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An Introduction to Well Services

Prepared byWell Services – Assam Asset -1-

Foreword Every year due to the company policy a whole set of new officers on transfer from other regions joins Well Services-Assam Asset. These officers are of diverse background and often had very little exposure in the operations of Well Services. It was increasingly being felt that a systematic training approach is required for these officers so that they are smoothly inducted in the Well Services operations. Keeping the above in mind, this introductory manual was conceived and a qualitative approach was adopted while describing the various major operations namely-Workover, Well Completion & Testing and Well Stimulation Services. Only those operations normally being carried out by Well Services Assam have been touched and it is hoped that the officers shall get a conceptual idea and feel of the things which will further incite them to go into the details of the jobs for which they will be responsible during their tenure. The compilation team is especially grateful to Shri R.K. Sharma-GM-Head Well Services, whose valuable guidance & encouragement was primarily instrumental in penning the manual. The team is also highly indebted to Shri Vijay Lal SE(P), Shri Ajay Ratan SE(P) & other members of Planning Cell, Shri Abhijit Chaudhury Dy. SE(P), Shri V.S. Limbachiya SE(P) and all the superiors / colleagues of Workover, WC&T and WSS sections without whose valuable suggestions the manual could not have made headway. As this is an initial attempt to such specific compilation, one may feel that certain topics may need more elaboration or improvement and the compilation team is open to all such valuable suggestions. It is hoped that the new officers shall find the book extremely useful.

Compilation Team 1. Ashutosh Dash- CE(P) 2. Ashis Guha – SE(P) 3. Kaushik Parmar- EE(P)

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Contents 1. Eastern Region: a Brief description 2. Introduction to Well Services 3. Different sections of Well services • Work over 1. Concept of a well 2. Rig description 3. Rig Operations during workover 4. Types of Work over jobs. •

Well Stimulation services 1. WSS Units 2. WSS activities

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Well Completion and Testing 1. Well Testing & Concept of initial well completion 2. Downhole tools and equipments 3. Fishing operations

4. Associated Services • Logging • Reservoir studies • Cementation 5. Brief description of Assam Asset fields: • Lakwa • Geleky • RDS • Demulgaon • Satellite

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WELL SERVICES, ASSAM ASSET : A BRIEF Well Services Group is a pioneer in its field covering the entire gamut of activities consisting of work over operations, well testing and completion & well stimulation services. Having a strong and experienced man power of more than 700 persons, this group has rose to the occasion to meet the multidimensional challenges in day-to day activities with utmost concern in safety aspects. This group comprises of three major sections viz. Work Over Section, Well Testing & Completion and Well Stimulation Services. WORK OVER : The work over operations play the major role in sustaining the oil production from the mature fields of Eastern Region. These operations are required for revival of sick oil, gas& water injection and Effluent Disposal wells. The work over section is the flag ship of well services group. Starting with the sole work over rig U-34-I in 1967, the section is presently operating a fleet of 18 work over rigs catering to the jobs like Water shut off, zone transfer, casing repair, sand control jobs, servicing of effluent disposal wells, servicing of wells on artificial lifts, installation of artificial lift systems etc. The total rig strength comprises of 15 departmental rigs and 4 chartered hired rigs. Average work over load for work over is around 200 plus wells in a year. Most importantly, work over section is spearheading the activities daring all odds like environmental problems, difficult road conditions, embankment problems and logistic constraints. A blend of pro-active attitude and expertise helps to overcome the multifaceted challenges like bottom hole complications at a depth of 4000 m plus, precision cementation jobs to arrest water channeling, localized coning and recovery of high paraffin oil. WELL COMPLETION AND TESTING: This section comprises of Well Testing and Down Hole sections. Well Testing is the first and foremost major activity under taken after drilling a well, success of which decides all future oil production activities. All identified prospective objects are individually perforated and completed using down hole equipments and the well is activated. Flow studies are then carried out to measure the flow rates to estimate the reservoir potential. The wells are then suitably completed and put on production. Since its inception in 1964, well completion and testing section has played crucial role in reserve accretion on a continuous and sustainable basis and production enhancement year after year. Established in 1975, Down Hole section has been providing relentless service in terms of down hole equipments like packers, bridge plugs/cement retainers; fishing services and slick line services. Latest specialized equipments are acquired from the World market and services offered are the best in terms of quality, professionalism and success rate. WELL STIMULATION SERVICES: Well stimulation services came into being in its present entity in 1983-84 to fulfill the need of stimulation and specialized services for enhancing oil and gas production. WSS provides stimulation services such as hydraulic fracturing, acidization, surfactant/solvent treatment and specialized services like coil tubing services, gravel pack, nitrogen application,

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water shut off, hot oil circulation, sand gel plug , tubular scouring and cleaning etc. This section has also actively participated in crisis management activities like blow out control, trouble shooting in trunk lines operations etc. Over 20 years, Well Stimulation Services has kept abreast with developments in stimulation and specialized services by acquiring state of the art equipments and services of world renowned consultants from time to time. In a nutshell, Well Services Group, Assam Asset has been playing a dynamic and crucial role in Eastern Region through reserve accretion, production enhancement and revival of sick wells.

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Workover All wells require a sound servicing program if production is to be maintained, restored or improved during the production life of a well . These operations have one major functionto keep a well at high level of productivity. If production of a well is to be maintained , it is essential that a well servicing and later if needed a workover program be developed. The necessity of such program is based on certain requirement s that are basic to all wells such as general maintenance and repair of equipment , while other requirements varies from well to well. Well Servicing operations are carried out by trained crews who use a variety of specialized equipment , most of which are scaled down versions of equipment employed on a standard rotary drilling rig used to drill the original well. Well Workover & intervention is the process of performing major maintenance or remedial treatments on an oil or gas well. In many cases, workover implies the removal and replacement of the production tubing string after the well has been killed and a workover rig has been placed on location. Rigless through-tubing workover operations, using coiled tubing, snubbing or slick-line equipment, are routinely conducted to complete treatments or well service activities that avoid a full workover where the tubing is removed. This operation saves considerable time and expense.

CONCEPT OF A WELL : A well consists of the various components: • • • •

Christmas tree Tubing head & tubing pipes Casing heads & Casing pipes Tubing components

A Christmas tree is the assembly of gate valves, chokes, and fittings that controls the flow of oil or gas during production. The bottom connection of the tree matches the top connection of the tubing head adapter. The tree and adapter are usually made up and installed as a unit immediately after tubing is suspended. The tree consists primarily of a series of gate valves and a production choke. Gate valves located between the tubing head adapter and the production tee are called master valves. Christmas trees always have at least one master valve; usually two are used. Dual master valves allow the use of the top master valve for normal use, thus reducing wear on the lower master valve, which is the most difficult to replace. Replacement of the top master valve can be accomplished with relative ease by isolating the upper portion of the tree with the lower master valve. A gate valve called a crown valve or working valve is often placed above the production tee. This valve facilitates installation or dismantling of a lubricator without shutting in the well.

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A gate valve is almost always placed immediately off of the production tee. This valve, called a wing valve, can be used to shut off flow to the production facilities and still allow work down the tree or tubing. A tree cap is sometimes installed on top of each tree above the crown valve to provide quick access to the tubing bore for bottomhole testing, installing a backpressure valve, swabbing, or paraffin scraping. Most tree caps are tapped for a pressure gauge and have internal lift threads to facilitate the installment of the tree.

Typical Wellhead TUBING: The central downhole component of a completed well is the production tubing . The primary reasons for utilizing production tubing are: • It is relatively easy to remove if problem develops • It isolates producing fluids from the casing and makes control of the fluids easier. • It facilitates circulation of heavy fluids into the well bore to control the well. • It allows artificial lift equipment to be included in the completion design. • It allows for more efficient producing rates from lower productivity wells.

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Tubing is suspended from a tubing hanger within the well head at the surface and packs off around the production casing. The tubing head performs a function similar to the casing head , in that it accommodates the tubing hanger which usually screws onto the top of the tubing string and seals off the casing tubing annulus with metal to metal and / or rubber sealing elements. Often the tubing hanger is further secured by a series of set screws. An adapter provides a transition from the tubing head to the arrangement of valves and fittings above the casing and tubing head used to control the flow ( Christmas tree).

CASING : The basis of any completion is the heavy steel pipe lining the wellbore – casing. Together with the cement sheath holding it in place , the casing performs several important functions: • Supporting the sides of the hole • Preventing communication of fluids and pressures between shallow & deep formations • Allowing for control of pressures • Providing a base for surface & subsurface equipments The conductor prevents the surface hole from caving and it also prevents lost circulation. Surface casing provides protection for shallow freshwater formations , and the production string of casing is set to or through the productive zones , to isolate them and allow for selective completions. There may be intermediate casing strings between surface and production casing if the depth of the well requires it . Each casing string is cemented in place and the production string is perforated across the productive zone. Casing hangers allow the weight or tension load of a casing string to be transferred to a casing head or spool. Casing hangers also center the casing string in the head or spool and provide a pressure-tight seal against the inside of the casing head or casing spool bowl to contain pressure in the annulus between its casing string and the previous string. Most commonly Slip-type hangers are used which have slips in serrated segments for gripping the casing. The casing head is screwed or welded to the outer most casing stub. The inside of the casing head provided a shouldered sealing surface for the casing hanger , which grips the hanging casing. Guide Shoe :A guide shoe is attached to the bottom of the first joint of casing lowered into the hole. Its rounded nose facilitates the movement of the casing down the hole. Float collar: This is placed several casing lengths above the guide shoe, and contains a one way valve. This backpressure valve enables the casing to “float” down the hole by preventing the entry of drilling fluid into the casing. The valve also prevents a blowout through the casing, should a kick occur during the primary cementing operation, and prevents backflow of cement after pumping.

