Space out means that you stop your drill string at the proper location where all the BOP rams (annular and pipe rams) will not close against a tool joint. Please see the figure below for more understanding.
Practically, on land or offshore (shelf), stopping your drill string with the tool joint at the rotary table is the correct and simple way to space out. The reason is that most of rigs are designed to have about 30 ft from the rotary table to top of annular preventer. Anyway, since each rig is different, you need to make sure that the drilling contractor has the correct way to space out.
Why is it important to space out? You may heard about 3-S (Space Out, Shut down, and Shut In) for well control. This is the first important step to shut the well in effectively. If you properly space out, you will have ability to control the well in the correct way. However, if you don’t space out your drill string correctly, you may not be able to use one or more of your BOP effectively and you will be in a big trouble.
Leak Off Test – Test – you you pressure test shoe and formation until formation break down. Let’s I explain more about it: Leak off Test is conducted in order to find the fracture pressure (fracture gradient) of formation and shoe. When conducting the LOT, you will pump drilling fluid to until you see the fracture trend of formation. Once formation is fractured, the first pressure that deviated from a trend is typically called Leak Off Pressure. We use the leak off pressure to calculate LOT.
Formation Integrity Test – Test – you you test strength of shoe and formation to designed pressure. Let’s I explain more about it: Formation Integrity Test is typically used for testing strength of formation and shoe by increasing Bottom Hole Pressure (BHP) to designed pressure. When you do the FIT test, you will increase surface pressure until it reaches the required pressure only. There is no intention to break the formation with FIT. You will do FIT to ensure that you will be able to drill to section target depth and will be able to control the well in case of well control situation without underground blow out.
Margin of Overpull in Drillstring
Margin of overpull is additional tension to be applied when pulling the stuck drill string without breaking the tensile limit of the drill string. This is the difference between maximum allowable tensile load of drill string and hook load.
The formula for margin of overpull is described below;
Margin of Overpull = Ta – Ta – Th Th
Where;
Ta is the maximum allowable tensile strength, lb.
Th is the hook load (excluding top drive weight), lb.
The ratio between Ta and Th is safety factor (SF).
SF =Ta ÷ Th
Example: The drill string consists of the following equipment:
5” DP S-135, S-135, 4-1/2” 4-1/2” IF connection, adjusted weight of 23.5 ppf = 8,000 ft
5” HWDP S-135, S-135, 4-1/2” 4-1/2” IF connection, adjusted weight of 58 ppf = 900 ft
Margin of Overpull in Drillstring
Margin of overpull is additional tension to be applied when pulling the stuck drill string without breaking the tensile limit of the drill string. This is the difference between maximum allowable tensile load of drill string and hook load.
The formula for margin of overpull is described below;
Margin of Overpull = Ta – Ta – Th Th
Where;
Ta is the maximum allowable tensile strength, lb.
Th is the hook load (excluding top drive weight), lb.
The ratio between Ta and Th is safety factor (SF).
SF =Ta ÷ Th
Example: The drill string consists of the following equipment:
5” DP S-135, S-135, 4-1/2” 4-1/2” IF connection, adjusted weight of 23.5 ppf = 8,000 ft
5” HWDP S-135, S-135, 4-1/2” 4-1/2” IF connection, adjusted weight of 58 ppf = 900 ft
Mud motor and MWD, weight 20 Klb, = 100 ft
Expected hook load at TD = 270 Klb
Tensile strength of 5” DP S-135 S-135 (premium class) = 436 Klb
Tensile strength of 5” HWDP S-135 S-135 (premium class) = 1,100 Klb
90% of tensile strength is allowed to pull without permission from town.
Determine the margin of overpull from the information above.
Maximum tension will happen at the surface so 5”DP will get the most tension when pulling and since only 90% of tensile strength is allowed. The allowable tensile (Ta) is as follows;
Ta = 0.9 x 436 = 392 Klb
Th = 270 Klb at TD
Margin of over pull = 392 – 392 – 270 270 = 122 Klb
Safety Factor = 392 ÷ 270 = 1.45
Reserve Fluid System and Pumping System in Koomey Unit
Reserve Fluid System in Koomey According to API RP53, each closing unit should have a fluid reservoir tank with a capacity equal to or at least twice the usable fluid capacity of the accumulator system and reservoir fluid is stored at atmospheric pressure
Pumping System in Koomey Unit Pumps in the Koomey Unit provide power to charge bottles to 3,000 psi. According to API RP53, it states about the pumping system as follows: • Two or three independent sources of power (Air, Electric or Nitrogen) • For surface accumulators: With the acc umulator removed from service, each pump system should be capable of closing the annular BOP on drill pipe, opening HCR and obtaining a minimum pressure of 200 psi over pre -charge pressure within 2 minutes. Once the BOP rams are activated, pressure in the bottles will drop due to fluid movement. When pressure drops to set pressure, pumps will automatically kick in and pressure up the bottles to 3,000 psi. The set points of each pump are as follows: • Electrical pump is normally set at 2700 to 3000 psi. • Pneumatic pump is normally set at 2600 to 2900 psi.
