reportfinalsem.docx

Jyothi Engineering

Dept. Mechanical

College

Engineering

CHAPTER 1 INTRODUCTION

The Blowout preventer or BOP is invented by HARRY S.CAMARON in 1922. BOP is a large specified valve usually installed in stacks used to seal control and monitor oil and gas well. It was invented to prevent blowout of oil wells. A typical subsea deep water blowout preventer system includes components such as electrical and hydraulic line, control pods, hydraulic accumulator, ram type BOP and annular type BOP. Well kick is an influx of fluid from the formation into the wellbore. All rock formations penetrated by drill bit have void spaces to some degree. This space contains either oil, gas, or water. These fluids are under high pressure depending on factors such as how old the formation is, how it was formed, and how deeply it is buried. Blowout is an uncontrollable flow of crude oil or natural gas from the oil well. It happens when the hydrostatic pressure of cutting mud decrease below the pressure of formation fluid. Blowout may be caused due to insufficient mud weight, lost circulation, and failure to keep the hole filled while tripping. Blowout leads to the explosion of drilling rig, and effect the environment of nature. Just like blowout happen in Gulf of Mexico on April 20, 2010.miles of sea area is spreader with oil, tons of fuel is wasted, badly effect the environment and ecosystem of sea. There are mainly two types of BOP over there RAM type and ANNULAR type. The function of these two are same but operation and pressure rating is different. RAM type BOP is capable to withstand pressure over 20000 psi but annular only have a pressure rating in between 500 to 1500 psi. Thus a blow out preventer are critical to the safety of crew in rig, balance of the ecosystem and to monitor and maintenance of well integrity.

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Seminar Report 2017

Jyothi Engineering

Dept. Mechanical

College

Engineering

CHAPTER 2 BACKGROUND

2.1 Oil and Gas Exploration Although the fundamentals of exploration process remains the same as that of conventional processes, modern technology and engineering have greatly improved exploration performance. There are mainly three steps to explore oil or gas reservoir; desk study, geological survey, and drilling. Once the drilling location has been decided according to the data that is gathered in the desk study and geological survey, the main stage, drilling operation can begin.

Fig 2.1. Formation of well kick and blowout [2]. 2.2 Drilling The drilling operation is a very sophisticated operation and can begin only after the drilling program has been decided, the drilling site has been prepared and all drilling equipment that comprises the drilling rig has been put in place at drilling site. Basically a land drill rig consists of multiple diesel engines that supply power, hoisting equipment that raises and lowers the drill string, and rotary equipment that turns the drill string and drill bit, and drilling mud handling equipment, which is used to prepare mud and pump it down the hole.

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Jyothi Engineering

Dept. Mechanical

College

Engineering

Fig 2.2. Mud circulation.

Fig 2.3. Drill rig setup [3]. As can be seen in Fig 2.2, mud pumps force drilling fluid (mud) down the annular space through the inside of the drill string and out of the bit upward around the drill string (annulus). Since pump pressure, hydrostatic pressure of mud, and friction pressure loss in the annulus, balance the formation fluid pressure, mud circulation is a very important process in terms of preventing blowout.

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Jyothi Engineering

Dept. Mechanical

College

Engineering

Offshore drilling operation can be conducted using a variety of self-contained mobile offshore drilling rigs. The choice of drilling rig depends on the depth of water, sea bed conditions and prevailing meteorological conditions, particularly wind speed, wave height and current speed Mainly there are three types of offshore drilling rigs; jack-up, semi-submersible and drillship. 2.3 Jack Up Jack-up oil drilling rigs are used for shallow water drilling typically less than 300 feet. These units are towed to the drilling location and then jacked up into position as their name suggest. A typical jack-up has three or four long legs that run through the air when jack up is not in drilling mode. These legs, each of which can support the weight of the entire unit, are jacked down to sea floor when the jack-up is over the proposed well location. When the weight of the entire unit is fully supported, the legs are jacked down further until the unit rises out of the water about 10 – 4 feet in the air. After checking all safety issues, the unit will switch to drilling mode and begin drilling the well.

Fig 2.4. Jack up.