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Commonly used Tubing components; Packers : The packer seals the casing-tubing annulus with a rubber packing element, thus preventing flow & pressure communication between tubing and annulus. This has been discussed in the “down hole section”. Gas lift mandrels : A gas lift mandrel is a tubing component that holds a gas lift valve which in turn allows the passage of gas lift gas between annulus & tubing. This has been discussed in Artificial Lift Section. A TYPICAL WELL SCHEMATIC

13 3/8” casing

9 5/8” casing

2 7/8” tubing

Packer Perforation Bridge Plug

5 1/2” casing

Float Collar

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Workover rig As workover rig equipments are scaled down versions of equipment employed on a standard rotary drilling rig used to drill the original well, it will be worthwhile to discuss the basic drilling function of the rotary rig and its equipment. This will help in understanding the operations carried out by the workover rig. For drilling , we need to be able to transmit torque from a prime power source to a bit via a drillstem ; we need to have the capability to lengthen or shorten the drillstem as necessary and to regulate the force it exerts on the bit at the bottom of the hole; we need to be able to circulate a drilling fluid down the drill stem, through the bit and back up the annulus between pipe and the hole ; and we need to be able to control the subsurface pressures encountered as we drill deeper. Rigs are rated according to their drawworks’ horse power , mud pump horse power & load bearing capacity. The load bearing capacity can be translated to a depth limitation depending on the size of the drill pipe. The four basic drilling functions of a rig are : • Hoisting • Rotating • Circulating • Controlling The principal components of a rig that perform these functions are shown in the figure. The derrick supports the crown block and travelling block, which are operated via the drawworks and its drilling line. The Kelly and the swivel are connected to the drillstring and are suspended from the hook beneath the travelling block, allowing the Kelly and drill string to be turned by the rotary table. A drilling fluid circulation system pumps mud from the tanks through stand pipe , hose, swivel and drillstem , returning the mud and cuttings up the annulus and back to the tanks. The BOP or Blow Out Preventer stack and its operating equipment allow the drilling crew to maintain control over sub-surface pressures

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Hoisting (derrick, drawworks, blocks and hook) The derrick , or mast and the sub-structure it sits upon support the weight of the drill stem and allow the vertical movement of the suspended drillpipe. The substructure also supports the rig floor equipment and provides workspace for its operation . The drill string must be removed from time to time , the length of the drill pipe section that can be disconnected and stacked to one side of the derrick is determined by the height of the derrick. The draw works is a spool or drum pon which the heavy steel cable (drilling line) is wrapped. From the drawworks, the line is threaded through the crown block at the top of the derrick and then through the travelling block, which hangs suspended from the crown block. By reeling in or letting out drill line from the drawworks drum, the travelling block and suspended drillstem can be raised or lowered. In order to safely manage the movement of such heavy load with precision , the driller relies on an electrical or hydraulic brake system to control the speed of the travelling block and a mechanical brake to bring it to a complete stop. The hook is attached to the travelling block and is used to pick up the drillstem via the swivel and Kelly when drilling , or with elevators when tripping into or out of the hole.

Rotating (swivel , Kelly, rotary table) The swivel allows the drillstem to rotate while supporting the weight of drill string in the hole and providing a pressure tight connection for the connection for the circulation of drilling

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fluid. The drilling fluid enters the swivel by way of the “gooseneck” a curved pipe connected to a high pressure hose. Connected to the hose is the Kelly which is a square or hexagonal length of pipe that fits into a bushing in the rig's rotary table. As the rotary table turns to the right, the kelly turns with it. Kellys are manufactured with either square or hexagonal cross sections.

The main function of a kelly is to transfer energy from the rotary table to the rest of the drill string. On modern rigs, this function is more commonly performed by a top drive unit, power swivel or power sub located directly below a conventional swivel. Of course, when a downhole mud motor is used for directional or other applications, there is normally no drill - 12 -

string rotation. The Kelly cock is a special valve on the end of the Kelly nearest the swivel , which can be closed to shut in the drill stem. A lower Kelly cock is also available on the bottom end of the Kelly to perform the same function when the upper Kelly cock is not accessible. A kelly saver sub should always be run between the kelly and the top joint of drill pipe. This protects the kelly's lower connection threads from wear, as joints of drill pipe are continually made up and broken out. A saver sub is much less expensive and much easier to replace than the kelly itself, and it can also be equipped with a rubber protector to help keep the kelly centralized and to protect the top joint of casing against wear. The flat sided Kelly fits through a corresponding opening in the Kelly drive bushing , which in turn fits into the master bushing set into the rotary table. The rotary table is turned by the rig’s power source , the table turns the bushings, the Kelly bushings turns the Kelly, the Kelly turns the drillpipe and so on …… down to the bit.

Circulating (pumps, standpipe, return line, solids control equipment) Circulation of a drilling fluid to carry cuttings up the hole and cool the bit is an important function of any rotary rig. The heart of the circulating system is the mud pump (or pumps) which is powered by the rigs prime power source , as are the rotary table and drawworks. Mud pumps are positive displacement pumps that push a volume of drilling mud through the system with each stroke of their pistons. The mud pump pumps the drilling fluid from the mud pit or tanks up the standpipe toa point on the derrick where the rotary hose connects the standpipe to the swivel. The flexible , high pressure hose allows the travelling block to move up & down in the derrick while maintaining a pressure tight system. The circulating drilling mud moves through the swivel , Kelly, drill pipe and drill collars , exiting through the bit at the bottom of the hole (or casing) carrying the drilled rock in suspension.

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At the surface, the mud leaves the hole through the return line and falls over a vibrating screen called a shale shaker. This device screens out the cuttings and dumps them. Once cleaned the mud is returned to the mud tank from where it can be once again pumped down the hole.

Controlling (blowout preventers, choke system) Controlling the subsurface pressures encountered while drilling is an important part of the operation. One of the purposes of drilling mud is to provide a hydrostatic head of fluid to counterbalance the pore pressure of fluids in permeable formations . In spite of this , however for a variety of reasons , the well may ‘kick’ that is formation fluids may flow into the well bore , upsetting the balance of the system, pushing mud out of the hole , and exposing the upper part of the hole and equipment to the higher pressures of the deep subsurface. If left uncontrolled , this can lead to a blowout with the formation fluids forcefully erupting from the well , often igniting , and endangering the crew, the rig & environment. The blowout preventers are a series of powerful sealing elements designed to close off the annular space between the pipe & hole where the mud is normally returning to the surface. By closing off this route , the well can be “shut in” and the mud and /or formation fluids forced to flow through a controllable choke , or adjustable valve. This choke allows the drilling crew to control the pressure that reaches the surface and and to follow the necessary steps for “killing” the well and restoring a balanced system. The blowout preventers are a stack of hydraulically operated valves that effectively seal off the annular space between casing & drill pipe / tubing. A typical BOP stack include an

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annular preventer with a doughnut-shaped rubber sealing element that can be squeezed against drillpipe. Below this device are a series of ram –type preventers including pipe rams with rubber jaws moulded to grip a certain size drill-pipe, blind rams , which completely close the hole when no pipe is present , and shear rams which crush the pipe in a situation in which the pipe cannot be removed in time.

BOP Accumulator BOP The hydraulic pressure required to operate the preventers is supplied by accumulators. The energy stored in the accumulators by nitrogen precharge is high enough to complete closing and opening of BOP. Companies have various specifications for the minimum accumulator volume, but a widely used one is 1.5 times the sufficient fluid volume at 3000 psi to close all preventers and have 1200 psi remaining. The above four basic functions – hoisting , rotating, circulating , and controlling pressure are performed by every rotary rig. The other components of the drilling system that are critical in the performance of these functions and require a little more scrutiny: the drill string , the drilling fluid and the drilling process.

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THE DRILL STRING : As the drill string moves downhole, it is subjected to a variety of stresses, including tension, compression, vibration, torsion, friction, formation pressure and circulating fluid pressure. It is also exposed to abrasive solids and corrosive fluids. The drill string not only must be sturdy enough to withstand this hostile environment, but it must be lightweight and manageable enough to be efficiently handled within the limits of the rig's hoisting system. At the same time, it must: • provide weight on the bit while holding the drillpipe in tension • allow control over wellbore deviation and maintains rigidity to drill a straight hole It is vital that the drill pipe never be subjected to high torque or compressional forces, since it could easily twist off . The length and makeup of the drill string depends on such factors as well depth, hole size, operating parameters and directional considerations.

The major components of a drill string are the kelly (or topdrive unit which was discussed earlier), drill pipe and bottomhole assembly . The longest portion of the drill string consists of connected lengths of drill pipe. The primary purposes of drill pipe are to provide length to the drill string and transmit rotational energy from the kelly to the bottomhole assembly and the drill bit. Drill pipe also serves as a conduit for the drilling fluid.

The bottomhole assembly is that portion of the drill string between the drill pipe and the drill bit. Its individual components may be arranged in any number of ways to promote drilling objectives, and can include: 1. D  rill collars, which provide weight and stability to the drill bit, maintain tension on the drill pipe and help keep the hole on a straight course. When drill pipe rotates in the compressed state, it experiences cyclic stress reversals. Each rotation of the string causes the drill pipe fibers to go from compression to tension to compression. This high cyclic stress bending causes metal fatigue, which is cumulative and eventually leads to drill pipe failure.

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2.

Stabilizers, which centralize the drill collars, help maintain the hole at fullgauge diameter and aid in directional control;

3. Jars, which can provide sharp upward or downward impact to free stuck pipe; 4. Crossover subs, which join components having different types of connections. For example, a double-box crossover would be needed to join a bit with an API Regular pin connection to a drill collar with API Full Hole pin connection. 5. Drill Bit is generally the most critical component of the drill stem. In workover only cement drilling is done. The type of bits generally used in workover are discussed in Down hole Section.

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DRILLING FLUID: Most wells are drilled with a fluid with special properties which is called mud. The addition of clay and chemicals to the water permits the adjustment of viscosity, density, and other properties to improve hole cleaning and prevent sloughing shale, lost circulation, formation flow, and formation damage. During workover operations in most cases brine is used for drilling of cement. In any case the properties of the fluid must be such that it performs the following functions: • Control subsurface pressures Subsurface pressures are controlled by adjusting the density of the drilling fluid so that a balance is maintained between the hydrostatic pressure imposed by the column of drilling fluid and the pore pressures of the formations • Remove cuttings from the hole Viscosity is the drilling fluid property that is important when removig cuttings from the hole . Mud must have the proper viscosity to lift the rock cuttings out from underneath the bit and carry them up the annulus to the surface. In addition the mud must exhibit the sufficient gel strength to hold the cuttings in suspension when circulation stops , and prevent them from settling to the bottom of the hole , collecting around the bit and making the pipe stick in the hole. • Cool & lubricate the drill stem This function is performed primarily at the bottom of the drill stem, where the bit is forced against the bottom of the hole and rotated. The combination of weight & speed creates frictional heat within the bit that must be removed by the circulating fluid to prevent rapid wear. • Aid formation evaluation & productivity Drilling fluids properties should be monitored to ensure that the interaction between mud and formation does not prevent the formation from being easily evaluated or produced. For example , oil based & salt water based fluids can make some electrical logging operations difficult. Some formations can be irreparably damaged by the invasion of mud & mud filtrate. For example water mud in zones containing water sensitive clays , are examples of permeability damaging situations. In Geleky field it is observed that using NaCl brine swells the formation and this can be avoided by using KCl brine. CEMENT DRILLING PROCESS (Running in & Pulling out): During workover, mainly Cement drilling is carried out to clear the bore hole of completion casing. The running in & pulling out process of drill pipes and tubings discussed below is conceptually same in all other operations such as ‘scrapping’ or ‘completion string pulling out / running in’ etc. While “Running in” The drill string lowered ( as discussed earlier) comprises of the drill bit , drill collars, followed with joints of drill pipes & finally Kelly. Weight is applied to the bit by allowing the bottom hole assembly to rest on cement top somewhat, and the rotary table

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begins to turn the Kelly. As the bit chews away at the bottom of the hole, the mud pump circulates the cuttings up the annulus. The Kelly slowly moves downward until the top of the Kelly and the attached swivel are near the drilling floor (after a drill pipe length about 9-10 m has been drilled). From now on , each time a kelly length has been drilled down , another joint of drill pipe is added to the drillstem. During “Pulling out” the Kelly and the attached drillstring are lifted up in the derrick until the kelly bushing has cleared the drill floor and the tool joint between Kelly & drillpipe is visible. SLIPs ( flexible , toothed wedges ) are set in the rotary table to grip the drill string and allow it to hang motionless while the crew “breaks out” (unscrews) the Kelly with the rotary tongs. The ROTARY TONGS are nothing more than oversized pipe wrenches hung from the from the derrick, over the drill floor, and pulled by a cable from the draw works. Now the Kelly is hanging freely from the hook , and the crew can swing it over to the pipe joint that is waiting “ box end up “ in the mouse hole. (In our workover rigs, the waiting pipe is on the catwalk which is pulled towards the Kelly end by the help of winch & cat line). The Kelly is screwed into the new joint and both are then lifted up into the derrick and swing over the drillstring held by the slips. The driller lowers the assembly and carefully “stabs” the pin of the new joint into the box end of the waiting joint. The pipe is quickly screwed together and tightened with the tongs before the slips are removed. The entire assembly is then lowered back into the hole to drill another joint length. After the Kelly has been “drilled down” (912m), the connection process must be repeated, joint by joint , as the hole is deepened.

