Report on drilling fluids

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PETROLEUM ENGINEERING DEPARTMENT

PCB 2033 DRILLING ENGINEERING EXPERIMENT TITLE: DRILLING SIMULATOR Group 4 Group Members: 1. 2. 3. 4.

JACINTO SIQUERA MAKSAT GYZYLOV GERALDINA MATEUS TOBIAS CLAUDIO JOSE NOVEL

16623 15708 16622 16592

Experiment Date: 11 February 2014 (Thursday) 4.00pm to 6.00pm Submission Date:

Introduction Fundamentally, the drilling process is consisted of several systems, including: -

Circulating system Rotating system Hoisting system Power system Well control system

Each system has their specific functions and will be explained below.

Circulating system A major function of the fluid circulating system is to remove the rock cuttings from the hole as drilling progresses. The drilling mud travels: 1) From the steel tanks to the mud pump 2) From the pump through the high- pressure surface connection to the drill string 3) Through the drill string to the bit 4) Through the nozzle of the bit and up the annular space between the drill string and hole to the surface 5) Through the contaminant- removal equipment back to the suction tank The principle components of the rig circulating system include: 1) 2) 3) 4)

Mud pumps Mud pits Mud-mixing equipment Contaminant- removal equipment

The drilling fluid that is being circulated is called mud. The main functions of mud include: 1) 2) 3) 4) 5)

Lifting –up the cuttings Covering the underground pressure Restraining the well bore Creating mud cake and preventing filtrate loss Lubricating drill bit and drill string

6) Gathering down hole information 7) Transferring hydraulic force to down hole motor The mud density can be altered by adding different amount of additive. The mud density is very important to control the hydraulic pressure and prevent blowout accident. During this experiment, the mud balance will be used to test and determine the mud density followed by the FANN viscometer to determine the gel strength, yield point and plastic viscosity.

Rotating system The rotary system includes all of the equipment used to achieve bit rotation. Besides, this system also helps when tightening and loosening the pipe connection. There are 2 types of rotary sources:

1) Rotary table The drill string is turned in clockwise direction as viewed from above by the revolving or spinning section of the drill floor. The drill string receives the rotary motion and power through the Kelly bushing and the Kelly. Nowadays, almost all rigs have a rotary table. It will either act as the primary or backup system for rotating the drill string. Power for driving the rotary table usually is provided by an independent rotary drive. However, in some cases, power is taken from the drawworks. A hydraulic transmission between rotary table and the rotary drive is often used. 2) Top Drive Top drive technology, which allows continuous rotation of the drill string, has replaced the rotary table in certain operations. A few rigs are being built today with top drive systems only, and lack of traditional Kelly system. Top drive is a device that turns the drill string. It consists of one or more motors (electric or hydraulic) connected with appropriate gearing to a short section of pipe called a quill, that in turn may be screwed into a saver sub or the drill string itself. The top drive is suspended from the hook, so the rotary mechanism is free to travel up and down the derrick. This is radically different from the more conventional rotary table and kelly method of

turning the drill string because it enables drilling to be done with three joint stands instead of single joints of pipe. It also enables the driller to quickly engage the pumps or the rotary while tripping pipe, which cannot be done easily with the kelly system.

Hoisting System The function of the hoisting system is to provide a mean of lowering or raising drill strings, casing string and other subsurface equipment into or out of the hole. The principle components of the hoisting system are: 1) The derrick and substructures 2) The block and tackle 3) The drawworks Drilling operations performed with the hoisting system are called: 1) Making a connection This process refers to the periodic process of adding a new joint of drill pipe as the hole deepens. 2) Making trip This process refers to the process of removing the drill string from the hole to change a portion of the downhole assembly and then lowering the drill string back to the hole bottom. A trip is made usually to change a dull bit.