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Jyothi Engineering

Dept. Mechanical

College

Engineering

2.4 Semi-Submersible There are two main differences between semi-submersible and jack-up oil rigs; water depth and stabilizing issue. Semi-submersibles are typically limited to drilling in water depths less than 8,000 feet while jack-up is around 300 feet. Jack-up drilling rigs maintain its position with help of their legs, while semi-submersible rigs flood their huge ballast tanks with seawater to submerge them below the surface of the water and use anchors or dynamic positioning (DP) system to maintain their position.

Fig 2.5. Semi submersible. 2.5 Drillship These drilling rigs are basically built on traditional ship bodies to meet the growing demand for highly capable ultra-deep-water drilling rigs. Although they are not quite as stable as semi-submersibles, drill ships have larger storage capacities that enable to work for extended periods without the need for constant resupplying. Also

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Jyothi Engineering

Dept. Mechanical

College

Engineering

drill ships have advantages in terms of speed and they can maintain their operation in a very harsh weather condition where most semi-submersibles must be evacuated.

Fig 2.6. Drillship 2.6 Surface casing and drilling sequence

Fig 2.7. Surface casing with cement The drill bit is connected to drill string which runs all the way back to the drilling rig. The drill bit is rotated with drill string in the wellbore to cuts through the earth as high pressure mud is pumped down the center of the drill string and out through nozzles in the drill bit. After several hundred meters of drilling (the depth depends the casing plan), large diameter metal tubing called “surface casing” is placed

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Jyothi Engineering

Dept. Mechanical

College

Engineering

into the ground. Surface casing forms the backbone of the well, provides structural support to maintain the integrity of the borehole, and isolated underground formations from the well. Once surface casing is installed its place, drilling operation can continue to drill deeper. During the drilling operation the drill bit cuts away the ground formations, while the drilling fluid carries the small rock pieces out of the hole to prevent them from building up on the bottom of the well. Besides carrying rock pieces out of the hole, mud has several other important functions: • Providing hydrostatic pressure to prevent formation fluids or gas from entering into the wellbore (well kick). Cleaning the drill bit and keeping it cool during the drilling operation. • Keeping drill pipe lubricated to prevent it from getting stuck in the ground. The all sections of the well are drilled the same way as the surface casing was drilled in the earlier step. Each time, after drilling deep enough, a new casing with a diameter smaller than the previous casing is installed the end of the previous casing and cemented. This process is repeated until the drill bit reaches the oil and/or gas reservoir.

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Jyothi Engineering

Dept. Mechanical

College

Engineering

CHAPTER 3 LITERATURE REVIEW

To study the damage and failure of the shear ram of the blowout preventer in the shearing process Chuanjun Han et. al (2015) studied stress distribution of drill pipes at different stages and analyzes the Von-Mises stresses of the upper and lower shear ram. Finite element model of the shear ram is found out. In his experiment, shear rams are installed on the U-shape slot. There is one hydraulic push rod after each shear ram. When shutting occurs, hydraulic system drives the push rods, and then the push rods drive the two rams to close. When the rams are closed, the drill pipe will be gradually cut off. Constraints are applied on the Y direction of the upper face of drill pipe. The two rams can only be moved in the Z direction. Gravity load was applied on the lower surface of the drill pipe. The velocity of shear rams is 20 mm/s. He suggested that with the increase in the length of the pipe, the peak stresses of the upper and lower ram can be reduced. The increase in diameter also accounts to decrease in the Von-Mises stresses. Further observations are made on blade angle, Vshape angle, and Edge chamfer angle. With the increase in the blade angle, the stresses of the ram decreases first and then decreases. The blade angle is varied between 0°-6° and the angle between 2°-4° is found out to be optimum. The peak stresses of the rams are studied for V-shape angle varying in the range of 155° ~ 180°. With the increase of the V-shape angle, the peak stresses of rams decrease first and then increase. When the V-shape angle is 163°, the stresses of the two rams are the smallest. The peak stresses of the rams for an edge chamfer angle varying in the range of 0° ~ 90° is also studied..With the increase in the edge chamfer angle, the peak stresses of the rams decrease first and then increase, but the changing laws of upper ram and lower ram are different. When the edge chamfer angle is 45°, 8