Trip Tank is a small metal tank with small capacity about 20-40 bbls with 1 bbl divisions inside and it is used to monitor the well. There are several operations that we can use the trip tank to monitor the well as follows;
1. Trip Out Of Hole (TOOH): While tripping out of hole, the trip tank is used to track volume of mud replacing volume of drill string. The volume of mud should be equal to displacement volume of any kind of tubular tripped out of hole. 2. Trip In Hole (TIH): While tripping in hole, the drilling string (bit, BHA and drill pipe) is ran back in the hole, the trip tank must be use to keep track volume gain. The expected volume gain should be equal to the displacement volume of whole string. Learn more about pipe displacement 3. Flow check: The trip tank is utilized to determine well condition in order to see if the well is still under static condition. The importance of trip tank is as follows: 1. Provide sufficient hydrostatic pressure to prevent influx from reservoir. When TOH, mud hydrostatic will be lost because mud volume must substitute drill pipe volume pulled out of hole. If hydrostatic pressure decreases too much, influx from reservoir can come into the hole and make a trouble in well control. For this reason, mud in trip tank must be filled into hole to maintain hydrostatic pressure. 2. Kick Indicator: Volume of mud from the trip tank is pumped in the hole can be an indicator that relates to a situation occurring in wellbore as kick. If the volume of mud measured by trip tank is less than the expected volume of drill pipe volume tripped out of hole, the suspect problem is kick because volume of kick substitutes volume of mud. The circulation system while tripping I would like to show the circulation system while tripping out of hole therefore you will be more understanding about how trip tank works.
While Tripping Out of Hole (TOH), a trip tank pump will circulate mud into a bell nipple in order to keep the hole full all the time and the over-flow mud will return back to the trip tank. Once every stand is pulled, the mud volume in the well will decrease because the drill pipe is pulled out of
hole. Since the trip tank pump is always run while tripping, the annulus will be full all the time (see figure below).
Drill Collar Weight Calculation To Prevent Drill Pipe Buckling Drill collar provides weight to the bit for drilling and keep the drill string from buckling. Additionally, drill pipe should not run in compression because it can get seriously damaged therefore we need to know weight of drill collar that is enough to provide weight to the bit.
Drill pipe buckle due to insufficient of drill collar
Drill pipe straight because of sufficient drill collar weight Drill collar weight in a vertical well
The following formula is used to determine required drill collar weight to obtain a desired weight on bit for a vertical well.
WDC = (WOB x SF) ÷ BF Where WDC is drill collar weight in air, lb. WOB is a required weight on bit, lb. SF is a safety factor. BF is mud buoyancy factor .
Drill collar weight in a deviated well In a deviated well, the drill collar weight will not directly transfer to the bit because of well inclination which has direct affect on weight on bit.
The following formula is used to determine required drill collar weight to obtain a desired weight on bit for a deviated well. WDC = (WOB x SF) ÷ (BF x COS (θ)) Where WDC is drill collar weight in air, lb. WOB is a required weight on bit, lb. SF is a safety factor. BF is mud buoyancy factor .
θ is inclination of the well. Example: The deviated well has inclination of 30 degree in tangent section and planned mud weight is 12.0 ppg. Safety factor for this case is 25%.
What is the drill collar weight to obtain the desired WOB of 50 Klb?
Buoyancy Factor = (65.5 – 12.0) ÷ 65.5 = 0.817 SF @ 25 % = 1.25 WDC = (50,000 x 1.25) ÷ (0.817 x COS (30)) WDC = 88,333 Klb In this case, drill collar weight in the air should be 88.3 Klb. In reality, the BHA does not only have the drill collar so you need to adapt this figure. For instant, the BHA consists of mud motor,
.
stabilizer, LWD and HWDP which have a total weight of 30 Klb Therefore, the actual drill collar weight is just only 58.3 Klb (88.3 – 30).