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SLIPS

ROTARY TONGS At some point it becomes necessary to pull out of the hole, say for changing the bit. When making such a “trip” drill pipe is handled in stands , usually two joints each (approx-18m). First the Kelly , rotary bushings and swivel is disengaged from the pipe string & put aside on the catwalk rack. With this equipment out of the way , the elevators, which hang from the hook, can be latched around the pipe just below the tool joint box and used to lift the pipe out of the hole. When a stand of say two joints has been pulled up into the derrick, the slips are used once again to hang the drillstring in the rotary table while the bottom tool-joint is “broken” with the tongs and unscrewed with a wrench. The stand of pipe is then swung to one side of the drill floor, where it is set down and secured at the top by the derrickman. Free of their load , the hook and elevators are lowered once again to grip another stand of pipe and repeat the process, until all of the drill stem is racked in the derrick. The bit is removed from the final stand of drill collars / drill pipe and the rotary table is carefully covered to prevent any loose items from falling into the hole. Running in (Tripping in) the hole is the reverse procedure of tripping out.

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Rig Operations during a Workover Typical Operations carried out by a workover rig are : • Well subduing ( Refer to “Circulating in Workover Rig” section) : Before any job is carried out in a well, the well fluid is circulated out and replaced by a heavier fluid usually brine. • Removal of Christmas tree and installation of BOP for safe operations and controlling the well incase of sudden activity. • Initial pulling out: The production tubing along with all tubing components (packer, GLVs, SRP/ESPs etc.) is pulled out. In case of packer completion wells, the packer is to be first released by applying pull. • Casing scrapping ( “Down hole” section) is done by running in a string with a casing scrapper attached at the bottom and with continuous circulation so as to lift all the cuttings to the surface. Sometimes a jet nozzle is attached to jet out sand (due to incursion) or debris which might have accumulated in the well. • Cementation (Cementation ): Normally squeeze cementation is done to shut off an interval or sometimes block cementation is done to repair or raise cement behind casing. Sometimes a zone is isolated by placing a cement plug. • Cement Drilling : As also stated earlier, in workover drilling is primarily cement drilling which is carried out to clear the hole after cement squeeze off jobs or to drilloff the plug which was earlier meant for zone isolation and to reach a prospective interval below. • Perforation ( “Logging”Section) is done to provide effective flow communication between the formation and wellbore, and this involves creating a series of holes through casing and cement--perforating. • Stimulation ( Well Stimulation Services) Well stimulation techniques are tools for improving or restoring productivity. Mainly acidising & well bore cleaning operations are carried out. • Activation (Well Testing) – Activation of a well after workover is similar activation methods applied during initial testing operations. Usually the workover fluid is knocked out with compressor applications followed by displacement of annulus volume by nitrogen. This induces a flow of formation fluid to the well bore and up the well. • Bottom hole studies ( Refer to Bottom Hole studies Section) These studies are done mainly to determine the productivity index and well fluid gradient i.e. the fluid composition of water & hydrocarbon. These studies helps in determining the type completion ( self or type of artificial lift) best suited for the well. • Completion (refer to Well Completion Section): Basically after a workover job the well is re-completed on self or suitable artificial lift after which the well flow lines are connected and the well is ready to flow. • Apart from the above certain specialized jobs are carried out such as Sand control by gravel pack , Hydrofracturing , Fishing etc. which shall be subsequently discussed under appropriate topics.

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Types of workover jobs: When a well goes off production, the problem is identified and analysed and the best course of action is decided. The following aspects helps to determine the well problem: • Studying the well’s mechanical status at the time it went off production • Equipment failures (SRP,ESP, Gas lift etc.) • Sub-surface geology for assessing the reservoir capability of further flow • Analysing the well’s past production performance • Review of the well servicing and workover history will reveal whether the well has experienced similar problems in the past Once the well’s problem has been identified, a course of action must be formulated for its repair. A workover plan is drawn out by a multidisciplinary team comprising of representatives of Workover Section, Subsurface Team, Surface Group, Well Logging , Cementing Section etc. This plan once approved by all the sections, forms the basis of workover job execution. Typical Workover jobs are as below:

1. Servicing / Installation of Artificial lift or Lift Mode change. As the name implies, this job is undertaken to replace the worn out / damaged / nonfunctional equipment. The workover rig is brought to the well (ILM-Inter locational movement) and the equipment is pulled out after subduing the well. The damaged equipment is replaced by new one and is run back into the well. Thereafter the well is reactivated by conventional methods. The pulled equipment is inspected and repaired for further use if found suitable.

2. Stimulation by acid job , Additional Perforation , Re-Perforation This category of jobs are undertaken to improve production. Acidizing : is resorted to for cleaning the well bore in case skin caused due to mud invasion. The acid (generally mild HCl) is pumped through tubing and spotted against the perforation before squeezing . After the job reverse washing by workover fluid is carried out to ensure no acid is left in the cased hole. Re-performation/additional performation: Re-perforation is carried out when perforations are clogged resulting in poor communication or for increasing permeability in low permeability zones. Perforating successively higher or lower intervals above/below the existing perforations is termed as additional perforation . this adds to the effective thickness of the producing formation , thereby enhancing the productivity of the well.

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3. Water Shut-Off Techniques If a well is producing water more than expected rate , then the possible sources of undesirable water has to be identified. The following are primary reasons for water contribution: • Perforation in aquifer – there are often water bearing zones near gas or oil bearing zones and if some perforations are made into a water zone, then this may contribute to water production. • Water coning • Encroaching oil/water contact- In a producing zone with time the water moves upwards to displace the oil towards the completed well bore. • Channel behind casing can be caused due to poor or damaged cementation behind casing. Water may flow from one zone to another through these channels behind casing. • Casing leaks WSO by Cement Squeezing: In this , the present producing interval is squeezed & plugged off by cement. The hole is then cleared to the desired oil zone interval by drilling and perforated. Subsequently the well is reactivated and re-completed. WSO by Polymer : Poly-acrylamide polymers are injected at the oil-water interface zone which absorb onto the rock matrix and remain there as a “film” that attracts water. Thereafter, all water that passes near this “film” is slowed by attraction to the polymer. However oil & gas is repulsed by the polymer and flows through the centre of the pores. In a sense, the polymer film creates a frictional, force for the water to overcome, but tends to lubricate the flow of oil and gas through the pores of a formation. The procedure is as follows: • Subdue well by workover fluid & pull out production string • Internal wire catcher trip & scrapper trip for hole clearing • Squeeze off the producing interval by cement • Cement drill & clear hole & scrape hole & perforate interval in oil-water interface zone. • Pump in polymer & seal the interval by cement squeezing • Drill cement & clear hole till the oil producing interval , scrape & perforate • Activate the well & carry out reservoir study • Complete the well by running in completion string. In case of bio-polymer water shut-off job, polymer is pumped into the producing interval followed by crude oil for well bore saturation. Channel repair job can be undertaken by Block cementation technique discussed under “Cementation”. In case of micro-channels behind casing, recently IPT-Seal job designed by IOGPT have been tried in wells of Lakwa & Rudrasagar fields.

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Casing leaks can develop as a result of corrosion , abrasion etc. This can be repaired by either cutting the string above, retrieving it and then replacing it OR by squeezing cement in the leak portion so as to seal it off.

4. Zone transfer: Sometimes need arises to shift to another zone interval from the present one due to poor productivity of oil & gas. If one has to move from a lower zone to a upper one, then zones can be separated by setting a bridge plug or placing a cement plug in between . If need arises to move from a upper zone to a lower one then the upper zone can be simply squeezed off by cement, the plug drilled through and lower zone interval perforated & subsequently activated & well completed. 5. Water injection & effluent disposal wells servicing & conversion Water injection in a field is undertaken for maintenance of reservoir pressure. These wells develop problems mainly due to scaling and subsequent poor injectivity. The completion string have to be pulled out , the cased hole cleared by scrapping , injectivity improved by acid job & reperforation if required and finally re-completed. Similar workover job is also carried out in Effluent disposal wells. Sometimes a sick oil or gas well is converted into a water injector or ED well. The producing interval is squeezed off by cement and the interval earmarked for water injection or effluent disposal is “opened up” by perforating, required injectivity established or improved by acid job if required and the well is completed as WI or ED well.

6. Sand control by gravel pack: This has been discussed in the Well Stimulation Services Section.

7. Well abandonment : In this cement plugs ( usually two ) are placed at appropriate places in the well and a plate is welded on the casing head. The plugging operation has been discussed in the Cementing Section.

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Well Stimulation Services Initially or during the producing life of a well it may not produce as expected or may go off production for many reasons. Well stimulation techniques are tools for improving or restoring productivity. WSS-ER came into being its present entity in 1983-84 to fulfill the need of stimulation and specialized services for enhancing oil & gas production. WSS provides services in following areas. Stimulation Services: Acidization Hydraulic fracturing

Specialized Services: Coil tubing Services Nitrogen Services Sand Control by Gravel Pack Water shut off by polymer Hot Oil Services

Major equipments with WSS , ER are listed below. 1. 2. 3. 4.

Acid pumper Coil tubing unit Nitrogen pumper Hot-oiler unit

ACID PUMPER: Though it is called Acid pumper carrying out acidizing jobs , it is also being used for various pumping jobs such as pumping polymer for Water Shut-off job and pumping brine for well killing.

ACIDIZING:

I.

Acid Washing or Clean-up

This operation is designed to remove acid soluble scales present in the well bore or in open perforations. It involves spotting a small quantity of acid at the desired position in the well bore and allowing it to react, without external agitation, with scales/ deposits on the formation.Acid can be circulated back and forth across the perforations or formation’s face. Stimulation occurs primarily from removal of flow restrictions in the tubing or perforations.

