Study of Coil Tubing Operations for Hydraulic Fracturing

Hydarulic Fracturing Depatrament Essar Oil Limited, Duragapur

BySteffones .K

B. Tech in Applied Petroleum Engineering

University of Petroleum and Energy Studies

Dehradun

20th December 2014 to 10th January 2015

Under the Guidance ofMr. Anjani Kumar

Manager H.F Department Essar Oil Ltd.

Essar Oil LimitedDurgapur, West Bengal

CERTIFICATE

This is to certify that the student Steffones.K of University of Petroleum and Energy Studies,

Dehradun has successfully completed the project work on “Study of Coil Tubing Operations for

Hydraulic Fracturing” in the Hydraulic fracturing department at the Essar Oil limited, Durgapur

from 20th December, 2014 to 10th January, 2015. This project work is the requirement towards

awarding the Degree of Bachelor of Technology in Applied Petroleum Engineering, from University

of Petroleum and Energy Studies, Dehradun.

Mr. Anjani KumarProject Supervisor

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ACKNOWLEDGEMENT

I express my deep sense of gratitude to Mr. Manoj Kumar,(DGM-HR|E&P Division| Essar Oil) for giving me the opportunity to work at Essar Oil and providing all the necessary facilities towards the completion of this project. I am thankful to Anjani Kumar, (Manager| HF| Essar Oil Ltd.) who mentored me throughout this project. It was with his invaluable guidance that this work could be completed in time.I express my sincere thanks Ms Priya Sihag (Assistant Engineer |HF| Essar Oil Ltd.) and Mr. Zulquarnain (Assistant Engineer |HF| Essar Oil Ltd.) for providing valuable insights on operations on-site. I would also like to thank to Mr. Manish Tiwari (Dy. Manager |HF| Essar Oil Ltd.) , Mr. Anshit Sharma(Assistant Engineer |HF| Essar Oil Ltd.) Mr. Ramniwash(Assistant Engineer |HF| Essar Oil Ltd.) and Ms.Suneha Sharma(Dy. Manager |HF| Essar Oil Ltd.) for their constant support and guidance in every part of this study. I would like to thank Dr. D.K. Gupta, Head – Department of Petroleum and Earth Sciences, UPES for giving me this great opportunity to pursue a winter internship at Essar Oil Ltd.

Steffones .KB.Tech, Applied Petroleum EngineeringUPES, Dehradun

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Table of Contents

Sl. No. Subject

Page No.

1 Introduction to Coil Tubing Unit 5

1.1 Coil tubing Reel 6

1.2 Coil tubing control Cab 6

1.3 Injector Head 8

1.4 Well control equipment 9

1.5 Coil Tubing String Design 10

1.6 Coil Tubing BHA 11

1.7 Advantages of Coil Tubing 14

1.8 Completion Application 14

1.9 Field Application 15

2 Operations of Coil Tubing 15

3Procedural Analysis of Fracturing Operations using Coil tubing. 16

4 Brief of Hydraulic Fracturing 18

4.1 Hydraulic Fracturing 18

4.2 Aim of Hydraulic Fracturing 18

4.3 Hydraulic Fracturing Fluid 19

4.3 Process of Hydraulic Fracturing 19

5 Conclusion 20

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List of Figures

Sl. No. Subject

Page No.

1 Coil Tubing Front View 5

2 Coil Tubing Reel Unit 6

3 Control Cabin 7

4 Injector Head 7

5 Injector Head Schematic Diagram 8

6 Stripper 8

7 Quad BOP 9

8 Coil Tubing Design Parameters 9

9 Coil Tubing BHA 11

10 Coil Tubing BHA 11

11 Roll Connector 11

12 Fullbore nozzle 11

13 BHA Schematic Diagram 12

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1. INTRODUCTION TO COIL TUBING UNITCoiled Tubing (CT) has been defined as any continuously-milled tubular product manufactured in lengths that require spooling onto a take-up reel, during the primary milling or manufacturing process. The tube is nominally straightened prior to being inserted into the wellbore and is recoiled for spooling back onto the reel. Tubing diameter normally ranges from 0.75 in. to 4 in., and single reel tubing lengths in excess of 30,000 ft. have been commercially manufactured. Common CT steels have yield strengths ranging from 55,000 PSI to 120,000 PSI.