Driller’s Method Quiz No. 1 In order to get more understanding about driller’s method, there are some quizzes that will help you get clear picture of it. 1st example -
Before start circulating, you have the following information Original Shut in Drill Pipe Pressure = 500 psi Initial Circulating Pressure (ICP) = 1500 psi
After end of 1st circulation of Driller’s Method, the drillpipe pressure gauge and the casing pressure gauge shows that the circulating drill pipe pressure = 1500 psi and casing pressure = 650 psi (see the figure below).
Do you think what is happening with the well? VVV VV V V Answer: There is influx (kick) remaining in well because casing pressure is higher than the
original shut in drill pipe pressure. Additional circulation is required for this case.
Explanation
Driller’s method concept is to hold bottom hole pressure constant therefore with neglecting frictional pressure, once influx in out of hole, you should see that casing pressure must be equal to initial shut in drill pipe pressure Drill pipe side: BHP = Hydrostatic Pressure + Shut in Drill pipe pressure —> equation 1 Casing side: BHP = Hydrostatic pressure + Casing Pressure + Frictional Pressure —> equation 2 Neglect frictional pressure so we can write the formula like this. Casing side: BHP = Hydrostatic pressure + Casing Pressure —> equation 3 With the assumption stated above, you will see that equation 1 = equation 3 Then you will know that Shut in Drill pipe pressure = Casing Pressure
learn About Drill Pipe Float Valve A drill pipe float valve is a check valve installed in the drill stem that allows mud to be pumped down but prevents flow back up. There are two types of float valves which are flapper type and plunger type.
Dilution of Mud System to Control Low Gravity Solid by Adding Mud
Adding bbl of drillingfluid can help control low gravity solid (LGS) in mud system. However, this is different from the way to control LGS by adding base fluid as base oil or water because mud that is added into system has some Low Gravity Solid (LGS). Hence, when we calculate it, we need to account for Low Gravity Solid (LGS) of new mud into the calculation as well. This post will demonstrate you how to determine barrels of drilling fluid required to achive the desired Low Gravity Solid (LGS). Formula, used to calculate dilution of mud system, is listed below; Vwm = Vm x (Fct – Fcop) ÷ (Fcop – Fca)
Where; Vwm = barrels of dilution water or base fluid Vm = total barrels of mud in circulating system Fct = percent low gravity solids in system Fcop = percent total low gravity solids desired Fca = percent low gravity solids bentonite and/or chemicals added in mud Example: Determine how much barrels of oil base mud to diluate total 2000 bbl of mud in system
from total LGS = 7 % to desired LGS of 3.5 %. The oil base mud has 2% of bentonite slurry. Vwm = Vm x (Fct – Fcop) ÷ (Fcop – Fca) Vwm = 2000 x (7 – 3.5) ÷ (3.5-2) Vwm = 4667 bbl In order to dilute total of 2000 bbl of the original mud with 7% LGS down to 3.5% LGS, 4667 bbl of mud that has 2% bentonite is requied to add into the system. Please find the excel sheet used to calculate how much barrel of drilling fluid to control Low Gravity Solid (LGS) in mud system.
Establish Circulation in Driller’s Method Step – 1 You can read previous about driller’s method here!!! Today, I post about 1st step of establishing circulation in driller’s method, bring the pumps up by holding casing pressure constant. The idea of holding casing pressure constant while bring up pumps is to maintain constant bottom hole pressure. Bring pump up to circulating rate, typically about 2-5 BPM, by holding constant casing pressure. The reason why we need to hold constant casing pressure is to maintain constant bottom hole pressure. Let’s me explain more by showing you some equations. Note: Acronyms are listed below; BHP = Bottom Hole Pressure HP = Hydrostatic Pressure CP = Casing Pressure FrP = Frictional Pressure At static condition: BHP = HP in the annulus + CP
At dynamic condition: BHP = HP in annulus + CP + FrP In the dynamic environment, if we pump as slowly as possible, FrP can be ignored. The equation above tells us that when you hold CP constant, the BHP will be maintained the same. After you bring pump to kill rate, you will get circulating pressure called Initial Circulating Pressure (ICP). ICP is summation of shut in drill pipe pressure (SIDPP) and pressure to overcome friction called Slow Circulating Rate Pressure (SCR pressure). Hence, we can write the relationship in term of equation below. ICP = SIDPP + SCR pressure SCR pressure = ICP – SIDPP Note: Kill rate is normally about 2-5 BPM. Before performing this operation, you must ensure these following items; 1. Ensure that team members know their role and responsibility. You should have a pre job safety meeting before killing operation. 2. Eliminate all ignition sources that are close to the rig and vent lines of mud-gas separator. 3. Ensure that a circulating system is lined up properly. 4. Zero strokes counter and record time every activity. Circulate Out The Influx Holding Drill Pipe Pressure Constant by DRILLINGFORMULAS.COM on OCTOBER 24, 2010
After the pumps are brought up to desired kill rate and drill pipe pressure stabilize, personnel must observe and record the drillpipe pressure. For the first circulation, you must hold drill pipe pressure constant in order to maintain constant bottom hole pressure. To achieve maintain drill pipe pressure constant, personnel must manipulate the choke while circulating.