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II. Matrix

acidizing :

This type of acidizing treatment is designed to remove skin damage that extends beyond the immediate surface of the perforations or the face of the producing zone. Acid enters the pore space of the formation below fracturing pressure and dissolves both the surface of the rock and the flow restricting contaminants within the matrix. A matrix acidizing treatment may be effective penetrating into the formation only a few inches or up to several feet from the wellbore, depending on formation permeability. In wells that have suffered from skin damage, production can increase many-fold. However, if a well had little or no skin damage, an acidizing treatment stimulates natural production little more than one to two times, depending on its design. Acids used in Upper Assam fields are •

•

Hydrochloric acid (HCL) : Hydrochloric acid (HCl) is the workhorse of the stimulation business, finding extensive use in both carbonate and sandstone acidizing. Many acidizing treatments employ HCl to some extent. Usually, it is used as a 15% solution when treating carbonate formations. In sandstone acidizing, 5 to 7.5% HCl is often used ahead of hydrochloric-hydrofluoric acid mixtures to prevent precipitation of formation-plugging reaction products. Hydrofluoric acid (HF) : Hydrofluoric acid is the primary dissolving chemical used in sandstone acidizing. In these applications, HF is usually mixed as a dilute solution with HCl, or an organic acid. Its principal use is to dissolve siliceous minerals. HF is the only acid that reacts either siliceous minerals such as sand and clays. The reaction of HF on quartz (SiO2), a primary component of sand, is:

4HF + SiO2 → SiF4 + 2H2O SiF4 + 2HF → H2SiF6 Here, the end reaction product, fluosilicic acid (H2SiF6), is soluble in water, but its potassium and sodium salts are insoluble. Hydrochloric-hydrofluoric acid mixtures are the chief solutions used in matrix acidizing of sandstone. The mixtures is formed from the reaction of ammonium bifluoride (NH4HF2) or ammonium fluoride (NH4F) with HCl. Water shut-off by polymer : Dilute poly-acryl amide polymers are injected into a well to restrict water production. Polyacryl amides adsorbs on to the rock matrix and remains there as a film that attracts water. All water that passes near the film is slowed by attraction to the polymer but oil or gases are repulsed by the polymer which causes oil or gas to flow through the centre of the pores. An injectivity of 300 litres per minute at 1000 psi is desired for polymer pumping into the formations in Assam Asset.

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Coiled Tubing Unit (CTU)

The coiled tubing unit is a second generation workover system employing continuous string tubing to carry out various workover and well maintenance jobs on the live wells. The 1 inch or 1 ¼ inch continuous tubing is stored on a ‛reel’ and coiled upon itself in the same manner as the flexible cable of a logging unit. The tubing is straightened and lowered in the hole by an ‛ Injector ’, installed directly on the well head through a ‛stripper’ which allows the lowering and pulling out of coiled tubing under pressure. The ability to circulate fluid e.g. water, oil, acid, mud cement slurry or gas e.g. air, nitrogen through the coiled tubing while the tubing is lowered or raised makes the coil tubing unit a very versatile equipment to carry out sand clean out, paraffin plug removal , cement squeeze , acid spotting jobs etc.

NITROGEN SERVICES

For oil field works, nitrogen is pumped as a liquid at about -1960 C by high pressure cryogenic pumping equipment on Nitrogen Unit. The liquid is passed through a high capacity heat exchanger to develop warm dry nitrogen which is subsequently injected into the well. The standard equipment comprises of an insulated vessel which carries liquid nitrogen, a cryogenic pumping system and a vaporizer unit to convert liquid nitrogen to gaseous form. The cryogenic high pressure vaporizer is a direct fired vaporizer and its heater produces heat by burning diesel.

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Nitrogen is circulated down the annulus with returns from the tubing for displacing fluids from a well. Pre-calculated tables called Zip tables showing nitrogen gas volumes over a range of pressure in a well is used to calculate displacement volume in the well.

HOT OILER UNIT Hot oil pumping unit are used for • Hot oiling a well through tubing • Circulating and heating a tank • Hot oiling a flow pipe line. The unit comprises of: a. Heater – This is made of heating coil (Steel tube) & burner which heats the oil from outside. b. High pressure pumping unit - for pumping the heated oil to a high pressure ( upto 10000 psi) into well or flow line. c. Storage tank for oil The hot oiler is connected to the well head by chicksons. Hot oil is pumped into the well circulated out. Paraffin melts and thus removed. Hot oil jobs can also be done by CTU.

SAND CONTROL GRAVEL PACK JOB: A certain amount of sediment will always be produced along with formation fluids . Sand control is the technology and practice of preventing sand flow from unconsolidated sandstone formation. Sand production may lead to the following problems: • • •

Completely plugged (sanded up) wells Reduced productivity Abrasion of downhole and surface equipment

There are various methods of sand control. The method commonly employed in this region is Cased Hole Gravel packing. The completion intervals are perforated with high density, large diameter perforations capable of penetrating the damaged zone. The perforation damage is cleaned out and a cavity created behind the pipe by backflushing & backsurging, The screen is run and the gravel pumped into the void outside the casing, the perforation tunnels and casing/screen annular area. The key to success is the creation of a cavity behind the casing to permit effective packing of a high-permeability path through the casing, cement, and damaged zone, out against the native formation. The perforations through the casing should have a large diameter (3/4 to 1 in., or 19 to 25 mm) and high density (8 to 12 shots per foot [spf], or 26 to 39 shots per meter [spm]) in order to achieve maximum flow area. The gravel size is optimized to achieve the maximum permeability that can completely stop the formation material at the formation-gravel interface. Gravel should be placed without incurring mixing of gravel with formation solids. Gravel should be tightly packed in the liner-casing annulus

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and in the perforation tunnels, without any voids (i.e., a packing efficiency of 100%). All completion fluids should be very clean and not create formation damage.The liner screen should be designed to achieve minimum flow resistance while still preventing any gravel from entering the tubing string.

Schematic of internal gravel pack The crossover tool circulation method is commonly employed for GP job. The slurry travels down the tubing, through a crossover tool located below a packer and down into the screencasing annulus. The returning fluid passes through the screen and travels up a tailpipe, through the crossover tool, and then up the tubing-casing annulus.

Crossover tool circulation method

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HYDRAULIC FRACTURING Hydraulic fracturing is a type of well stimulation treatment designed to bypass nearwellbore damage and improve the fluid flow path from the formation to the well.

The hydraulic fracturing treatment When a hydrocarbon producing well is drilled and completed, even if the best practices are followed, a certain "damage" is created around the wellbore.This damage takes the form of an additional, uninvited resistance to hydrocarbon flow. Since in most cases the flow of fluids is converging radially toward the wellbore, this extra resistance causes a very large loss of pressure, decreasing the overall well productivity. In a hydraulic fracturing treatment, a highviscosity fluid is injected into the well at treating pressures that are higher than the so-called formation breakdown pressure (practically speaking, the minimum horizontal stress.) These high pressures typically result in the propagation of a two-wing, vertically oriented. Fluid injection continues for some time beyond this initial propagation, and when the created fracture is wide enough to accept them, solid particles (sand or some other type of proppant material) are injected simultaneously with the carrying fluid. The proppant material gradually - 30 -

fills up the fracture so that when the pumps are stopped, the fracture faces gradually close on the proppant. The propped-open, vertically oriented fracture that results from a successful treatment might be several dozen or several hundred feet high, and possibly several thousand feet long. Although it will typically be only a fraction of an inch wide, it will drastically change the streamline structure in the formation. Not only will it bypass near-wellbore damage, but it will also impart a bilinear rather than a radial flow structure that can enhance well productivity by as much as four to six times that of the initial stabilized rate.

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CONCEPT OF INITIAL WELL COMPLETION WELL TESTING After drilling is completed , the well is cased, cemented & fitted with control equipment like well head and X-mas tree assembly & BOP and handed over to production for testing, completion and safe production of oil & gas. The well testing involves the following activities: • Hermatical testing of casing , well head, X-mas tree assembly and BOP. • CBL-VDL • Perforation of casing • Activation of well • Well testing , to ascertain rate of flow of fluid • Bottom hole studies to ascertain reservoir data Hermatical testing of casing and well head etc. Before taking over the well from Drilling department , hermatical test of the casing & casing head is carried out. The well is first scrapped with a scrapper upto the bottom with drilling BOP fitted over the well head. The bop is then removed and X-mas tree fitted over the well head. Drilling mud is the displaced by brine and the well washed thoroughly. The casing , casing head and X-mas tree is then pressure tested separately to the maximum pressure expected in the formation in brine for about half hour. After this the X-mas tree is removed and the BOP re-installed after testing it to 1.5 times of working pressure. CBL-VDL and Gamma-neutron logs are taken for ascertaining cement bond and depth control. Perforation : The selected zone is perforated to establish communication between the well and formation. During perforation , there is chance of blowout if the formation fluid is not kept under control. Activation of the well : After a well is perforated , it is activated to induce flow of formation fluid to the well bore , and then tp the surface. This is done by the following: 1. Displacement of kill fluid with brine , water , diesel or crude oil as per requirement of the well. Displacement is done in stages so that the reduction in hydrostatic head is gradual and in case the well becomes active , the flow is well controlled one. 2. Compressor / Nitrogen application : The well is pressurized by Compressed air injection followed by pumping of nitrogen . After this the annulus pressure is released through a bean to induce formation fluids into the well bore. 3. Swabbing : A swab tool is run in and then pulled out at a steady rate so as to avoid pressure surges. Testing of the well: The final stage of well completion operation is the testing of wells. The purpose of the test is to ascertain the potential of the perforated horizon to produce hydrocarbon. In the beginning when the well starts producing oil & gas the products are lead through a bean in the line to an

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open pit but immediately thereafter portable separators and tanks are connected to the well. Oil & gas are separated in the separator, the gas is diverted to a flare line and burned. Oil settles in the separator and when the level reaches a pre set limit , it is discharged automatically into a tank. The flow rate of oil is thus measured . The bean regulated and controls the flow and pressure of fluids from the well. Bottom Hole studies: After testing studies are under taken to ascertain various reservoir parameters of the zone whether producing or static. Pressure & temperature in the well are recorded and sample of well fluid is drawn & analysed. After a zone has been tested, the well is subdued , X-mas tree removed , tubing pulled out , bop installed and a bridge plug is set to isolate the tested lower zone . Preparations are then made to test the upper zone.

WELL COMPLETION: After successfully drilling and evaluating a well, the next decision is whether to complete or abandon it . In abandoning a well , a cement plug (or plugs) is set in the hole , whatever casing can be removed is recovered , and the drillsite is returned to its orginal condition. The next step toward completing a well involves the running of the final string of casing – the production string. The manner in which this is done determines the basic completion method and may follow one of several configurations. The completion methods employed in Assam can be classified into the following: 1. Completion based on the Interface between the Wellbore and Reservoir • • •

Openhole completion: in which the producing formation is not isolated by the casing , which extends only to the top of the producing interval Liner completion: which is not cemented and not tied back to the surface Cased and perforated completion: which involves cementing the production casing across the productive interval and then perforating the casing for production.