The coiled tubing unit is comprised of the complete set of equipment necessary to perform standard continuous-length tubing operations in the field. The unit consists of four basic elements:

Reel - for storage and transport of the CT Injector Head - to provide the surface drive force to run and retrieve the CT Control Cabin - from which the equipment operator monitors and controls the

CT Power Pack - to generate hydraulic and pneumatic power required to operate the

CT unit.

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Guide Arch

Tubing ReelPower Pack

Coil Tubing

Injector Head

Fig.1 COIL TUBING UNIT FRONT VIEW

Coil Tubing Reel-Coiled tubing is stored on a drum that is supported on a shaft and mounted on a skid frame. A bi-directional hydraulic motor directly driving the reel via roller chain and sprockets or by a gear drive system rotates the reel. The drive system has dual function: when running in hole (RIH), the motor acts as a constant-torque brake, enabling back tension to be held on the pipe and while pulling out of hole (POOH), more tension is applied to enable efficient spooling of the pipe onto the drum. The reel will have a brake mechanism to prevent accidental rotational movement when it is required. The reel drive system should produce enough torque to provide the required tension to the coiled tubing to bend the coiled tubing over the gooseneck and onto the reel. This tension provided by the reel on the coiled tubing unit between the reel and injector is commonly referred to as ‘reel back-tension’

Coiled Tubing Control Cab-The control cabin fully allows the operation and control of all functions of the coiled tubing unit from within the cabin. The typical unit is hydraulically elevated for better operator vision. The control panel incorporates:

Injector controls Reel controls BOP controls Auxiliary shear seal BOP controls Hydraulic circuit pressure gauges Weight indicator Coiled tubing internal pressure Wellhead pressure - WHP Data Acquisition unit Remote power pack control

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Fig 2 Coil Tubing Reel unit

The unit is fully insulated with a heater for cold climates and space for air conditioning unit in warm climates. All necessary hoses to control and operate the Injector Head, BOP’s, PowerPack and Tubing Reels are incorporated on hydraulically powered reels on the front of the skid.

Injector Head:

The basic functions are:

• Tubing is gripped between contoured blocks carried by two sets of chain guided by rollers over the area of contact between blocks and tubing .

• Each set of chains is powered by a hydraulic motor, which drives through a safety clutch and gearbox.

• The clutch prevents tubing falling into hole in event of prime mover failure and also serves as a brake.

• Continuous straightening device and depth measuring odometer are mounted on injector’s sub frame.

• On top of main frame of Injector head a curved roller guide is present known as Gooseneck for supporting tubing during its transition from motion along the vertical axis of wellhead to the horizontal coiling axis of storage reel.

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Fig 4 Injector Head

Injector Head

Fig 3 Control Cabin

Goose Neck

Well Control EquipmentProper well control equipment is another key component of CT operations, given that a majority of these operations are performed in the presence of surface wellhead pressure. Typical CT well control equipment consists of a BOP topped with a stripper (high pressure CT units have two strippers and additional BOP components). All components must be rated for the maximum wellhead pressure and temperature possible for the planned field operation.

The stripper (sometimes referred to as a pack off or stuffing box) provides the primary operational seal between pressurized wellbore fluids and the surface environment. It is physically located between the BOP and the injector head. The stripper provides a dynamic seal around the CT during tripping and a static seal around the CT when there is no movement. The latest style of stripper devices is designed with a side door,that permits easy access and replacement of the sealing elements, with the CT in place.

The BOP is situated beneath the stripper, and can also be used to contain wellbore pressure. A CT BOP is designed specifically for CT operations. It consists of several pairs of rams, with each ram designed to perform a specific function. The number and type of ram pairs in a BOP are determined by the BOP configuration: single, double, or quad. A quad system is commonly used in most operations.The four BOP rams, from top to bottom and their associated functions are:

Blind ram - seals the wellbore when the CT is out of the BOP Shear ram - used to cut the CT Slip ram - supports the CT weight hanging below it (some are bi-directional and

prevent the CT from moving upward) Pipe ram - seals around the hanging CT

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Fig 5 Injector Head Schematic

Fig 5 StripperCut View

Fig 6 StripperFront View

Standard CT BOPs also contain two equalizing ports, one on each side of the sealing rams. It also has a side outlet between the slip and shear rams. This outlet can be used as a safety kill line. BOPs are available in a range of sizes, and normally follow the API flange sizes.