Seminar Report 2017

Jyothi Engineering

Dept. Mechanical

College

Engineering

the peak stress and high stress area of upper ram are the smallest, and the optimal edge chamfer angle of the upper ram is 45°.When the edge chamfer angle is 15°, the peak stress and high stress area of lower ram are the smallest, and the optimal edge chamfer angle of the lower ram is 15°. J. V. Langston in his work "Training program to improve well control operations" suggested that Blowouts can be prevented by first stopping the influx of fluids into the wellbore. He observed that the only way to stop the influx of fluids in the wellbore is to oppose the pore pressure with an equal or greater pressure. The most obvious way to stop an influx is to raise the mud weight to a hydrostatic pressure greater than the pore pressure. Sometimes this is either impractical or impossible, so operators must find another way of controlling kicks. If the annular space is closed between the drill string and the casing at the surface, then no fluid will be able to leave the well bore at that point thus preventing the blowout and control the flow of the rig.

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CHAPTER 4 BLOWOUT

All formations that are penetrated during drilling operations are permeable to some degree and under tremendous pressure. The borehole pressure, which consists of the hydrostatic pressure of the mud, pump pressure, and friction pressure loss in the annulus, balances the formation fluid pressure. If for any reason the borehole pressure falls below the formation fluid pressure, the formation fluids might enter the wellbore. Such an event is known as a first signal of blowout “well kick”. There are several reasons that might cause well kick: • Mud weight less than formation pore pressure • Lost circulation • Failure to fill up the hole while tripping. • Recirculation of gas or oil cut mud. • Encountering abnormally high formation pressure.

Fig 4.1. Lucas gusher

blowout accident

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4.1 Mud Weight Less Than Formation Pore Pressure In order to maximize penetration rates, drilling mud weight is chosen very near to and, in some cases, below the formation pore pressures if there is enough data about specific pore pressure and reservoir fluid composition in the drilling location. But in many areas the mud weight requirement is not known since there might not be enough data about formation pore pressure. In such cases, the drilling operation group decides the mud weight by examining all collected geological data for this specific drilling location. If the formation pore pressure exceeds the drilling operation group’s expectation, well kick may occur.

4.2 Lost Circulation Lost circulation means the loss of returned mud, which is pumped through the inside the drill string down and back to the surface through the annulus. From a pressure balance standpoint, it means that the ability of the ground formation to resist injection has fallen below the mud circulation pressure. Therefore mud penetrates the formation zone, which might be naturally fractured formations or high-permeability formations. If for any reason return is lost, the resulting loss of hydrostatic pressure in the wellbore might cause any formation fluid, which contains greater pressure, to flow into the wellbore, which means well kick will occur. . 4.3 Failure to Keep the Hole Fill While Tripping Tripping is a procedure of removing and/or replacing the drill string from the well. During the tripping procedure there might be a vacuum in the wellbore, which can cause an imbalance in pressure between wellbore and formation. Therefore, if rig crews don’t take proper precaution, formation fluid might enter the wellbore, which means well kick might exist.

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4.4 Mud Cut Mud cut is a drilling fluid that has gas (air or natural gas) bubbles in it. Mud cut has been considered a warning signal, but not necessarily a serious problem for well kick. But intense gas-cut mud causes essential reductions in bottom hole pressures because a gas cut mud has lower density than a mud not cut by gas. Thus, there would be reductions in total hydrostatic pressures when a productive oil or gas zone is present and this could cause serious well kick problem if a kick cannot be controlled properly, uncontrolled formation fluid would reach to the surface. Such a catastrophic event is known as blowout.

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CHAPTER 5 BLOWOUT PREVENTER

BOP is a large specified valve usually installed in stacks. It was invented to prevent blowout of oil wells. The terms blowout preventer, blowout preventer stack are commonly used interchangeably and in a general manner to describe an assembly of several stacked blowout preventer of varying type and function, as well as auxiliary component .a typical subsea deep water blowout preventer system includes components such as electrical and hydraulic line, control pods, hydraulic accumulator, ram type BOP and annular type BOP.

Fig 5.1. BOP combination in wellhead [1]. A well kick can be kept under control if the proper pressure control equipment is used, which is called a blowout preventer stack, is installed at the surface. The blowout preventer stacks are massive devices with steel reinforced rubber goods. When they are activated they are required to close/seal the borehole and secure the 13

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well. The contacting sealing pressure must be greater than formation fluid pressure. In some cases this pressures might be more than 20,000 psi. A blowout preventer stack generally utilizes several different types of blowout preventers; annular and ram types.