2. The Production Method • •

Self flow Artificial lift – Gas lift, Sucker rod pump, Electrical Submersible pump,

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Openhole completion

Liner completion

Cased & perforated completion

Artificial Lift Systems If the producing bottom hole pressure becomes so low that it will not allow the well to produce at a desired flow rate , some sort of artificial energy supply will be needed to lift or help lift the fluid out of the well bore. This energy can be supplied through a variety of artificial lift methods that are applied at the producing well itself. The common methods of artificial lift system employed in Assam Asset are: • Lightening of the fluid column by gas injection (Gas Lift) • Subsurface pumping (SRP & ESP)

Gas lift : The purpose of any artificial lift system, including gas lift, is to reduce the bottom hole pressure in order to allow the well to flow under the existing formation pressure. With gas lift, this can be accomplished by forcing gas through a choke or control valve, located at the surface, down the annulus and then through valves into the tubing. The injected gas aerates the

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liquid column in the tubing. The aeration reduces the bottomhole pressure caused by the weight of the column of fluid in the tubing. With sufficient aeration, the bottomhole pressure may be reduced to a point where the well once again begins to flow. The continuous aeration of the fluid column in the tubing will cause more oil to flow from the formation into the wellbore and then to the surface. Over time, though, as more fluids are produced, the average reservoir pressure decreases, requiring increasing amounts of aeration to maintain a constant production level. A typical pressure operated gas lift valve is shown below.Nitrogen is normally injected into the dome and charged to a specified pressure. The bellows serve as a flexible or responsive element. The movement of the bellows causes the stem to rise and fall and the ball to open and close over the port. When the port is open, the annulus and tubing are in communication. The gas lift valve is contained in a gas lift mandrel which is a tubing component.

. GAS LIFT VALVE

GAS LIFT SYSTEM Sucker Rod Pumping System

In sucker rod pumping the pumping motion is transmitted from the surface to the pump by means of a string of narrow jointed rods placed within the tubing. The pumping system consists of : • Subsurface pump- which displaces the fluid at the bottom of the well and thereby reduces bottomhole pressure. - 35 -

• • •

Rod string-transmits power to the pump from the surface Surface unit- which transfer rotating motion to a linear oscillation of the rod string Gear reducer – which controls the speed of the motor or engine that is the prime mover.

Sucker Rod Pumping System The subsurface pump is essentially a plunger and valve arrangement within a tube or barrel. When the close fitting plunger is lifted within the barrel, it creates a low pressure region below the plunger, which is filled by fluid from the formation. Simultaneously, the plunger and rods lift fluid up the tubing . The valves are designed to open & close so that they allow fluids to enter the pump on the upstroke and be displaced above the travelling valve on the down stroke. The fluid above the travelling valve moves one full stroke upward on the upstroke .

Electrical submersible centrifugal pumps This is a rodless pumping system. Electrical power is supplied via a bank of transformers that convert primary line voltage to system voltage. Power is transmitted through the power cable to an electric motor at the bottom of the tubing string. The motor is isolated from well fluids by a protector. Above that is a gas separator and the motor driven pump, which normally is a multistage centrifugal pump.

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DOWNHOLE SERVICES: The Down hole section provides the following specialized equipment & expert services mainly to Workover Group. • • • • • •

Drill Bits - Rolling cutter bits , Drag bits Milling tools – PMT, CMT, FMT Packers Bridge plugs & cement retainers Fishing Operations Wireline services

Drill Bits : Bits are available in a bewildering array of types and mainly grouped into two basic categories – Rolling cutter bits & Drag bits. Rolling cutter bits, also known as roller cone bits, consist of cutting elements arranged on cones (usually three cones, but sometimes two) that rotate on bearings about their own axis as the drill string turns the body of the bit. Materials such as steel and diamond are used for the bits.

Fixed cutter bits, also known as drag bits, consist of stationary cutting elements that are integral with the body of the bit and are rotated directly by the turning of the drill string.

MILLING TOOLS: Milling tools are used to mill away stuck fish that cannot be retrieved by conventional fishing methods. Peripheral milling tool (PMT) is used for milling over bridge plugs / cement retainers & permanent packers and subsequently can be pushed downhole. Conical milling tool (CMT) & Flat (Frazer) Milling tool (FMT) are used to mill tubing ends , internal casing cuts , washovers pipes etc. - 38 -

PACKERS: The packer seals the casing-tubing annulus with a rubber packing element, thus preventing flow & pressure communication between tubing and annulus. Packers are used mainly for the following reasons: • • • • • •

to improve safety by providing a barrier to flow through the annulus to keep well fluids and pressures isolated from the casing to separate zones in the same wellbore to keep gas lift or hydraulic power fluid injection pressure isolated from the formation to isolate a casing leak to facilitate temporary well service operations (e.g., stimulations, squeezes)

Packers are designed either to remain in the well permanently or to be retrieved if future downhole work is required. Retrievable Packer is run on the tubing. After setting, it can be released and recovered from the well on the tubing. Since it is an integral part of the tubing string, the tubing cannot be removed from the well without pulling the packer, unless a detachable packer head is used. Retrievable packers may be designed to be set mechanically or hydraulically. Mechanical setting methods include rotation of the tubing string, reciprocation of the tubing string, or the application of tension or set-down weight. With mechanical packers, the tubing is usually set in compression. Hydraulic packers are set by applying hydraulic pressure through the tubing string, but once set they hold the set position mechanically. The tubing is usually in tension.

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For packer setting a shear release seal assembly is used. A pump out ball seat near the bottom of the tubing provides a means of applying setting pressure . After the packer is set the ball and seat is pumped out.

Retrievable Packers

Permanent Packer

Permanent Packers are independent of the tubing and may be run on tubing or on wireline. The tubing can be released from the packer and can be pulled, leaving the packer set in the casing. Tubing can subsequently be run back and resealed in the packer. The packer may thus be considered an integral part of the casing. The permanent packer cannot be recovered as such, but it can be destructively removed (e.g., by milling)

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CASING SCRAPPER: A casing scrapper is used to remove foreign substances, such as scale, perforating bars, cement from inside the casing wall. The scrapping action is provided by spring tensioned blade against the casing wall.

BRIDGE PLUGS: A bridge plug is set in the casing to prevent the flow in the casing. Bridge plugs can also be set between perforations to isolate the lower perforations from the upper zone. It can be set either mechanically or by wire line.

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CEMENT RETAINER: Cement retainer is a special packer that is used in squeezingcement mainly for remedial block cementation (cement rise behind casing). A cement retainer has two way valve. When the tubing to which the retainer is attached is picked up, the retainer valve closes (stabbing tool is used along with tubing) When the stabbing tool is stabbed to the retainer the valve opens. The closed valve holds final squeeze pressure as the excess cement is circulated out. For block cementation method refer to “Cementation Section”.

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FISHING OPERATIONS Fishing jobs-attempts to recover pipe or other objects that become lost or stuck in the well-can be among the most challenging of well operations. Not only does fishing require specialized equipment and high levels of expertise, but its success often depends on intangibles like common sense, intuition...and even luck. Fishing jobs can be classified into four general categories, based on the type of material in the hole: • Stuck pipe:: Circumstances under which pipe becomes stuck include differential pressure sticking, key seating, solids accumulation and mechanical sticking. • Parted pipe: : When the drill string parts in the well, it is most often because of metal fatigue. • Junk Examples : are bit cones, tong dies, hand tools, float collar remnants or other relatively small objects that get left in or dropped down the hole. • Wireline tools , balled-up piano wire etc. Locating the stuck pipe interval Once we know how the pipe became stuck, we have to determine where it is stuck so that we can design our recovery procedures. In other words, we have to determine the free point--the depth above which the string is completely free. For our initial free point estimate, we take a stretch reading to see how far the pipe moves when we pull a certain weight above the string weight. While not as accurate, stretch readings provide a good approximation. Once we determine an approximate free point, a pipe recovery logging tool can be run in to determine accurately the free point. This tool is similar in some ways to a conventional cement bond log. It provides us with acoustic measurements in which high energy readings indicate free pipe and low-energy readings indicate stuck pipe. If we can't free stuck pipe (working and jarring it from the surface), the next step is to back off, or unscrew the string above the free point. This allows us to retrieve and lay down the free pipe so that we can run fishing tools to engage the remainder of the string. When a normal back-off is not possible, a string-shot back-off programme can be planned. This is a wireline tool containing a precise amount of detonating cord that produces an explosion at the back-off point. We can run this tool by itself or with a free point indicator. Once the tool reaches back-off depth, a predetermined amount of left-hand torque is applied. The wire line operator detonates the cord, and the force of the explosion unscrews the pipe. When backing off is not practical-or when our efforts are unsuccessful--we may use chemical or jet cutters. Chemical cutters in particular can provide fast, smooth cuts when properly applied, and do not require putting torque on the pipe.

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Free point log

String shot detonator

FISHING TOOLS for pipe recovery

Engaging the outside diameter OVERSHOT: Its inside diameter is fitted with grapples, which are helically tapered spiral sections sized to fit given pipe diameters. To engage the fish, the overshot is first lowered down on top of the pipe. It is then rotated slowly to the right and, at the same time, lowered over the outside of the fish If the top of the fish has jagged or flared ends, it may be necessary to smooth them out with a milling shoe before engaging with the overshot.

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BOX TAPS, COLLARS,

OR

DIE

These are internally machined one-piece tools with wickers designed to engage the outside of the fish. Made of case hardened steels, they function as threading tools to cut threads on the upper end of a fish. This permits the part left in the well to be pulled. A die collar may be run to the top of the pipe while maintaining circulation to help clean out solids. When it reaches the top of the fish, circulation is stopped and a light weight is applied to the fish. The tool is then rotated, embedding the wickers in the fish, until it cuts enough threads to provide a firm grip; rotation is then stopped and the fish is pulled.

WASHPIPE OR WASHOVER PIPE is a thin-walled tubular, run in sections to clean out the annulus around stuck pipe. In its simplest configuration, it is run with a rotary shoe. This assembly is rotated and lowered over the fish while maintaining circulation to remove solids from outside of the pipe. Circulation continues until the fish is completely washed over or it reaches the top of the wash pipe. The crew then pulls and lays down the wash pipe, and then runs other tools to engage and pull, cut or back off the fish.

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Engaging the inside diameter When there is not enough clearance between the pipe and hole to run an overshot or other externally engaging tool, we may try and latch the pipe's inside diameter.

TAPER TAP are externally threaded to engage the pipe's internal diameter in much the same way that a box tap would engage the external diameter RELEASING SPEARS are designed to internally engage all but the smallest inside-diameter pipes A releasing spear contains slips that can be set by rotating the fishing string once the tool is inside the pipe. The slips can be released by bumping down and rotating the string--an advantage over taper taps, which do not have a built-in releasing mechanism. Releasing spears can be run in combination with back-off or cutting tools and pulling equipment.