Ct String Design-The length of CT on a reel varies depending on diameter. For comparison, a small reel may only be able to hold 4,000 ft. of 2 7/8 in. tubing, but may have a 15,000 ft. capacity if 1 1/2 in. tubing is spooled on it. A properly sized CT string must have the following attributes for the planned operation:

Enough mechanical strength to safely withstand the combination of forces imposed by the job..

Adequate stiffness to RIH to the required depth and/or push with the required force.

Light weight to reduce logistics problems and total cost. Maximum possible working life.

The simplest method of designing a CT string considers only the wall thickness necessary at a given location for the required mechanical strength and the total weight of the string. This method assumes the open-ended CT string is hanging vertically in a fluid with the buoyed weight of the tubing being the only force acting on the string. Starting at the bottom of the string and working up, the designer selects the wall thickness at the top of each section that provides sufficient tensile force at that location.

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Fig 8 Coil Tubing Design parameters

Fig 7 Quad BOP

Coil Tubing BHA: 1. Connector- This is used to connect coil tube with the bottom hole assembly. Also called grapple connector. They have diameter of about 1.75 in.

2. The Motor Head Assembly (MHA): This is the essential core piece of equipment for all reliable coiled tubing operations. It incorporates five standard tools in one purpose built unit; the coil connector, dual flapper check valves, the safety disconnect, and a dual circulating sub. The dual circulating sub combines a conventional drop ball circulating sub and a pressure activated rupture disc. The standard MHA is rated to a working pressure of 10,000 psi. Two types of MHA are generally in use in perforation operation: High flow MHA: This is used for cleaning job and its diameter of 1 inches and we can pump up to 6 bpm thorough this MHA. Low flow MHA: This is used for perforation and its diameter of 0.6 in. we can pump up to maximum 3 bpm thorough this MHA.

3. Centralizer: Coiled Tubing will exhibit a residual curvature that tries to force the end of the tools against the side of the well bore and causing possible hang ups on nipples etc. The centralizer uses four bow springs to effect centralization.

4. Straight bar: The Straight Bar is specially designed coiled tubing operations. It is approximately 2 feet long full flow through metal bar with a box - pin connection. The Straight Bar is often used to extend very short tool strings, such as a simple cleanout or lifting tool string. By extending a short tool string the possibility of standing up in restrictions will reduce.

5. Casing collar locator (CCL): is equipment used to locate the casing collar in bore well. It has 3 keys in it which help in finding collar.

6. Nozzle: These are the holes from which high velocity water, gel or slurry is pumped out in bore hole. The diameter of nozzle is 0.1875 in. The high-velocity slurry cuts through the casing and cement and into the formation. The resulting perforations serve as excellent initiation points for fracturing. Assemblies having 3 nozzles are in use for perforation by most company. The reverse circulation nozzles assemblies have 3 nozzles of diameter 0.5 in. for making cuts and 5 pair of reverse nozzle housing.

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MHA

CentralizerJetting Nozzle

MCCL Key

Fig 9 Coil Tubing BHA

Fig 10 Coil Tubing BHA

Fig 11 Roller ConnectorFig 12 Fullbore nozzle

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BHA SCHEMATIC

Fig 13 Coil Tubing BHA

Advantages of Coil Tubing-While the initial development of coiled tubing was spurred by the desire to work on live wellbores, speed and economy have emerged as key advantages for application of CT. In addition, the relatively small footprint and short rig-up time make CT even more attractive for drilling and workover applications.Some of the key benefits associated with the use of CT technology are as follows:

Safe and efficient live well intervention Rapid mobilization and rig-up Ability to circulate while RIH/POOH Reduced trip time, resulting in less production downtime Reduced crew/personnel requirements Cost may be significantly reduced

Coiled tubing can also be fitted with internal electrical conductors or hydraulic conduits, which enables downhole communication and power functions to be established between the BHA and surface. In addition, modern CT strings provide sufficient rigidity and strength to be pushed/pulled through highly deviated or horizontal wellbores. This enables successful execution of downhole operations that would be impossible to perform with conventional wireline approaches, or would be cost prohibitive if performed by jointed-pipe.