5.1 TYPES OF BOP 5.1.1. Annular Type BOP

Fig 5.2. Annular Blowout Preventer. An annular BOP is a device used in combination with hydraulic system that can seal off Upon command, high-pressure fluid is directed to the closing hydraulic ports. Different sizes of annulus whether drill pipe is in use in the wellbore or not positioned in the lower side of the piston. This causes the operating piston to move upward so the moving piston compresses the packer . Because of a cap at the top of annular blowout preventer, the packer can only move toward the center of the wellbore to pack off a drill pipe or seal off the wellbore. The annular blowout preventer was invented by Granville Sloan Knox in 1946; a U.S patent for it was awarded in 1952.often around the rig it is called the Hydril, after the name of one of the manufacturers of such devices.

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An annular type blowout preventer can close around the drill string, casing or a no-cylindrical objet, such as the Kelly, Drill pipe including the largest diameter tool joint can be stripped (move vertically while pressure is contained below) through an annular preventer by careful control of the hydraulic closing pressure. Annular blowout preventer are also effective at maintain a seal around the drill pipe even as it rotates during drilling. Regular typically require that an annular preventer be able to completely close a wellbore, but annular preventers are generally not as effective as ram prevents in maintain a seal on open hole. Annular BOP are typically located at the top of a BOP stack, with one or two annular preventer positioned above a series of several ram preventers. An annular BOP use the principle of wedge to shut in the well bore. It has a donut –like rubber seal, known as an elastomeric packing unit, reinforced with steel ribs. The packing unit is situated in BOP housing between the head and hydraulic piston. When the piston is actuated, its upward trust force the packing unit to constrict, like a sphincter, seal the annulus or open hole. Annular preventers have only two moving part, piston and packing unit, making them simple and easy to maintain relative to ram preventers. The original type of annular blowout preventer use wedge faced pisto.as the piston rises, vertical movement of the packing unit is restricted by the head and the sloped face of the piston squeezes the packing unit inward, toward the center of the well bore.

5.1.2 Ram Types Blowout Preventer Except for using a pair of opposing steel rams, a ram type blowout preventer is similar in operation to a gate valve. When they are activated, the rams are pulled toward the center of the wellbore to close and seal the wellbore. To seal the wellbore the top faces and/or inside of the rams are fitted with elastomeric material so rams can be pressed against each other or around the drill pipe through the wellbore. There are four types of ram blowout preventer: pipe, blind, shear, and blind shear.

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i) Pipe Ram It is used to close and seal around a drill pipe to restrict flow in the annulus. Thus mud cannot flow through annulus but there is no restriction within the drill pipe. Size of pipe ram depends on the outside diameter of drill pipe.

Fig 5.3. Shear ram.

ii) Blind Ram It is device which upon command, closes off and seals the well when there is not any tube in the wellbore.

Fig 5.4. Blind Ram

iii) Shear Ram

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The shear ram upon command, cuts the drill pipe or casing with hardened steel blades in an emergency Unlike other rams, It does not seal the well bore.

Fig 5.4. Shear Ram

C. Blind Shear Ram. Blind shear ram cuts the drill pipe or casing and then seal the wellbore. It is to seal a wellbore, even when bore is occupied by a drill string. It work by cutting the drill string as ram close off the ram, and lower portion captured by other rams.

Fig 5.5. Blind Shear Ram Two control pods yellow and blue controls the ram with one at a time. Control pods are connected to shuttle valve. Hydraulic fluid pass through shuttle valve to piston chamber. It exerts a pressure in the piston and it moves front and shear the pipe. Blind shear ram works in emergency when signal from rig is lost.

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CHAPTER 6 EVALUATION OF SHEAR STRESS When cutting comes into contact with drill pipe, deformation of pipe is linear elastic. Increase in shear ram load increases stress of drill pipe gradually. When the stress exceeds the maximum yield limit, the deformation of pipe is plastic. When plastic deformation occurs, a dislocation phenomenon between the crystals inside of the material also appears.

Fig 6.1. Finite model of the drill pipe and shear ram [1] Cross section of pipe becomes oval shape due to squeezing. The shearing time is usually 5s-8s which is very short. As a result heat accumulation is not large. So the effect of temperature is not considered. The shear ram is a monolithic ram, and its substrate and edge material are the high strength alloy steel 40CrNiMo.