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Internal Spear Taper Tap

Wireline Tool Recovery Fishing for wireline tools requires different equipment from that used in pipe recovery. The main concerns with wireline tools are that the cable can become tangled or wadded in the hole, or that fishing attempts may cause the wireline to pull out of the rope socket or even part, making retrieval of the tool more difficult. To recover dropped wireline that may have become wadded or tangled, we can use a wireline barb or rope spear to penetrate, engage, and pull the debris

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Junk & Boot basket Junk & boot baskets remove milled or drilled material from a well. A junk basket is run on the bottom of the work string along with junk mill at the bottom of junk basket. By reversing or forward circulation (depending on tools) cutting is swept into an inner chamber or basket. Steering material that cannot be circulated out to the surface are caught in the basket and retained when the basket is pulled to the surface.

MAGNETS are useful for retrieving iron-containing metal objects. They can be run on drill pipe or wireline Magnets are designed to extend their magnetic field axially, or downward, to prevent damage as they are lowered through casing. IMPRESSION BLOCK Beyond establishing the type of fish--pipe, wireline or junk--it is not always easy to determine what is "looking up" at us from a well. The fish may be aligned at an angle, the end of a joint of pipe may be jagged or flared, or there may be hole restrictions. We can use an impression block to determine the condition and configuration of the fish or casing string. This tool consists of a steel body holding a molded piece of lead or wax. When we lower the block down on the fish, an impression of the fish forms on the soft material.

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LOGGING SERVICES Perforation: Once a well has been cased and cemented we must provide effective flow communication between the formation and wellbore, and this involves creating a series of holes through casing and cement--perforating. Cased holes may be perforated by the following methods: • Conventional casing guns which are run into the well on electric wireline with or without wireline pressure control equipment • Through-tubing guns which are run into the well after the tubing has been installed, again via wireline pressure control equipment • Tubing-conveyed guns which are run on the bottom of the tubing string and detonated using mechanical, electrical, or pressure-activated firing mechanisms

The completion designer also has the option of perforating overbalanced, with a higher pressure in the wellbore than in the formation, or underbalanced, with a wellbore pressure lower than formation pore pressure. Generally speaking, the larger-diameter casing guns run via wireline will give larger hole diameters and greater penetration depths than the smaller through-tubing guns. Throughtubing perforating, however, provides a safe, practical method for perforating underbalanced. - 49 -

Underbalanced perforating has been generally accepted as a technique that can help to maximize well productivity. Tubing-conveyed perforating provides a means to combine both high-performance guns and flexible pressure conditions. Shaped Charge Operation is generally used for perforation. The firing is initiated electrically or mechanically by the detonator (blasting cap) via the detonating cord (Primacord), which in turn sets off the primer explosive. The primer initiates detonation of the main charge. Explosive pressure on the metal liner causes it to collapse inwardly along its axis forming a high-velocity jet of fluidized metal.

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Acoustic Bond Logs Cement-Bond Log (CBL)/ Variable density log (VDL) The CBL is an acoustic device used to detect the presence of cement. The tool includes an omni directional acoustic transmitter and usually two receivers located 3 and 5 ft (0.91 and 1.52 m), respectively, from the transmitter. The tool emits an acoustic signal, which is detected by these receivers. Figure 1 shows a schematic of the CBL tool with possible acoustic paths from the transmitter to receiver.

Figure-1

Figure 1 shows that, excluding the path through the tool, there are four possible acoustic paths for the acoustic signal to get to the receiver. The tools are designed to suppress the signal traveling through the tool. Of the remaining four paths, the one through the casing is likely to be the fastest, since an acoustic signal is known to travel relatively quickly through steel pipe. Thus, if the casing signal is fastest, it is the first of the four to arrive at the receiver. The next signal to arrive at the receiver is the one passing through the formation. The other signals either arrive later or are greatly weakened by the time they get to the receiver. Figure 2 shows the makeup of the received acoustic signal. The acoustic signal is affected by cement contacting the pipe in that the cement, which is coupled to the pipe in shear, tends to dissipate the signal energy as the signal propagates down through the pipe. The greater the cement annular fill contacting the pipe, the weaker the signal at the receiver. The effect of a good cement job on the received signal is to weaken the pipe portion of the signal while strengthening the formation portion. The formation signal is strong because there is no fluid gap for the signal to cross behind pipe, leaving a solid, unbroken acoustic path. Hence the signal passes freely through the casing to the formation and returns. When no cement is present, the condition is called free pipe and the pipe simply "rings" rather loudly as the pipe signal reverberates. Figure 3 illustrates the wavetrains associated with the various conditions of cement behind pipe.

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Figure 2

Figure 3

- 52 -

The variable-density log (VDL) is also derived directly from the wavetrain. Referring to Figure 2 , the VDL is made up of numerous closely spaced exposures of the film by the positive wavetrain amplitudes. The result is a contour map of the history of the wavetrain over the logged interval. Notice in Figure 2 that the pipe portion of the received acoustic signal appears as strong straight lines. If the tool is centralized, the acoustic path of the pipe signal does not change during the logging operation, and hence the signal always arrives at the same time and at the same frequency. The formation signal, on the other hand, comes in at all different times, since the cement thickness may vary and the acoustic properties of the formation change from one point to the next in a well. While the VDL theoretically is shaded for degrees of amplitude, it almost always appears as a black and white set of lines. Notice in Figure 3 that in a very good bond, the pipe portion of the VDL does not show up because the amplitude of the wavetrain is too low to expose the film. The formation signal, however, comes in quite strongly. With poorer bonds, both the pipe and the formation signals may be present.

Circumferential Imaging Tools Circumferential imaging tools (e.g., Halliburton’s Circumferential Acoustic Scanning Tool (CAST-VTM) and Schlumberger’s Ultrasonic Imager (USITM)) employ single rotating head transducers to transmit and receive high-frequency ultrasonic pulses in the wellbore. These pulses are recorded and processed to obtain 360o profiles of casing and cement images in real time. Schlumberger’s USI tool, for example, directly measures the acoustical impedance of the medium behind the casing string. These measurements can be processed into high-resolution cement impedance images, which accurately indicate cement placement and zones of hydraulic isolation. This tool can also provide information on casing condition, in the form of detailed images showing internal radius, thickness and both internal and external metal loss.

Cased Hole Formation Resistivity (CHFR) Log Resistivity logs measure the resistivity or conductivity of the rocks and their saturating fluids to an electric current. A voltage source sent a current through the ground between two widely spaced electrodes. The voltage drop between two other more closely spaced electrodes is used as a measure of the ground resistivity. Cased hole resistivity tools provide deep-reading resistivity measurements through steel casing. Such resistivity measurements can be used for: • detecting and evaluating bypassed hydrocarbons, • monitoring the reservoir to track fluid movement, • making accurate saturation calculations in formations with deep invasion, • optimizing sweep efficiency for improved production, The Schlumberger CHFR tool uses four levels of three voltage electrodes. The electrodes on each level are spaced 120 degrees apart. After establishing good contact with the casing, the tool transmits an electrical current. Most of the current will remain in the casing, where it flows both upward and downward before returning to the surface. However, a very small portion of the current will escape into the formation, and the casing will tend to act as a focusing electrode to force the current deep into the formation. While logging, the currents that escape to the formation cause a voltage drop in the casing segment. Electrodes on the tool

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measure the difference in electrical potential that is created by this leaked current. The difference in potential that is detected by the CHFR tool is measured and this is proportional to the conductivity of the formation.

Caliper Logs by Mechanical Calipers Mechanical calipers are of two basic types. The bow-spring type caliper is typically run with a flowmeter, and is used to monitor the inside of the pipe. Its use is critical when restrictions such as asphalt, paraffin, or scale buildup are likely. The other is the multifinger type, with anywhere from 40 to 80 individual fingers. As these fingers scrape the pipe wall, their maximum deflection is monitored.

Multi-finger type

Bow-spring type caliper

Casing collar locator Depth control in a cased hole is achieved by running a gamma ray and collar locator, typically at the time of perforating. The cased-hole gamma ray log, which responds to formations’ natural radioactivities is similar to an openhole gamma ray log. Correlation of these two logs enables easy location of the collars with respect to down-hole zones. A short joint of pipe at or near the zone of interest is very helpful in accurate depth control. The figure shows a typical gamma ray and collar locator survey.

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Gamma ray and collar locator survey

Production logging tool: The tools used to quantitatively evaluate flow volumes downhole are the radioactive tracer/gamma ray and the flowmeter. The radioactive techniques are used mostly in injection wells, since they are relatively easy and inexpensive and there is no danger of radioactive material coming to the surface. The flowmeter is most often used in producing wells, where use of the radioactive tracer is rare. For evaluations to be made when multiphase flow is present, flowmeters are commonly used. The two types of turbine flowmeters are the small-diameter and the full-bore. These tools are run continuously over the interval of interest, making a number of logging passes, usually in both the up and down directions, all at different logging speeds. These tools respond to the bulk flow rate, even in multiphase flow. They are best suited for use in vertical wells, but also may be used effectively in deviated wells, especially at higher flow rates. For radioactive tracer logging, the tool is held stationary and a small cloud of radioactive material is ejected into the flow ( velocity shot technique),. As this cloud passes two gamma ray detectors on the tool below the ejector, a measurement is made of the time of transit between those detectors. This measurement is made by recording the response at the detectors while the film is scrolling at a constant rate.

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BOTTOM HOLE PRESSURE STUDIES: Bottom hole pressures are measured so as to have an idea of formation zone conditions mainly for deciding the completion strategy ( artificial lift). The pressure gauges are small enough in diameter which makes it possible to be run through the tubing. BHP is determined with continuously recording pressure gauges. The pressure element and recording section are encased and sealed against external pressure except for an opening to communicate the pressure to the element. The entire instrument is run to the depth at which the pressure is to be measured , allowed to stabilize thermally , and then returned to the surface and the pressure determined from the chart . The self-contained gauges have three essential components: a pressure-sensing device, a pressure-time recorder, and a mechanical clock. The pressure element of a mechanical gauge is normally a multiple-coil Bourdon-tube type . Well pressure is transmitted through a rubber diaphragm to fluid contained inside of the Bourdon tube. Pressure increases cause the tube to uncoil. The rotation is transferred to a stylus that makes a mark on a coated-metal chart. The recording chart is moved vertically by a clock, with the time of movement along one axis of the chart dependent upon the clock selected (2 to 360 hours). The stylus is moved perpendicular to this direction by the Bourdon tube as it records pressures, and the movement of the chart by the clock records time. The relative motion of each yields a pressure-time chart. A vapour pressure type recording thermometer can be run in combination with this to obtain continuously recorded temperatures and allow correction of pressure measurements. In Workover operations generally the following studies are conducted: 1. Recording Liquid Level & Static Bottom Hole Pressure after well has been activated subsequent to perforation in the zone. 2. Influx Study: In this the well is activated by compressor applications followed by nitrogen job. The BHS tool is lowered without releasing the pressure in the well. The well pressure is then released and with the influx of fluid from the formation there is pressure/level rise which is recorded by the tool.