Completion ApplicationsCT is routinely used as cost-effective solution for numerous workover applications. A key advantage of CT in this application is the ability to continuously circulate through the CT while utilizing CT pressure control equipment to treat a live well. This avoids potential formation damage associated with well killing operations. The ability to circulate with CT also enables the use of flow-activated or hydraulic tools. Other key features of CT for workover applications include the inherent stiffness of the CT string. This rigidity allows access to highly deviated/horizontal wellbores, and the ability to apply significant tensile or compression forces downhole. In addition, CT permits much faster trip times as compared to jointed pipe operations.

Pumping Applications Removing sand or fill from a wellbore Fracturing/acidizing a formation Unloading a well with nitrogen Gravel packing Cutting tubulars with fluid Pumping slurry plugs Zone isolation (to control flow profiles Scale removal (hydraulic) Removal of wax, hydrocarbon, or hydrate plugs

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Fig 13 Coil Tubing BHA

Mechanical Applications Setting a plug or packer Fishing Perforating Logging Scale removal (mechanical) Cutting tubulars (mechanical) Sliding sleeve operation Running a completion Straddles for zonal isolation Drilling

Coil tubing Field ApplicationsThe use of CT has continued to grow beyond the typical well cleanout and acid stimulation application. This growth can be attributed to a multitude of factors, including advances in CT technology and materials as well as the increased emphasis on wellbores containing a horizontal and/or highly-deviated section.Various uses are-:

Well Unloading Cleanouts Acidizing/Stimulation Velocity Strings Fishing Tool Conveyance Well Logging (real-time & memory) Setting/Retrieving Plugs

2. OPERATIONS OF COIL TUBINGFracturing / Acidizing A Formation-This CT application has experienced significant growth in recent years, and provides several advantages versus conventional formation treatment techniques. In particular, CT provides the ability to quickly move in and out of the hole (or be quickly repositioned) when fracturing multiple zones in a single well. CT also provides the ability to facture or accurately spot the treatment fluid to ensure complete coverage of the zone of interest. When used in conjunction with an appropriate diversion technique, more uniform treating of long target zones can be achieved. This is particularly important in horizontal wellbores. At the end of the formation treating operation, CT can be used to remove any sand plugs used in the treating process, and to lift the well to be placed on production.One of the earlier concerns with CT fracturing was the erosion effects that occur when proppant is pumped during the fracturing operation and the resulting impact on CT string life. An ultrasonic thickness (UT) gauge is now used on location to measure CT thickness during the job. Data from these UT measurements can be used to adjust the CT fatigue models, and to accurately monitor remaining CT string life.

Removing Sand or Fill from a Wellbore-The removal of sand or fill from a wellbore is the most common CT operation performed in the field. The process has several names, including sand washing, sand jetting, sand cleanout, and fill removal. The objective of this process is to remove an accumulation of solid particles in the wellbore. These materials will act to impede fluid flow and reduce well productivity. In many cases CT is the only viable means of removing fill from a wellbore. Fill includes materials such as formation sand or fines, proppant flowback or fracture operation screenout, and gravel-pack failures.

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3. PROCEDURAL ANALYSIS OF FRACTURING OPERATIONS USING COIL TUBING

Running In-o The coil tubing unit is spotted near the wellbore and the injector head is

connected to the wellhead.o Then Brakes are released, lever arm is lifted coiled tubing is guided

through guide arch into the injector head.o All the master valves are opened and coil tubing is run in to the hole

through Opti-frac Head into the wellbore. Depth Correlation-

o The mechanical casing collar locator (MCCL) is used for depth correlation for CT assisted perforating and fracturing operations and is absolutely critical for depth correlation when zones are thin.

o It indicates the casing collars and, in turn, helps correlate the depth shown on the CT unit depth meter to the wireline depth. A clear weight spike indicates a collar when the CT is POOH at a slow speed. The speed at which the CT is POOH is an essential factor that determines the prominence of the weight spikes.

o Distance between nozzle and key is ‘t’ m and Coil tubing will show the depth of nozzle not key. If we have collar depth of X then the depth of nozzle should be X+t and if CT is showing Y depth of tubing then,

Z= Y- (X +t)Then Z will be correction factor and correct depth in CT by new depth

Y + Z

Tagging of Cement Tag/ Sand Tag- Tago As we run into the wellbore the weight of the coil tubing will increase but

as we encounter sand or cement we find that the weight of tubing decreases, this is called as tag. Tag is the indicator of encountering sand or cement in the well.

o In a job first we tag at the top of the cement point. By this we will know the sump for the Fracturing job.

