DRILLING SIMULATION INTRODUCTION
BASIC DRILLING SYSTEM 1.1. Circulating System
The main objective of circulation system is to pump fluid through the whole active fluid system, including the borehole and all the surface tanks that constitute the primary system. The complete, circuitous path that the drilling the drilling fluid travels starting at the:
main rig main rig pumps
surface piping
standpipe
kelly hose (rotary)
kelly
drillpipe
drill collars
bit nozzles
openhole and casing strings
flowline
mud-cleaning mud-cleaning equipment
mud tanks
positive displacement main rig pumps
Functions of Drilling Fluids:
Lift-up cuttings
To cover the underground pressure
To restrain the well bore
To create mud cake and prevent filtrate loss
To lubricate drill bit and drill string
Down hole information gathering media and well logging
To transfer hydraulic force to downhole motor
1.2. Rotating System
The main objectives of this system is to create rotation force towards drill bit at the bottom hole and provide helps when tightening and loosing pipe connection. There are two types of rotating source: 1.
Rotary Table The revolving or spinning section of the drillfloor that provides power to turn the drillstring in a clockwise direction (as viewed from above). The rotary motion and power are transmitted through the kelly bushing and the kelly to the drillstring. Almost all rigs today have a rotary table, either as primary or backup system for rotating the drillstring. Top drive technology, which allows continuous rotation of the drillstring, has replaced the rotary table in certain operations. A few rigs are being built today with top drive systems only, and lack the traditional kelly system.
2.
Top Drive A device that turns the drillstring. drillstring. It consists of one or more motors (electric or hydraulic) connected with appropriate gearing to a short section of p ipe called a quill that in turn may be screwed into a saver sub or the drillstring itself. The topdrive is suspended from the hook, so the rotary mechanism is free to travel up and down the derrick. This derrick. This is radically different from the more conventional rotary table and kelly method of turning the drillstring 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, pipe, which cannot be done easily with the kelly system.
1.3. Hoisting System
The main objective of this system is to provide lifting and dropping force towards drill string and any components around rig floor. Several components of this system are:
crown block
travelling block
mast
substructure (sub)
prime mover
1.4. Pressure Control System
The objective of this system is to prevent blowout and maintain kick during drilling and tripping. The equipment is called Blowout Preventer (BOP). BOP is a large valve at the top of a well that may be closed if the drilling crew loses control of formation fluids. By closing this valve (usually operated remotely via hydraulic actuators), the drilling crew usually regains control of the reservoir, and procedures can then be initiated to increase the mud density until it is possible to open the BOP and retain pressure control of the formation. BOPs come in a variety of styles, sizes and pressure ratings. Some can effectively close over an open wellbore, some are designed to seal around tubular components in the well (drillpipe, casing or tubing) and others are fitted with hardened steel shearing surfaces that can actually cut through drillpipe. 1.5. Power System
The source of power for the rig location is provided by the Power System. On modern rigs, the prime mover consists of one to four or more diesel engines. These engines commonly produce several thousand horsepower. Typically, the diesel engines are connected to electric generators. The electrical power is then distributed by a silicon-controlled-rectifier (SCR) system around the rig site. Rigs that convert diesel power to electricity are known as diesel electric rigs. Older designs transmit power from the diesel engines to certain rig components (drawworks, pumps and rotary table) through a system of mechanical belts, chains and clutches. On these rigs, a smaller electric generator powers lighting and small electrical requirements. These older rigs are referred to as mechanical rigs or more commonly, simply power rigs.
2.
KICK AND BLOW OUT
A kick is defined as 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. Meanwhile, Blow Out happens if the kick is reaching the surface and uncontrollable. Wells kick because the reservoir pressure of an exposed permeable formation is higher than the wellbore pressure at that depth. Blow out can happen in almost every oil and gas operation such as:
Drilling Operation
Work over Operation
Well Service Operation (Maintenance)
There are many situations which can produce this downhole condition. Among the most likely and recurring are:
Low density drilling fluid.
Abnormal reservoir pressure.
Swabbing.
Not keeping the hole full on trips.