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CEMENTATION Cementing operation is performed immediately after casing has been run in the hole. This is called Primary cementation.The slurry is formed by mixing water with Portland cement, or with cement blended with additives. Cement slurry is forced into the annular space between the casing and the wall of the hole, where the cement can set and form a permanent barrier against water and other fluids. Protection of the well and prevention of possible value loss are two vital considerations in cementing. • Protection Against Pressure, Corrosion, and Shock Loading; Maintenance of Casing Support • Prevention of Fluid Migration, Lost Circulation, Pollution, and Blowouts Major components of surface-cementing equipment are: • mixers or blenders • pumping/displacing unit • cementing or plug-release head Dry cement must be mixed with the proper amount of water to ensure that slurry and setcement properties are as designed. For most slurries, the jet mixer produces a uniform mixture. The jet mixer induces a partial vacuum at the venturi throat, drawing in the dry cement. High stream turbulence then provides thorough mixing. Density measurements are made to gauge consistency and control the mixing operation. Density is measured on samples with balances (two types). JET MIXER The typical slurry-pumping unit is truck-mounted, and contains diesel engines and displacement tanks that are accurately graduated so that water or mud volumes can be controlled to place the slurry downhole properly.

Slurry Pumping unit

CCementing Head

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In operation, the pumper draws slurry from the mixer. Cementing heads provide a connection for pump-truck and rig-pump lines into the casing. In Two plug primary cementation , a predetermined volume of slurry is pumped into the casing between two wiper plugs. The bottom plug ruptures when it seats; the top plug is solid. The top plug is displaced with mud or completion fluid. Flow stops and pressure builds when the top plug lands. Check valves in the float shoe to prevent backflow of the heavier column of slurry in the annulus. The cement rises and fills the gap between the formation & casing.

Two plug primary cementation

Squeeze Cementing In Workover squeeze cementing is mainly carried out for the various purposes. Squeeze cementing is the process of forcing a cement slurry through holes in the casing. Its primary objective is to create a seal in the casing-wellbore annulus. The purposes for which squeeze cementing is carried out are as below: • repair of a primary cement job that failed because of cement bypassing mud (channeling) or insufficient cement height (fillup) in the annulus • elimination of water intrusion from above, below, or within the hydrocarbonproducing zone — commonly called "block squeezing" • reduction of the producing gas/oil ratio by isolating gas zones from adjacent oil intervals • repair of casing leaks caused by corrosion or split pipe

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• plugging of all or part of one or more zones in a multizone injection well to direct injection into desired intervals • plugging and abandonment of a depleted or watered-out producing zone The basic components and concept of squeezing are illustrated in the figure:

Concept of cement squeezing

Bradenhead versus Packer Methods The Bradenhead squeeze technique is normally used on low-pressure formations. Usually, the interval to be squeezed is at or near the bottom of the well. The operational steps of the general procedure are as follows: • Circulate cement across the zone to be squeezed. • Pull drillpipe (or tubing) above cement. • Close BOPs or annulus valve and apply pressure to cement through drillpipe. • Reverse out excess or Wait on cementation (WOC) and pull out. Squeeze pressure is limited by casing-string and wellhead-burst strength, so the technique is usually used with a low-pressure squeeze. It is not a precise cement-placement technique, and

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is not generally recommended with several open intervals and only one to be squeezed, or where casing is not pressure-tight. Packer-squeeze techniques permit precise slurry placement and isolate high pressure from casing and wellhead while high squeeze pressures are applied downhole. A packer squeeze can be conducted with either drillable or retrievable squeeze packers.

Bradenhead Method

Block cementation by cement retainer: The drillable cement retainer is the best tool available for single interval squeeze , batch or block squeeze cementing . The retainer has two way valve and can be controlled from the surface . The tubing with stabbing tool can be set down to open the valve & can be picked up to close it. For block cementation i.e Squeeze cementing shut-off of channeling between zones ,perforations are done at two places one below the retainer & another above it and the retainer is set in between. While pumping cement below the retainer, fluid will flow through the channels behind the casing and out above the retainer. This will allow the cement to fill any channels where water may be invading. The Cement Retainer is then removed from the wellbore using downhole mills and motors.

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Cement Plugging

Cement plugging Cement plugging consists of placing a cement column in open or cased hole. Cement volume needed for a specific plugging operation depends on plug length and hole diameter. Fluid spacers should be used both ahead of and behind cement slurry to minimize mixing of cement and drilling fluid. Also, spotting a viscous pill spacer at the intended plug bottom can improve cement-plug stability Reasons for Setting Cement Plug • Well abandonement To seal off a dry hole or depleted well, cement plugs are placed at required depths • Curing lost circulation during drilling : If drilling-fluid circulation is lost during drilling, it can sometimes be restored by spotting a cement plug across the lostcirculation zone • Directional drilling and sidetracking (or whipstocking) : To sidetrack a hole around unrecoverable junk or for an undesirable direction or poor structural position, a cement plug is placed at a specific depth. This plug helps support the whipstock for directing the bit into the desired area • Zone isolation : In a well with two or more producing zones, it is sometimes beneficial to abandon a depleted or unprofitable producing zone by placing a cement plug above it •

Curing lost circulation

Well abandonement

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Whipstocking

Zone isolation

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MAJOR FIELDS OF ASSAM

Lakwa Field: It is the largest oil producing field in the eastern region. Lakwa field is in the shelf part of Assam-Arakan Basin and is located in Upper Assam. Field covers an area of 70 sq. Km. The field was discovered in 1964 and put on production in 1968. Lakwa field is a multilateral sandstone clastic reservoir . Field is having broadly two highs namely Lakwa & Lakhmani separated by a saddle at Tipam levels . The Lakhmani field is essentially a south-west extension of Lakwa field. Hydrocarbon is distributed in the multiple layers of Tipams and Barail sands. Tipams are subdivided into TS-1, TS-2, TS-3, TS-4, TS-5A, TS-5B, TS-5C and ts-6 from top to bottom in the same order. Out of these, TS-2 is the major reservoir contributing about 70% of oil from Lakwa Tipams.

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RECENT

FORMATION

DEPTH

BRAHMAPUTRA ALLUVIUM

PAY

REMARKS

MORA N

OCENE

PLEST

1000

TO

ENE

GROUP

DHEKIAJULI NAMSANG GAS BEARING INTERPRETED

NAZIRA SST

2000

TIPAM GROUP

MIOCENE TO PLIOCENE

GIRUJAN

TS-1 TS-2

LAKWA SAND STONE

TS-3 TS-4 B

3000

TS-5A TS-5B1

GELEKI SAND STONE

TS-5B2 TS-5C

INDICATIONS

TS-6 SAFRAI

BARAIL GROUP

RUDRASAGAR LBS-2 LBS-1

DEMULGAON

4000

BMS KOPILI

DISANGMUKH KOPILI JAINTIA GROUP

MIOCENE TO EOCENE

OLIGOCENE

LBS-6 LATE EOCENE TO

PLIOC

PLESTOCENE TO

AGE

ALLUVIUM

GENERALISED STRATIGRAPHY OF LAKWA FIELD

SYLHET

SYLHET

BASAL S.STONE

TURA

5000

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INDICATIONS

Rudrasagar field: This is one the main fields of Assam Asset which was discovered in 1960 and put on production in 1966. More than 175 wells have been drilled till now. Rudrasagar structure is broadly anticline and most of the wells of all the blocks are producing from various sand like Barail Main Sand (BMS), Barail Coal Shale sand(BCS), Tipam Sand(TS). Most of the wells are producing under edge water drive mechanism having no significant drop in reservoir pressure. The field is characterized by high water cut, less drop in reservoir pressure, strong productivity index and phenomena like sand incursion etc.

General Stratigraphy of Rudrasagar Field Depth (m)

Lithology

925

Alluvium

1375

Namsang

1920

Nazira sand stone

1970

Girujan clay

2392

Lakwa Tipams (TS-1, TS-2, TS-3)

2789

Lower Clay Marker +TS-4 Geleki Sandstone (TS-5 & TS-6)

2980

BCS

3200

BMS ( Pr=295 KSC, 80 Deg C, Oil Bearing)

Geleki Field: The field is situated towards the southern fringe of the upper Assam valley and is very close to Naga hills. The field was discovered in 1968. trial production began in August 1974. the oil bearing formations are Tipams , Barails and Kopilis. The main producing sands are TS-2, TS3A, TS-4B, TS-5A & BMS. The other sands contributing to production are TS-5A2, TS-5B, TS-6, Barail channel sands (BCS-5,4,3&2), BMS-III & Kopili Sand Units. Water injection has been envisaged in the development schemes of all the major sands of Geleki Field i.e. TS-2, TS-3A, TS-4B, TS-5A & BMS. Accordingly water injection is going on in these sands.

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General Stratigraphy of Geleky Field Depth (m)

Sand

Pressure Kg/cm2

Temp ( C)

Remarks

2450

TS-2

180-200

70-75

Oil

2500

TS-3A

181-200

70-75

Oil

2700

TS-4B

140-150

70-75

Oil

2750

TS-5A main

130-160

70-75

Oil

3250

TS-5A SW

250

75-78

Oil

3350

TS-6 SW

78-80

Oil

3700

BCS

90-92

4000

BMS

4300

Kopili Sand Stone

240-280

98-105

Oil

100-108

Demulgaon field This field is located between Lakwa & Rudrasagar fields which has more than 37 drilled wells. The field has four hydrocarbon bearing sands viz. BMS, BMS-sub, BCS & TS-IVA. BMS is the major producer of oil. In the year 2003-04, the field produced oil @133 tpd with 54% water cut through 10 wells.

Satellite Fields: Charali Field: The field is located 4 km SE of Rudrasagar field. It was discovered in 1974 m and put on production in 1979. More than 30 wells have been drilled. The field is currently producing from BMS, BCS-I, BCS-V, TS-V, TS-IV and TS-II sands. During the year 2003-04, the field produced oil@175 tpd with WC of 41% and GOR of 119 v/v.

Changmaigaon Field: Changmaigaon field is located about 9 km NE of Amguri field and about 10 km south of Rudrasagar field. A total of 15 wells have been drilled. The wells are producing through TS-II, IV & V sands. During the year 2003-04, the field produced oil @98 tpd with WC of 14% from five wells.

Nazira Field: The field is located 4 km SE of Rudrasagar field. As of now, two wells have been drilled. It was put on production in 2001. The major sand developed are TS-II, IIIC, IVA, IVB & VB. During the year 2003-04, the field produced oil @6 tpd with WC of 41%.

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Kuargaon Field: Kuargaon field is located towards NW of Lakhmani field . Till 1984 it was considered as a part of Lakhmani field. After interpretation of new seismic data, maps were reviewed and this part of Lakhmani field was renamed as Kuargaon. LBS are the main producing sands.