Perforating the coal seamo Actual depth of near collar is seen in CCL graph where we have to cut

and start pulling out the coil to locate that collar. Calculate offset and correct the depth in CT and pull the coil up to the depth where we have to cut.

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o Slurry (gel + proppant) is prepared at the time of locating the collar and after that pump the slurry through coil tubing at an optimum rate & pressure and displace it with gel.

Clean out processo According to the amount of sump available we can either dump the

perforation or cleanout the sand by doing bottoms-up.o Bottoms up to be performed from an appropriate depth (usually 10-15 m

below the perforation) to remove any unnecessary sand plug.o Gel is pumped the through coil and pumped until we get clean (sand free)

returns. After getting clean return we will pull the coil up and make the next perforation.

Injectivity Test o After perforation job, it is important to check whether the perforation is

able to intake the acid or not. To check the injectivity simply gel is pumped at lower rate either from CT of annulus.

o Pressure was applied across the annulus and was maintained to about 500 psi over the initial shut-in pressure (ISIP) of the previous treatment and circulation pressure response is observed.

o If perforation has not been choked with sand settled than pressure trend would be either constant or breakdown would be observed. Once the injectivity is confirmed, acid job is carried out.

Acid Displacemento In this acid is pumped down the CT and jetted onto the perforations.

Instant reaction between the acid and carbonates present in the cement in the near-wellbore region occurred.

o Acid was jetted onto the perforations for a period of approximately 3 to 4 minutes.

o Once the acid was jetted, it was displaced into the annulus between the CT and the casing. Because of issues relating to health, safety, and environment (HSE) concerns, it was displaced to the annulus, and immediately after the fracture was initiated, all the reaction products were flowed into the formation, along with any unspent acid.

Acid Squeezing-o There were multiple instances where there were exceptional cement

losses in the formation. It was observed that it was still hard to break down the formation, even with the acid so the annulus was closed and the acid was squeezed into the perforation.

o In this case, any acid in the annulus would enter the perforations, providing an extended duration of time to react with the cement and also enter the cleat’s natural fractures, which would have been the path of least resistance for any cement losses that would have occurred.

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Stand by During the Fracturing Job- o After getting pressure breakdown in acid job we will pull the coil up to a

safe depth (around 100 m above the perforation) and proceed for fracturing job and pump gel from coil at minimum rate to maintain pressure in the coil during fracturing job.

Complete Cleanout of wellbore after completion of all fracturing Jobs-o The typical procedure involved in this application is to circulate a fluid

through the CT while slowly penetrating the fill with an appropriate full-bore nozzle attached to the end of the CT string. This action causes the fill material to become entrained in the circulating fluid flow, and is subsequently transported out of the wellbore through the CT/production tubing annulus. This operation is called wiper trip.

o An alternative fill removal approach is to pump down the CT/production tubing annulus and allow the returns to be transported to surface within the CT string. This procedure, called reverse circulation, can be very useful for removing large quantities of particulate, such as fracturing sand, from the wellbore. It may also be applied when a particular wellbore configuration precludes annular velocities sufficient to lift the fill material.

4. BRIEF OF HYDRAULIC FRACTURING IN CBM

Hydraulic Fracturing Most coalbed require some method of stimulation to adequately produce water from seam and allow for production of gas. Although production may occur without stimulation, experiences have proven that economics are greatly enhanced following a fracturing treatment. Hydraulic fracturing typically involves injecting fluid made up of water, sand and additives under high pressure into the cased well. The pressure caused by the injection typically creates a fracture in the coal seam where the well is perforated. For a large CSG treatment, the fracture might typically extend to a distance of 200 to 300 meters from the well. The fractures grow slowly. The sand in the hydraulic fracturing fluid acts to keep the fracture open after injection stops, and forms a conductive channel in the coal through which the water and gas can travel back to the well.

Aim of Hydraulic Fracturing Enhance the permeability of the cleat system in the coal, which in turn enhances

the dewatering process while lowering the reservoir pressure to the desorption pressure, consequently allowing gas production to occur.

Affect a large portion of the reservoir, increasing both productivity and reserves.