Power System Most rig power is consumed by the hoisting and fluid circulating system. The other rig systems have much smaller power requirements. The early drilling rigs were powered primarily by steam. However, because of high fuel consumption and lack of portability of the large boiler plants required, steam powered rigs have become impractical. Modern rigs are powered by internal combustion diesel engines and generally sub classified as: 1) Diesel- electric type Diesel- electric rigs are those in which the main rig engines are used to generate electricity. Electric power is transmitted easily to the

various rig systems, where the required work is accomplished through the use of electric motors. 2) Direct drive type Direct- drive rigs accomplish power transmission from the internal combustion engines using gears, chains, belts and clutches rather than generators and motors. The initial cost id less compared to dieselelectric type. The development of hydraulic drives has improved greatly the performance of this type of power system.

Well Control System The well control system prevents the uncontrolled flow of formation fluids from the wellbore. When the bit penetrates a permeable formation that has a fluid pressure in excess of the hydrostatic pressure exerted by the drilling fluid, formation fluid begins displacing the drilling fluid from the well. The flow of formation fluids into the well in the presence of drilling fluid is called a kick. The well control system permits: 1) Detecting the kick 2) Closing the well at surface 3) Circulating the well under pressure to remove the formation fluids and increase the mud density 4) Moving the drill string under pressure 5) Diverting flow away from rig personnel and equipment There are several causes of a kick, including: 1) 2) 3) 4) 5)

Low density drilling fluid Abnormal reservoir pressure Swabbing Not keeping the hole full on trips Lost circulation.

Failure in well control system results in an uncontrolled flow of formation fluids and is called a blowout. Blowout can cause loss of life, drilling equipment, the well, oil and gas reserves and environment. Hence, the well control system is one of the most important systems on the rig. Kick detection during drilling operations usually is achieved by use of a pitvolume indicator or a flow indicator. Both devices can detect a increase in the flow of mud returning from well over that which is being circulated by the pumps.

The flow of fluid from the well caused by a kick is stopped by using special pack- off devices called blowout preventers (BOP’s). Multiple BOP’s used in a series are referred to a collectively as a BOP stack. The BOP must be capable of terminating flow from the well under all drilling conditions. When the drill string is in the hole, movement of the pipe without releasing the well pressure should be allowed to occur. In addition, the BOP stack should allow fluid circulation through the well annulus under pressure. These objectives are usually accomplished by using several ram preventers and one annular preventer.

Objective of Experiment

The objectives of this experiment are as follow:  To conduct drilling operation simulation by using DrillSim 500.  To identify any kick indications by using DrillSim 500.  To control any kick confronted during drilling operations.

Procedures Drilling Test 1. The pump 1 rate was set to 20 spm (129psi), followed by 30 spm (225 psi). 2. The pump 2 rate was set to 20 spm (126psi), followed by 30 spm (227psi). 3. Mud pump 1 & 2’s rate were increased to achieve total pressure of 2500 Psi, at 119 spm. 4. The TDS Drive was switched on and rotary speed was set to 100 rpm. 5. The Draw Work was switched on and the speed was increased continuously 6. The handbrake was used to lower the drill string until bit touched bottom. 7. WOB was increased and maintained from 25 to 35 ton. 8. The drilling was continued by adjusting WOB at 25 to 35 ton lbs by adjusting handbrake at every time. 9. Kick indication was being identified at all operation time by observing alarm indication, pit deviation gauge, retune flow gauge. 10.Kick procedure was executed when kick is encountered.

Well Control Drillers Method 1. The surface instrumentation was monitored. Step 2 was followed once “positive” was kick detected. 2. Off bottom & space out were picked up (Tooljoint was ensured to be not across ram). The rotary was stopped. 3. Pump 1 and 2 were stopped. BOP’s Annular or Upper Ram was closed. BOP upstream choke valve was opened. 4. Stabilized SIDPP and SICP were read and recorded. Final pit gain were read and recorded as well. The remote choke was adjusted to maintain the SICP constant by increasing the pump pressure continuously 5, 10, 15 and 20 stocks.