When gas in drilling fluid is circulated ci rculated to the surface, the gas will naturally begin to expand because of decrease in pressure. The expansion of gas in mud will result in increasing both pit volume and casing pressure. This time is the most critical period of the well control operation. If personnel panic about it, the operation could be turned out from a good operation to a disaster. Sometimes, you may have difficulty to bleed the gas off fast enough to keep k eep the drill pipe pressure within required limits. As you know, excessive drill pipe pressure can result in formation breakdown. If you cannot release gas fast enough from the annulus to prevent an increase in drill pipe pressure, you must show down pump rate to compensate the pressure. Shut Down Pumps and Weight Up Mud in Driller’s Method After kick has been been circulated out of the well, the mud pumps can be shut down down and the well must be secured. While shutting down the pumps, it is a good practice to gradually close the choke instead of suddenly shut in. You must keep in mind that while w hile shutting down pumps, you must keep casing pressure constant achieved by manipulating the choke. This procedure is to ensure that constant bottom
hole pressure is maintained during the shutdown. The shut-in casing pressure and the shut-in drill pipe pressure should be equal after complete the first circulation of the driller’s method. After method. After shutdown shutdown pumps, the Shut Shut In Casing Pressure Pressure (SICP) and the Shut In Drill pipe Pressure (SIDP) should be equal to the initial shut-in drill pipe
pressure observed at the first time. If SICP and SIDP are the same but they are more than the initial shut-in drill pipe pressure, there is possibly trapped pressure on top of SICP. If you see that the casing pressure is still higher than the drillpipe pressure, this situation means there is still some kick in the annulus or another kick was possibly taken while circulating. If you see this situation, you must do an additional circulation to ensure that there is no influx left in the well before kill weight fluid is mixed and pumped. After you ensure ensure that there is no no influx in the well, well, you need need to weight up the the active pits to desired desired kill weight fluid. Kill weight fluid is calculated by the following equation. Kill mud weight = original mud weight + (Initial Shut In Drill Pipe Pressure ÷ (0.052 x TVD of the well)
The ideal condition is to maintain a reasonab reasonably ly low active volume because when the mud is circulated out of the hole, you will have room to weight up without having to stop circulating. At least, you should have enough volume to displace entire volume with kill weight mud. Circulate Kill Mud – Mud – 2nd Circulation of Driller’s Method Once you finish weighing up your mud system to required kill mud weight, you need to do the 2 nd circulation of driller’s method. This post will describe how to do the 2nd circulation of driller’s method. The second circulation of the driller’s method will be started after drilling fluid is weighted-up weighted-up to required kill weight. First, when you establish the desired pump rate you must hold casing pressure constant while bringing the pump up to speed, killing rate +/- 2-5 bpm. Please always hold this pump rate constant throughout the killing process. In order to hole casing pressure constant as the kill mud goes down the drill string, you must manipulate choke. The casing pressure will be held constant until kill mud goes down to the bit. At this stage, you need to know how many strokes from surface to the bit by calculating the drill pipe capacity. Read more about annular capacity calculation and inner capacity calculation Once the kill mud reaches the bit, you must hold this drill pipe pressure constant throughout throughout the remainder of the kill operation. Then you still need to continue circulation until the hole is full of kill mud. You can estimate how many strokes and volumes based on the estimated hole size.At this stage, you will see decreasing in casing pressure. Practically, you must check mud weight out to confirm that you have good kill mud all way around. For example, if you circulate total of hole volume all way around but you don’t get the desired kill weight up completely out of hole, you need to continue circulating until good kill mud all way around prior to shutting down pumps..