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Improve the economics of the well by increasing water withdrawal, consequently leading to a shorter period of dehydrating, decreasing the time required for gas flow to maximize and increase the gas flow rate.

Hydraulic Fracturing FluidWater and sand make up around 97 to 99 per cent of the hydraulic fracturing fluid. Added chemicals make up about 1 to 3 per cent of the hydraulic fracturing fluid. Some commonly used chemical additives, and their uses in hydraulic fracturing fluids, include:

Guar gum (a food thickening agent) is used to create a gel that transports sand through the fracture.

Bactericides, such as sodium hypochlorite (pool chlorine) and sodium hydroxide (used to make soap), are used to prevent bacterial growth that contaminates gas and restricts gas flow.

‘Breakers’, such as ammonium persulfate (used in hair bleach), that dissolve hydraulic fracturing gels so that they can transmit water and gas.

Surfactants, such as ethanol and the cleaning agent orange oil, are used to increase fluid recovery from the fracture.

Acids and alkalis, such as acetic acid (vinegar) and sodium carbonate (washing soda) to control the acid balance of the hydraulic fracturing fluid.

Process of Hydraulic Fracturing Pad Stage

In the pad stage, fracturing fluid only is injected into the well to break down the formation and create a pad. Pad is the initial part of the fracture fluid that creates the fracture width and controls the initial fluid loss but contains no proppant. The pad is created because the fracturing fluid injection rate is higher than the flow rate at which the fluid can escape into the formation. In other words, when injection pressure exceeds the formation break down pressure, fractures in formation gets created. It is very similar to the acid fracturing.

Slug Stage Two stages of slug stage is added between the Pad stage. It is usually added to block the multiple mini fractures that are created during the evolution of fracture geometry therefore slug stage helps in decreasing the tortuosity of the path so that in the later job designed amount of sand can be placed within optimum pressure ranges.

Slurry Stage

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After Pad and Slug Stage there starts slurry stage, in this sand is added to the formation in ‘Ramp’ & ‘Hold’ pattern so as to avoid sudden hit of sand into the formation which may otherwise lead to early screen out. Proppant is used to sustain the effect of the minimum horizontal stress from closing the fracture. The effective packing is the reflection of the effective permeability between the reservoir and the wellbore through fractures; also good packing lessens the flow back of the sand during production stages.

Flush Stage In this step lower viscosity gel is used to clean the wellbore and displace all the sand which is in the wellbore, and displace it inside fractures.

5. CONCLUSION – FRACTURING THROUGH COIL TUBING ADVANTAGES & DISADVANTAGES

Advantages1. The coiled tubing can be used to isolate the completion from the fracturing process.By setting a squeeze packer at the end of the tubing, the hole tubing string is protected from the pressure and temperature changes normally experienced by the completion.

2. Coiled tubing fracturing is particularly effective when working on monobore completions, or on wells that have not yet been completed. By using an opposing cup tool, the coiled tubing can be used to easily isolate one zone from another.

3. If required, the coiled tubing can be used to gas lift the well on to production after the treatment(s).

4. Coiled tubing can often be used as an alternative to a workover. This can mean significant cost saving, especially offshore.Disadvantages1. The extra cost of the coiled tubing unit, over and above the cost of the frac spread.However, often this extra cost can produce savings in other areas (rig time, frac crew time etc). The operating company must also be prepared to pay for some or all of the cost of the coiled tubing string.

2. The extra space needed, due to the extra equipment required as compared to the frac spread by it. Of course, if the CT unit is being used as an alternative to a workover rig, this may not be as significant.

3. Rate limitations. In general, for a given fluid system, higher rates can be achieved through completions than through coiled tubing. However, it should be remembered

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that it is usually possible to take the static coiled tubing to higher pressures than the completion/wellhead assembly.

4. Although it is possible to frac through coiled tubing with standard fluid systems, as the depth increases and/or the coiled tubing diameter decreases, it may be necessary to use more exotic and expensive fluid systems.References Used-

1. An Introduction To Coil Tubing, ICoTA, 2005.2. Coil Tubing Equipment Corresponding Course, BJ services, 2005.3. Hydraulic Fracturing Operations—Well Construction and Integrity Guidelines4. Modern Fracturing , Enhanced Natural Gas Production, Economides, 2007.

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