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Fig 6.2. Fracture of the drill pipe [1].

Fig 6.3. Stress distribution of the drill pipe in the shearing process [1]. Shearing process in ram divided into 4 steps. Stresses in the upper and lower ram is simulated using finite element analysis (FEM). For shear BOP, shear rams are installed on the U-shape slot. There is one hydraulic push rod after each shear ram. When shutting occurs, hydraulic system drives the push rods, and then the push rods drive the two rams to close. When the rams are closed, the drill pipe will be gradually cut off. After shearing, rams mesh each other to produce sealing function.

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Fig 6.4. Von Mises stress of the upper shear ram[1].

Fig 6.5. Von Mises stress of the lower shear ram[1]

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CHAPTER 7 RESULTS AND DISCUSSIONS

7.1 Drill pipe length Peak stress of ram at length 9m, 1000m, 2000m, 3000m, 4000m, 4800m, 6000m, are studied. It is found out that with increase in drill pipe length, the peak stresses of two rams gradually decrease .From this it can be concluded that longer drill pipe can help in shearing process.

Fiq 7.1. Peak stresses of the rams for different drill pipe lengths [1].

7.2 Drill pipe diameter

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Six different diameters 168.3mm, 139.7mm, 127mm, 114mm, 102mm, 89mm, are selected. It is found out that smaller the diameter and wall thickness are, the shearing process is easier.

Fig 7.2. Peak stresses of the rams for different drill pipe diameter [1]

7.3 Blade angle Peak stresses of ram at angles 0°-6° are studied. It is found that with increase in the blade angle, the stresses of the ram decrease first and then increase. From graph, it is found out that optimal blade angle for upper ram is 4° and that of lower one is 3°.

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Fig 7.3. Peak stresses of rams for different blade angles [1].

7.4 V-shaped angle and end chamfer angle Peak stresses of ram for v- shaped angle at range 155°-180° and edge chamfer angle at 0°-90° are studied..With increase in angle, peak stress of ram decreases first and then increases. When v-shaped angle is 163°, the stresses of two rams are the smallest. The properties of edge chamfer angle at 0°-90° is studied. It is found out that With the increase in the edge chamfer angle, the peak stresses of the rams decrease first and then increase, but the changing laws of upper ram and lower ram are different. When the edge chamfer angle is 45°, the peak stress and high stress area of upper ram are the smallest, and the optimal edge chamfer angle of the upper ram is 45°.When the edge chamfer angle is 15°, the peak stress and high stress area of lower ram are the smallest, and the optimal edge chamfer angle of the lower ram is 15°.

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Fig 7.4. Peak stresses of the rams for different v-shape angles [1].

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Fig 7.5. Peak stresses of the ram for different edge chamfer angles [1]

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CHAPTER 8 CONCLUSIONS

Blow out preventer is irreplaceable in drilling industry. Conventional design are replacing by modern BOP as it is more reliable and gas more safety features than the conventional design. Parameters influencing working of BOP include drill pipe length, drill pipe diameter, blade angle, v-shaped angle and end- chamfer angle.      

Increase in drill pipe length reduce the shear stress in ram Decrease in drill pipe diameter and thickness reduce the shear stress in the ram Blade angle at 4° is optimum for upper ram and 3° is optimum for lower ram The optimum v-shape angle for maximum shearing of drill pipe is found to be 163° The optimum end chamfer angle for upper ram is 45° where as for lower ram is 15°. Shear stress reduces to minimum value and then increases to maximum for different angles.

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REFERENCES

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[1] Chuanjun Han, Xue Yang, Jie Zhang, Xianping Huang, Study of the damage and failure of the shear ram of the blowout preventer in the shearing process, Engineering Failure Analysis 58 (2015) 83–95.

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[2] J.V. Langston, “Training Program To Improve Well Control Operations.”

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[3] Youhong Sun, Feiyu Zhang, Qingyan Wang, Ke Gao, Application of “Crust 1” 10k ultra-deep scientific drilling rig in Songliao Basin Drilling Project(CCSDSKII), Journal of Petroleum Science and Engineering 145(2016), 222–229.

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