5. When the casing pressure is stabilized, the new circulating drill pipe pressure was read and recorded. The remote choke was adjusted to maintain the initial circulating drill pipe pressure constant until the influx (the kick) was out. Once influx was out, pump was stopped & remote choke was closed completely while maintaining the last CP constant. (If no further influx enter the well bore, theoretical SICP & SIDP should be the same) 6. Mud weight was increased to kill mud weight. Kill MW = (SIDPP /total vertical depth) / 0.052+ original MW Remote choke was opened and pump was started at 20 or 30 strokes per minute while maintaining SICP constant. Once desired pump rate was reached, SICP was continued to be remained constant until kill mud reach bit. Once kill mud reached bit, FCP (final drill pipe circulating pressure) were started to be remained constant until kill mud reached surface. 7. When the kill mud reached surface, pump was stopped & then remote choke was closed. SIDPP, SICP and pit volume were read and recorded. (SIDPP & SICP should be zero if the well is dead) BOP Upper ram was opened, BOP upstream choke valve was closed and flow check well. Well Control Engineers Method 1. The surface instrumentation was monitored. Step 2 was followed once “positive” was kick detected. 2. Off bottom & space out were picked up (Tooljoint was ensured to be not across ram). The rotary was stopped. Pump 1 and 2 were stopped. BOP’s Annular or Upper Ram was closed. BOP upstream choke valve was opened. 3. Stabilized SIDPP and SICP were read and recorded. Final pit gain were read and recorded as well. Kill sheet was prepared. 4. Mud weight was increased to kill mud weight. Kill MW grad = ((SIDPP + 150 psi overbalance/ 0.052*vert.depth) + original MW) Remote choke was opened and pump was slowly brought to kill rate to 20 or 30 spm.

Remote choke was adjusted to maintain casing pressure constant. When the pump was up to kill rate and casing pressure stable, the drill pipe pressure schedule was followed and maintained by remote choke adjustment according to the kill sheet. 5. When the kill mud was at the bit, FCP (final drill pipe circulating pressure) was maintained constant until kill mud reached surface. 6. When the kill mud reach surface, pump was stopped and the remote choke was closed. SIDPP, SICP and pit volume were read and recorded. (SIDPP & SICP should be zero if the well is dead) The BOP annular or upper ram was opened, BOP upstream choke valve was closed and flow check well.