Lost circulation
Kick indicators are classified into two groups: positive and secondary. Anytime the well experiences a positive indicator of a kick, immediate action must be taken to shut-in the well. When a secondary indicator of a kick is identified, steps should be taken to verify if the well is indeed kicking. The "Positive Indicators of a Kick" are:
Increase in Pit Volume
Increase in Flow rate
Immediate action should be taken to shut-in the well whenever these indicators are experienced. It is not recommended to check for flow after a positive indicator has been identifed. The "Secondary Indicators of a Kick" are:
Decrease in Circulating Pressure
Gradual Increase in Drilling Rate
Drilling Breaks
Increase in Gas Cutting
Increase in Water Cutting or Chlorides
The occurence of any of these indicators should alert the Drilling Representative that the well may be kicking, or is about to kick. These indicators should never be ignored. Instead, once realized, steps should be taken to determine the reason for the indication.
3.
SWABBING
Swabbing is a condition that arises when pipe is pulled from the well and produces a temporary bottomhole pressure reduction. Many downhole conditions tend to increase the likelihood that a well will be swabbed-in when pipe is pulled. Several of these are discussed below:
4.
Pulling Pipe Too Fast
Poor Mud Properties
Heaving or Swelling Formations
Large OD Tools
WELL CONTROL PROCEDURE (HARD SHUT IN * REMOTE CHOKE IS ALWAYS CLOSE
DURING DRILLING & TRIPPING ) 1.6. SHUT-IN PROCEDURE WHILE DRILLING 1.
When any indication is observed while drilling that the well maybe flowing, raise the drill with pumps on until spaced out, stop rotating drill string.
2.
Stop pumping and check for flow, if positive;
3.
Close annular or upper pipe rams.
4.
Open BOP upstream choke valve.
5.
Call supervisor and commence plotting a graph of shut in drill pipe & casing pressure. Check pit volume again.
1.7. SHUT-IN PROCEDURE WHILE TRIPPING 1.
When a possible sign is observed, set top tool joint in the slips.
2.
Check for flow.
3.
Install a full opening Safety valve on the drill pipe. Close the valve once it is installed.
4.
CLOSE annular BOP.
5.
Open BOP upstream choke valve.
6.
Alert supervisors.
7.
Read and record pressures on SICP & SIDP
8.
The operator's representative will have to decide whether to kill in situ, or strip back to bottom.
9.
If operator decided to strip to bottom, stab IBOP (Gray valve) & open full opening safety valve. Ready to strip drill string to bottom.
OBJECTIVES
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
Took slow pump rate pump#1 20 spm / 5 psi, 30 spm / 235 psi
Took slow pump rate pump#2 20 spm / 5 psi, 30 spm / 235 psi.
Increased mud pump 1 & 2 to achieve total of 600 gpm (8-1/2” hole size)
Rotary speed was set to 100 rpm.
Handbrake was used to lower the drill string until bit touches bottom.
Increased and maintained WOB at 35.000 lbs.
Continued drilling by adjusting WOB at 35.000 lbs by adjusting handbrake at every time.
Kick indication at all operation time is identified.
Continued to kick procedure when kick is encountered.
Well Control Drillers Method
1. Monitored surface instrumentation. Once “positive” kick detected, follow step 2 . 2. Picked up off bottom & spaced out (ensure tool joint is not across ram). Rotary is stopped. 3. Pump 1 and 2 were stopped. Closed BOP’s Annular or Upper Ram. Opened BOP upstream choke valve. 4. Final (stabilized) SIDPP and SICP were read and recorded. Final pit gain was also read and recorded. Adjusted the remote choke to maintain the SICP constant while bringing the pump up to 20 or 30 strokes per minute simultaneously. When the casing pressure is stabilized, new circulating drill pipe pressure were read and recorded. Adjusted the remote choke to maintain the initial circulating drill pipe pressure constant until the influx (the kick) is out. Once influx out, pump is stopped & remote choke was completely closed while maintaining the last CP constant. (If no further influx enter the well bore, theoretical SICP & SIDP should be the same) 5. Increased mud weight to kill mud weight. Kill MW = (SIDPP + 150 psi overbalance)/(0.052*vert. depth) + original MW Remote choke was opened and started pump at 20 or 30 strokes per minute while maintaining SICP constant. Once desired pump rate reached, continued to maintain SICP constant until kill mud reached the bit. Once kill mud reach bit, FCP (final drill pipe circulating pressure) is started to maintained constant until kill mud reached surface. 6. When the kill mud reached surface, pump is stopped & then re mote choke is closed. SIDPP, SICP and pit volume are read and recorded. (SIDPP & SICP should be zero if the well is dead). BOP upper ram is opened, BOP upstream choke valve is closed and flow check well.
3. Well Control Engineers Method
Monitored surface instrumentation. Once “positive” kick detected, follow step 2.
