness seal material and is used as back up services . Flouro ethylene sulfide it is harder than Teflon and is used as V-type seal .

Ryton

C. Elastomers used for O-Rings / Elements Service Temp. Pressure

Environment (A=acceptable ,B=No effect , C=Swells , NT= Not tested) H2S Co2 H-C Gas (CH4 ) Steam NR A A C NR B C A A NR C C B/C C NT

Nitrile Flouro Carbon Neoprene

-10 to 2750F -10 to 3250 F - 30 to 2000 F

10,000 Psi 9,000 Psi 2,000 Psi

EPDM

-30 to 3500 F

3,000 Psi

NR

NR

NR

NR

A

Kalrez

0 to 4000 F

10,000 Psi

A

B

A

B

B

Tension Packer

Sngle string Retrievable Mechanical packer

Single string Retrievable hydraulic Packer

Permanent Packer

Dual bore Hydraulic Packer

Retrievable seal bore Packer with Retrieving tool

POSITEST PACKER

Packers

Permanent packer

SAFETY

SAFETY-1 • 9.0 AREA CLASSIFICATION

• To determine the type of electrical installation appropriate to a particular situation, the hazardous areas have been classified into three zones • namely zone - 0, zone - 1 and zone - 2 according to the probability of the presence of hazardous atmosphere. • Zone - 0 • Zone-0 hazardous area means an area in which hazardous atmosphere is continuously present or is likely to be present for long periods and any arc or spark resulting from failure of electrical apparatus in such an area would almost certainly lead to fire or explosion. • Zone-1 • Zone-1 hazardous area means an area in which a hazardous atmosphereis likely to occur under normal operating conditions. Such onditions are likely to occur at any time at oil and gas wells and production installations.

• Zone-2 • Zone-2 hazardous area means an area in which a hazardous atmosphere is likely to occur only under abnormal operating conditions and if it occurs it will exist only for a short time. • 9.1 CLASSIFICATION OF HAZARDOUS AREA IN WORKOVER WELLSAreas surrounding a well in the process of drilling or being serviced by workover rig should be classified as follows:

• 9.1.1Well head area • • When the derrick is not enclosed and the sub-structure is open to ventilated area above the ground level extending vertically 8 m above the well and horizontally 16m in all directions from the well, the area should be classified as Zone-2 area. When the derrick floor and sub structure are enclosed, the entire enclosed sub structure including cellar-pits, and sumps below the ground level should be classified as Zone-1 area but the area enclosed above the derrick floor should be classified as Zone-2 area

Safety-2 • 9.1.2 Producing oil and gas wells • • Area around a flowing well without any cellar and located in open air is classified as Zone 2. • • Area around a flowing well located in open area with a cellar, extending vertically up to 60 cm above the ground level should be classified as Zone-2. The cellar should be classified as Zone-1. • • The area within a radius of not less then 16 m horizontally and extending 8 m vertically above from an open discharge of petroleum bearing fluid from a well under production test, should be classified as Zone-1 area. • • The area within a radius of not less than 16 m. horizontally & 8 m vertically from a well under production test in a closed system should be classified as Zone-2. • 9.1,3 Well servicing operation • • The area within a radius of not less than 16 m in all directions from well servicing operations should be classified as Zone-1. • • If tests with explosimeter, made every two hours, show that hazardous atmosphere does not exist then the area may be classified as Zone-2. • 9.1.4 USE OF ELECTRICAL EQUIPMENT IN HAZARDOUS AREA (OMR1984) • a. No electrical appliance, equipment, or machinery including lighting apparatus shall be used in zone ‘O’ hazardous area. • b. The Chief Inspector may from time to time by notification in the official Gazette specify appliances, equipment and machinery that are or may be used in zone 1 and zone 2 hazardous area which will be of such type, standard and make as approved by the Chief Inspector by a general or special order in writing. Where any such appliances, equipment, or machinery has been specified by the Chief Inspector, any appliances, equipment, or machinery other than that approved by the Chief Inspector as aforesaid shall not be used in such hazardous area.

Safety against H2 S environment H2S Safety requirement