Sonari field: Sonari structure located about 3 Kms , SE of Lakwa field was discovered in 1986with the drilling of well Sonari -1. The well proved to be hydrocarbon bearing in Barails , Safari & Tipams. Total 3 exploratory wells Sonari31,2, and 3 have been drilled so far. Sonari#1 was tested in LBS-2 and put on production but ceased to flow due to sand cut and during subsequent clearing operations fish was left in the well. Fishing operations are required to put back the well on production.

Safari Field: Safari was a new strike of oil & gas during the year 2000. the structure is located in the eastern limb of Lakwa main structure dissected by NE-SW fault. Sands BMS, LBS, Safari and TS-6, TS-5A have been interpreted as hydrocarbon bearing.

Recent Discoveries: •

Panidihing: Well PDAD produced oil from Tura formation (depth 4200 m). Produced oil @ 50 m3/d (API=23-24 deg, Pour Point= 39 degC)

•

Laiplingaon: Produced oil and gas from LBS sands. Oil @ 180 m3/d (API 35.7 deg, Pour point 27 degC) and gas @ 70000 m3/d

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ANNEXURE-I VITAL TECHNICAL DATA FOR DRILL PIPES, CASINGS, TUBINGS, KELLY AND ANNULAR VOLUME Size, Type & Grade of Drill Pipes 2 7/8” IF, 10.4 ppf, GGrade 3 ½” IF, 13 ppf, G-Grade Size and Type of Kelly 3” Square Kelly 3-1/2” Hexagonal Kelly

DRILL PIPE DATA Tool Joint Data Type O.D I.D

Upset portion O.D 3-3/16

Drill Pipe I.D 2.151

NC31(IF)

3-7/8

2.764

NC38(IF) 5 2-7/16 KELLY DATA Max. Bore Across Across Flats Corners

Upper Box Connection (LH) 6-5/8” Reg 6-5/8” Reg

Lower Pin Connection 2-7/8” IF 2-7/8” IF

4-1/8

1-3/4 1-3/4

2

3 3-1/2

3-15/16 3-31/32

Drift I.D 1.875 2.313

Mechanical Properties Tensile Yield Torsional Yield 300,080 lbs

16,180 ft-lbs

380,190 lbs

25,970 ft-lbs

Weight ( lbs per foot ) for Kelly with Bore I.D 1-1/4 1-1/2 1-3/4 25.8

24.0 30.1

21.8 27.9

TUBING DATA Size, type of Tubing 2-3/8” EUE, 4.7 ppf 2-7/8” NUE, 6.4 ppf 2-7/8” NUE, 8.6 ppf 2-7/8” EUE, 6.5 ppf 2-7/8” EUE, 8.7 ppf 3-1/2” NUE, 9.2 ppf 3-1/2” EUE, 9.3 ppf Size

ppf

5”

18.0 15.5 17.0 20.0 23.0 26.0 29.0 43.5 47.0

5-1/2” 7” 9-5/8” Tubing Size 2-3/8” 2-7/8” 3-1/2”

I.D

Drift Dia.

1.995 (50.6) 2.441 (62.0) 2.259 (57.4) 2.441 (62.0) 2.259 (57.4) 2.992 (76.0) 2.992 (76.0)

1.901 (48.29) 2.347 (59.61) 2.165 (54.99) 2.347 (59.61) 2.165 (54.99) 2.867 (72.82) 2.867 (72.82)

I.D 4.276 4.950 4.892 4.778 4.670 6.276 6.184 8.755 8.681

5-1/2”, 17 ppf 9.269 7.939

5”, 18 ppf 6.407 5.077

2-3/8” Tbg, 4.7 # 6.996 T (15,420 lbs)

(108.6) (125.7) (124.3) (121.4) (118.6) (159.4) (157.1) (222.4) (220.5)

2-3/8” D/P, 6.55 # 9.751 T (21,490 lbs)

Coupling O.D 3.063 (77.80) 3.500 (88.90) 3.500 (88.90) 3.668 (93.17) 3.668 (93.17) 4.25 (107.95) 4.50 (114.30)

Upset O.D

Capacity (Lts / Mt)

2.910 (73.91)

2.019 3.021 2.586

3.460 (87.88) 3.460 (87.88)

3.021 2.586 4.540

Grade N-80 P-105 N-80 P-105 N-80 P-105 N-80 P-105 N-80 P-105 N-80 P-105 N-80 P-105

4.180 4.540 (106.17) CASING DATA Hyd. Packer Capacity Drift I.D Bit Size Gauge Ring O.D (Lts / Mt) 4.151 (105.4) 4.125 (104.8) 9.266 4-1/8” 4.825 (122.6) 4.778 (121.4) 12.417 4-3/4” 4.767 (121.1) 4.626 (117.5) 12.128 4-3/4” 4.653 (118.2) 4.626 (117.5) 11.569 4-5/8” 4.545 (115.4) 4.500 (114.2) 11.052 4-1/2” 6.151 (156.2) 6.094 (154.8) 19.961 6-1/8” 6.059 (153.9) 5.969 (151.6) 19.380 6” 8.599 (218.4) 8.437 (214.3) 38.846 8-5/8” 8.525 (216.5) 8.218 (208.7) 38.192 8-1/2” ANNULAR VOLUME DATA ( Lts Per Mt ) CASING SIZE WITH PPF 5-1/2”, 20 ppf

5-1/2”, 23 ppf

8.711 7.380

8.194 6.863

7”, 23 ppf

7”, 29 ppf

Internal Yield Pr psi 11,200 14,700 10,570 13,870 15,000 19,690 10,570 13,870 15,000 19,690 10,160 13,340 10,160 13,340 Grade

N-80

9-5/8”, 43.5 ppf 35.987 34.657 32.637

17.679 16.522 16.349 15.191 14.330 13.172 WEIGHT OF A STRING OF 1,000 M ( 3,281 Ft ) FOR 2-7/8” D/P, 10.4 3-1/2” Tbg, 9.3 2-7/8” Tbg, 6.5 # 2-7/8” Tbg, 8.7 # # # 9.676 T 12.951 T 15.48 T 13.844 T (21,326 lbs) (28,545 lbs) (34,122 lbs) (30,513 lbs)

' L = F X L X S.C where,

L = [ ' L X F.P.C ] / F where,

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Joint Yield Strength lbs 104,340 136,940 105,570 138,560 159,310 209,100 144,960 190,260 198,710 260,810 159,090 208,800 202,220 271,970 Collapse Resistance psi 10,490 4,990 6,280 8,830 11,160 5,410 7,020 3,810 4,760

9-5/8, 47 ppf 35.333 34.003 31.984 3-1/2” D/P, 13.3 # 19.799 T (43,637 lbs)

' L : Stretch, in inches Ft F : Pull Force, in 1,000 lbs L : Length of string, in 1,000 Ft S.C : Stretch Constant

L

: Min. length of free pipe, in

' L : Stretch, in inches F : Pull force, in 1,000 lbs F.P.C : Free Point Constant

STRETCH CONSTANT ( in inches Per 1000 lbs Per 1000 FT ) AND FREE POINT CONSTANT FOR 2-3/8” Tbg, 4.7 # S.C 0.30675

F.P.C 3260

2-3/8” D/P, 6.55 # S.C 0.21704

2-7/8” Tbg, 6.5 #

2-7/8” Tbg, 8.7 #

2-7/8” D/P, 10.4 #

3-1/2” Tbg, 9.3 #

F.P.C S.C F.P.C S.C F.P.C S.C F.P.C S.C 4607 0.22075 4530 0.16103 6210 0.13996 7145 0.15444 STRETCH ( IN INCHES ) TO A 1000 M STRING WHEN GIVEN PULL OF

F.P.C 6475

2-3/8” Tbg, 4.7 #

2-3/8” D/P, 6.55 #

2-7/8” Tbg, 6.5 #

2-7/8” Tbg, 8.7 #

2-7/8” D/P, 10.4 #

3-1/2” Tbg, 9.3 #

10 K lbs

10 T

10 K lbs

10 T

10 K lbs

10 T

10 K lbs

10 T

10 K lbs

10 T

10 K lbs

10 T

10.064

22.18

7.121

15.69

7.243

15.96

5.283

11.64

4.592

10.12

5.067

11.17

1 Barrel = 0.15897 M3 1 Lt = 0.3531 Ft3

1 Ft = 0.3048 M 1 Kg / cm2 = 14.22 Lbs / in2

1 Gallon = 3.781 Lts 1 cm2 = 0.155 in2

1 PPF = 1.488 Kg / Mt 1 ft2 = 0.0929 M2

3-1/2” D/P, 13.3 # S.C F.P.C 0.11047 9052 3-1/2” D/P, 13.3 # 10 10 K lbs T 3.624 7.99 1 kg = 2.204 lbs

Annexure-II Rig Equipment Daily Check List Activity to be carried out No. A. DERRICK ENGINE Fuel level in the Derrick engine tank Coolant level in radiator of derrick engine Lube oil level in crank case Check fan belt for tension, wear & tear etc. Observe for any abnormal sound and vibration B. ALLISON TRANSMISSION Lube oil level in Allison Transmission Check air breather C. RIGHT ANGLE GEAR BOX Check oil level in right angle gear box. Check nuts on coupling bolts for firmness by hand D. HYDRAULIC SYSTEM Hydraulic oil level in hydraulic oil tank Check condition of hoses and end fittings E. PNEUMATIC SYSTEM Check condition of pneumatic hoses Drain moisture form air tanks

F. DRAW WORKS Check condition of draw works cooling hoses & swivel Check oil level in chain lubrication sumps Check lubrication of various links in & around the draw works Check water level in draw works cooling system Visually check the brake band for cracks, deformation etc. (especially near weld joints) G. ROTARY TABLE AND ITS DRIVE SYSTEM Check swivel and attached pneumatic line to clutch for

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Observations

leakage etc. Check oil level in gear box Check oil level in elevated rotary drive Check shafts at both end (i.e. input and out put from) of elevated rotary dive for proper lubrication Check oil level in the rotary table gear box Check the position of lock H. TRAVELING BLOCK Visually check the hook for crack and deformation etc. Check pulleys for freeness of rotation i.e. each pulley should freely rotate at no load .

I. MUD PUMP UNIT (PUMP & ENGINE) Check oil level in power end, Plunger lubrication pump, Chain lubrication sump, Fuller transmission and Engine sump Check drain plugs for oil seepage etc. Check belt tension of engine radiator and that of lubrication pump, adjust if necessary. Check lube oil hoses for its condition, oil seepage etc. Visually inspect plunger couplings After half an hour of running feel the temperature at bearings (From outer surface) and observe for any abnormal sound /vibration etc. J. BOP ACCUMULATOR UNIT Check pressure of the accumulator (2500 PSI) Check oil level in power end of pump, engine sump. Check oil leakage from plunger K. GENERATOR SET Check crank case oil level Check blower belt tension Check for any fuel/ lube oil leakage. Visually check engine alternator coupling Check alternator for vibration and abnormal sound.

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