Picked up off bottom & spaced out (ensure tool joint is not across ram). Rotary is stopped Pump 1 and 2 are stopped. BOP’s Annular or Upper Ram is closed. BOP upstream choke valve is opened.
1. Read and recorded final (stabilized) SIDPP and SICP. Read and re corded final pit gain. Prepared kill sheet.
Increased the mud weight to kill mud weight. Kill MW grad = ((SIDPP + 150 psi overbalance/ 0.052*vert.depth) + original MW) Opened remote choke and slowly bring pump to kill rate to 20 or 30 spm. Remote choke is adjusted to maintain casing pressure constant. When the pump is up to kill rate and casing pressure stabled, followed the drill pipe pressure schedule and maintain it by remote choke adjustment according to the kill sheet.
When the kill mud is at the bit, maintained FCP (final drill pipe circulating pressure) constant until kill mud reached surface.
When the kill mud reached surface, pump is stopped and the remote choke is closed. Read and recorded SIDPP, SICP and pit volume. (SIDPP & SICP should be zero if the well is dead). Open the BOP annular or upper ram, close BOP upstream choke valve and flow check well.
RESULT
Besides starting the experiment, some test have been carried out on the equipment that we going to use- DrillSim 500.The pump 1 and pump2 have been tested at 20 spm and 30 spm respectively. Pump1 20 spm = 123 psi 30 spm = 234 psi Pump 2 20 spm = 127 psi 30 spm = 233 psi
In this experiment, we do the Drilling Test. All procedures are conducted accordingly. Then, we moved to the well control Driller’s method. First and foremost, the well is drilled by increasing bit rotation. At a depth around 6000ft, we are aware of positive kick. At the moment kick was detected. 1. Top drive system is stopped. 2. Pump 1 and 2 are stopped 3. BOP’s annular or Upper Ram is closed then BOP upstream choke valve is opened. (Reminder: Closed BOP’s annular first just fo llowed by opened choke.) If not, blowout may happen. 4. Quickly recorded final stabilize value of SIDPP and SICP as well as pit gain. Remote choke is adjusted to maintain SICP constant. 5. Pull up the drill bit by pulling up the drawworks, and let the drill bit on the above of the surface of the bottomhole. At the same time, the pump is bringing up to 20 strokes per minute simultaneously. 6. Calculate kill mud density by using formula
Kill mud weight = (SIDPP/depth) ÷ 0.52 + original mud weight
KMW = (273/6000) ÷ 0.52 + 12.20 KMW = 13.56
7. SICP is maintained constant until kill mud reached the bit and filling up the outside wellbore. 8. When kill mud reach the bit, FCP is maintained until kill mud reached the surface (can be noticed when there is sudden decrease in mud out weight – it showed at the moment the gas is coming out). 9. After kick are successfully controlled by using killing mud, we continue the drilling as usual following the procedure.
DISCUSSION
As our main objectives of this experiment are: 1.
To conduct drilling operation simulation by using DrillSim 500.
2.
To identify any kick indications by using DrillSim 500.
3.
To control any kick confronted during drilling o perations. We are going to discuss the procedure of controlling a kick and interpret the result
obtained from the experiment. In this experiment, we face kick when drilling process is carrying. What is is “kick” basically? Kick is actually caused by imbalance hydrostatic pressure between formation or formation fluid and the wellbore, therefore causing the flow of the formation fluid (usually is gas) out of the formation to balance up the pressure. There are two ways that can cause the imbalance of pressure between the formation and the wellbore. First, kick happened if the mud weight is low compare to the formation pressure. The hydrostatics pressure exerted by the mud/fluid column not sufficiently/effectively enough to balance up the formation pressure. Mud weight low is only happen when the mud density is low or light and this low density of mud exerted the pressure on the formation is not capable to balance the pressure of the formation when it drilled deeper. In our experiment this kind of kick happen when the drill bit reach 6000ft of depth, it probably a different type of rock layer which given a higher pressure compare to the above layer. As physics theory mentioned high pressure fluid flow into the low pressure area, thus the formation fluid flow into the mud. If the mud is not proper ly control , blow out may happen. This type of kick also known as underbalanced kick. The second way a kick can occur is if dynamic and transient fluid pressure effects, usually due to motion of the drillstring or casing, effectively lower the pressure in the wellbore below that of the formation. This second kick type could be called an induced kick. Once the kick is occurred, we must follow up some crucial procedure in to order to control well and stop any influx of mud into the well. In this experiment, kick occurred we had to shut-in the well using the BOP/ blow out preventer. Then we used Drillers method to control and prevent the blowout of the kick. There are two methods in to order to control the kick are driller method and engineers method. For the experiment we are carrying, we used the driller method to control the kick to prevent blowout happen. Driller method is basically a two complete circulation method; once the kick is spotted, the drill string have to be trip up a short distance, top drive system is stopped but the pump is still operating to pump out the kick (fluid from the formation) by the old mud, and the old mud is then circulated using kill weight mud (new mud). In this experiment, we choose driller method over the engineer method due to its simplicity and it have less risk than engineer method and engineer method involved a lot of complex calculation.