RESULTS

Drilling test Pump Pump #1 Pump #2

stroke(s) per minute, spm 20 30 20 30

Pump pressure, psi 130 224 129 232

Well Control Drillers Method

1. When the BOP’s upper Ram is closed and the choke is opened. SIDPP SICP

331 psi 298 psi

Pit Deviation

1 barrel

2. After bringing the pump to 30 strokes per minute. SIDPP SICP Pit Deviation

620 psi 295 psi 1 barrel

3. When the influx is out. SIDPP SICP

454 psi 452 psi

4. Kill mud weight = [(331/6000) / 0.052] + 12.22 = 13.28 ppg

5. As the mud reached the bit. FDP = 375 psi

6. As the mud reached the surface. SIDPP SICP Pit Deviation Trap Pressure

295 psi 296 psi 5.7 barrel 6 psi

DISCUSSION OF RESULTS This experiment was to simulate the drilling operation, along with controlling an expected kick. To control the kick, Well control drillers method was used due to its simplicity and it has less risk of encountering a stuck pipe. The Driller’s Method requires two circulations. During the first circulation, the influx is circulated out with the original mud weight. Constant BHP is maintained by holding circulating drill pipe pressure constant through the first circulation. If the original mud weight is insufficient to balance the formation pressure, the well is killed by circulating a heavier mud (kill mud) in a second circulation. To hold constant BHP during the second circulation, one of two procedures is employed. Casing pressure is held constant while pumping kill mud from surface to bit, and drill pipe pressure is held constant thereafter until kill mud is observed returning to the surface. Alternately, during second circulation, a drill pipe pressure schedule can be calculated and followed while pumping kill mud from surface to bit, and drill pipe pressure is held constant thereafter. In this experiment, Top Drive System (TDS) was used instead of Rotary System. The advantage of TDS is that 3 drill pipes can be joined together at a time, as compared to Rotary System in which only 1 drill pipe can be joined at a time. Drawworks allows the vertical movement of the drill pipe. If the formation pressure is higher than the wellbore pressure, a kick may occur. Whereas if the formation pressure is lower than the wellbore pressure, the formation will be damaged. The lower pressure of the wellbore as compared to the formation is caused by 2 reasons. Firstly, the mud weight may be too low. Secondly, the hydrostatic pressure exerted on the formation by the fluid column may be insufficient to hold the formation fluid in the formation. “Kick” is any undesirable flow of formation fluids from the reservoir to the wellbore that occurs as a result of a negative pressure differential across the formation face. If the kick reaches the surface, it is known as a blow out. Kill line can be used to inject higher density drilling fluid in the case of Blowout Preventer (BOP) is closed.

While operating the driller brake, the lever should be given a jerk in order to slowly lower down the drill string. If the lever is push upwards and held in position, the drill string will lower rapidly, which may result in damaging the drill bit and drill collar. When the kick occurred, the shut in drill pipe pressure (SIDPP) was 331 psi, while the shut in casing pressure (SIDP) was 298 psi. To facilitate the kick controlling process, several parameters were recorded, namely SIDPP pressure, SICP pressure and the pit volume. In order to stop the kick, the original drilling mud had to be replaced with a higher density drilling mud. According to the equation: Kill MW = (SIDPP /total vertical depth) / 0.052+ original MW where SIDPP is 331 psi total vertical depth is 6000 feet original mud weight is 12.22 ppg As a result, the calculated kill mud weight was 13.28 psi.

CONCLUSION In conclusion, the activities done during this experiment allowed us to understand further about the objectives of this experiment. Namely to conduct a drilling operation by using DrillSim 500, identify any kick indications and subsequently control any kick which occurs during the drilling process. We have learned how a kick may occur, such as due to the fact that the drilling mud density is not appropriate and therefore can’t provide sufficient hydrostatic pressure to prevent the undesirable flow of formation fluid into the wellbore. Also we have learned how to prevent and stop the kick by maintaining pressure and other various important components. If a kick is not controlled well, a blowout may occur, which may in turn cause the loss of equipment and life.

ANSWER TO GIVEN QUESTIONS

1. Explain the correlation between bottom hole temperature and hydrostatic gradient.

An increase in the temperature at the bottom hole usually indicates an increase in pressure. The Bottom hole temperature is an important factor affecting cement thickening time, rheological properties, compressive strength development and set time. As water column increase with depth, the pressure at the bottom is higher at the top .This increase in pressure is consistent at descending depth .Hydrostatic gradient is pressure at a specific point in water column will drop with a constant value at depth 2. There are a variety that can cause abnormal formation fluid pressure. List 4 of the principal causes. 

Depositional Effects



Diagenetic Processes



Tectonic Effects



Thermodynamic Effects

3. What is MAASP stands for? When is the right time to re-calculate this parameter? MAASP stand for Maximum Allowable Annulus Surface Pressure, is an absolute upper limit for the pressure in the annulus of an oil and gas well as measured at the wellhead. If the mud weight is changed, MAASP has to be recalculated.

4. A well can be induced to flow by swabbing which happens due to the reduction of bottom hole pressure when pulling pipe. List 3 conditions that can cause swabbing. 

Pulling pipe too fast



Poor Mud Properties ( density)



Large OD tools ( outer diameter tools)

5. List at least 2 causes of the increase in rate of penetration during drilling. 

Increase in bit weight



Increase in rotary speed



Use suitable bit which the diameter, type, condition, and jet configuration is suitable with the formation to be drilled.