Besides the two methods, kick indicators also can be classified into two groups: positive and secondary. Engineers can easily notice the positive indicator of a kick when there is increase in pit volume for the mud and also increase in flow rate going out of the mud to the surface. If the positive indicator once confirmed, immediate action must be taken to shut-in the well. But for the secondary indicator of a kick, can be detected when there is decreasing in circulating pressure, gradual increase in Drilling rate, increasing in gas cutting and last but not least increasing in water cutting or chloride. There are differences between positive and secondary indicators, because once the secondary indicators is detected, several steps should be taken to verify if the well is indeed kicking or not. In this experiment the simulator has an automated alarm which goes on as soon as a kick is detected so when the alarm went on we encountered a kick with an increase of the pit volume. After detecting the kick the first step was to shut-in the well and start with procedure of controlling the well using the Drillers method. Our aim was to control the well and prevent the potential blow out and also preventing further influx from entering the wellbore. According to the Drillers method the shut-in drill pipe pressure (SIDPP), shut-in casing pressure (SICP) and pit volume should be recorded. We recorded the SIDPP pressure, SICP pressure and the pit volume. All these reading are essential for the procedure of controlling the well for example: SIDPP pressure is used to calculate the Kill mud weight, SICP pressure is determine the controlling method and pit volume is used to specify the
used
to
type of the influx
(water, gas or oil). After taking the readings of SIDPP, SICP and pit volume, we started pumping the kick out by the old mud while adjusting the choke to maintain the SICP constant between 0 and 200 psi. After the SICP is stabilised the choke is adjusted to maintain the SIDPP until the influx is out. When the influx is out, we change the mud weight by changing the density of the mud by calculating the kill mud weight using the below equation:
KMW =
+ OMW
KMW is kill mud weight OMW is the original mud weight =12.20 ppg TVD true vertical depth=6000 ft SIDPP the shut=in drillpipe pressure =273 psi KMW = 13.56 ppg The kill mud weight is then circulated into the wellbore from the pit, the pump will pump the kill mud weight to the bottom of the drill bit, but when the new mud is transferring, we have to maintain the pressure (FDP) until the new mud reached the surface
by controlling the choke. Once the mud reached the surface the pump was stopped and choke was closed but the SIDPP and SICP were not zero which meant that the well is not dead yet; the readings are shown above. As thee choke was opened and closed finally the SIDPP and SICP were both zero. The flow was checked. Finally the well is dead and the drilling operation can be resumed. The key point here is that during the kick control the well bore pressure is maintained slightly higher than the formation pressure.
ANSWER TO GIVEN QUESTIONS 1. Explain the correlation between bottom hole temperature and hydrostatic gradient.
Bottom hole temperature is an important factor affecting cement thickening time, rheological properties, compressive strength development and set time. Pressure gradient is the change per unit of 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
Structural Causes and
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)
Heaving or swelling Formations
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
Increase in fluid circulation rate, the rate of mud flowing from nozzle
Use suitable bit which the diameter, type , condition , and jet configuration is suitable with the rock.
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
Tool joint
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
=
0.03 bbl / ft
Drill-pipe 5” capacity
=
0.0178 bbl / ft
Metal displacement
=
0.0476 bbl / ft
Casing / pipe annular capacity
=
0.0476 bbl / ft
Casing capacity
=
0.0729 bbl / ft
One stand of drill-pipe
=
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
REFERENCE
http://www.scribd.com/doc/4209107/ABERDEEN-Drilling-Schools-Well-Control
http://www.offshore-mag.com/articles/print/volume-66/issue-1/drilling-completion/newdrilling-process-increases-rate-of-penetration-footage-per-day.html
http://en.wikipedia.org/wiki/MAASP
Rotary Drilling Handbook, sixth edition ,J.E.Brantly (ed.) Palmer Pub ,New York City