6. Mention at least 5 components of drill stem. Drill stem is the string of drill pipe that transmits power from the surface down to the drill bit in well drilling. The components are: 

Drill String



Swivel



Sub



Kelly



Drill Collar



Packer



Drill bit



7. Shown below is a pressure versus volume plot of a leak off test

The leak off was carried out with a 10.6 ppg mud. The casing shoes is at 4000 ft TVD

a. What is the maximum pressure that the exposed formations below the shoe can support? (CSGTVD x MUDWT x 0.052) + Surface pressure = (4000 x 10.6 x 0.052) +1100 = 3305 psi

b. What is the “Fracture Gradient”? Fracture gradient = Max. Press. + CSGTVD = 3305 + 4000 = 0.826 psi/ft c. What is the maximum mud weight? Max Mud Weight = Fracture gradient + 0.052 = 0.826 + 0.052 = 15.88 ppg d. If drilling was resumed and the mud weight was increased to 12.6 ppg. Calculate M.A.A.S.P MAASP = (Max mud weight – Drilling mud weight) x 0.052 x CSGTVD = (15.88 – 12.6) x 0.052 x 4000 = 682 psi

8. Given the following data: Depth

10000ft TVD

Bit size

8 ½”

Shoe depth

8500ft TVD

Mud weight

12.6 ppg

Collars – 600ft. Capacity

=

0.0077 bbl / ft

Metal displacement

=

Drill-pipe 5” capacity

=

0.03 bbl / ft

0.0178 bbl / ft

Metal displacement

=

Casing / pipe annular capacity =

0.0476 bbl / ft

Casing capacity

=

One stand of drill-pipe

=

0.0476 bbl / ft

0.0729 bbl / ft

94 ft

Assuming the 12.6 ppg mud givens an over-balances of 200 psi

a. If 10 stands of pipe are removed “dry” without filling the hole, what would be the resultant reduction in bottom-hole pressure?

Total depth = number * one stand drill-pipe length = 10 * 94 = 940 ft

Pulling dry pipe (psi/ft) =

Since it is removed dry, no mud is being carried out.

Pulling dry pipe (psi/ft) = Mud Gradient

= 0.052 * Mudweight = 0.052 * 12.6 = 0.6552 psi/ft

Metal Displacement = 0.0476 bbl/ft Casing Capacity = 0.0729 bbl/ft Pulling dry pipe (psi/ft) = = 1.2327 psi/ft

Reduction in Pressure = Pulling dry pipe * Depth = 1.2327 * 940 = 1158.74 psi

b. If 5 stands of pipe had been pulled “wet” without filling the hole, the resultant reduction in bottom-hole pressure would be.

Total depth = number * one stand drill-pipe length = 5 * 94 = 470 ft Since it is removed wet, mud is being removed too. Pulling wet pipe (psi/ft) =

Pulling wet pipe (psi/ft)= =

Metal Displacement = 0.0476 bbl/ft Casing Capacity = 0.0729 bbl/ft Drill pipe capacity = 0.0178 bbl/ft

Pulling wet pipe (psi/ft) = = 5.713 psi/ft Reduction in Pressure = Pulling dry pipe * Depth = 5.713 * 470 = 2685.11 psi c. If prior to tripping a 20 barrel slug of 14.6 ppg mud was displaced to prevent a wet trip, what would be the expected volume return due to the U-tubing of the heavy mud? (

Dry pipe volume = =

(

= 3.175 barrel

) )

References Applied Drilling Engineering, by Adam T. Bourgoyne Jr., Martin E. Chenevert. Keith K. Millheim and F.S.Young. SPE Textbook Series, Vol. 2, Society of Petroleum Engineers, Richardson, TX, 1991. Drilling Engineering, A complete Well Planning Approach, by Neal Adams and Tommie Carrier. PennWell Publishing Company, Tulsa, OK, 1985. Oilwell Drilling Engineering, Principles and Practice, by H. Rabia. Graham & Trotman. Printed by The Alden Press, Oxford, UK, 1985. Laboratory Manual

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