Shut Down And Perform Flow Check – Check – Last Last Step of Driller ’s ’s Method The mud pumps can be shut down after the total volume of the well has been displaced with kill mud. Practically, you need to check mud weight out several times to ensure that the mud weight out equates to the kill weight mud. Otherwise you may have misinterpretation once the well is shut in and flow checked. Once shutting down the mud pumps, the choke should be gradually closed in order to hold casing pressure constant. The drill pipe pressure will be slowly dropped to zero as the pump speed is reduced. Please always remember every time that you either bring the pumps up to speed or slow down pump speed, you must hold casing pressure constant. After the well is shut-in, shut-in, both the drill drill pipe pressure pressure and casing casing pressure should should be reading reading zero. Typically, you may see any trapped pressure that you account for any pressure safety factor while circulating. You may consider trying to bleed off trapped pressure pressure and observe if there is pressure built up. If there is no pressure built up, you must confirm that the well is dead by opening the choke and checking checking well via trip tank. At this stage, if the well is totally killed, you must not see any increases in the trip tank. Once you confirm that the well is dead, the BOPs can be opened. I would like to remind you that a small gas volume may be trapped between the choke line and the BOP. Please make sure that everybody is cleared from the rig floor before opening up the BOP. Once the BOP is opened, you probably need to circulate and condition the mud in order to obtain the desired mud properties. For example, if the yield point is too high, it will cause swabbing effect while pulling out of hole and it could lead to another kick. In order to prepare for a trip after conditioning the mud, you may raise the mud weight to an acceptable “trip margin”. Note: This is just only guide line for well control. Before you do any well control operation, please contact your supervisor and make good agreement about the forward plan. Kick Tolerance Concept and Calculation for Well Design Kick tolerance is the maximum gas volume for a given degree of underbalance which the circulation can be performed without exceeding the weakest formation in the wellbore. This article is the extended version of Kick Tolerance Calculation which will explain more on this topic. It is very critical that drilling personnel understand its importance to well design and drilling operation. There are two important factors used for determining the kick tolerance • Kick Intensity – – It It is the different between the maximum anticipated formation pressure and
planned mud weight. For example, the planned mud weight is 13.0 ppg and the possible kick pressure is 13.5 ppg. Therefore, the kick intensity is 0.5 ppg (13.5 – (13.5 – 13.0). 13.0). A zero kick intensity intensity (swabbed kick scenario) should should be used used for a know area area where you you have less uncertainty about an overpressure zone. • Kick Volume – – It It is a gas influx entering into the wellbore from the formation. Gas Gas kick is
always used for well control calculation because it is the worst case scenario. The kick volume should be realistic figure which personal can detect the influx on the rig. In a larger hole, it allows bigger influx volume than a small hole.
Maximum Allowable Annular Surface Pressure (MAASP) and Kick Tolerance
Weakest formation point in the open hole is assumed to be at the shoe depth of the previous casing. The well bore will be fractured if a summation of hydrostatic and surface pressure exceeds the weakest pressure (Leak Off Test pressure). The maximum surface pressure before breaking the formation is called “Maximum Allowable Shut In Casing Pressure” (MASICP). Make it simpler for your understanding. MASICP is the total of kick tolerance budget. It consists of pressure from kick intensity and hydrostatic pressure loss due to gas. Kick Tolerance Example Calculation
Previous casing shoe (9-5/8” casing) at 6,000’ MD/ 6,000’ TVD Predicted formation pressure at TD (10,000’MD/10,000’TVD) = 14.0 ppg Pore pressure uncertainty = 1.0 ppg Planned mud weight = 14.5 ppg (0.754 psi/ft) Gas gradient = 0.1 psi/ft LOT = 16.0 ppg Hole size = 8-1/2” Drill Pipe = 5” BHA + Drill Collar = 7” Length of BHA+Drill Collar = 400 ft Annular capacity between open hole and BHA = 0.0226 bbl/ft Annular capacity between open hole and 5” DP = 0.0459 bbl/ft
Calculation Steps
Maximum anticipated pressure = 14.0 + 1 = 15.0 ppg Maximum Allowable Shut In Casing Pressure (MASICP) = (LOT – MW) x 0.052 x Shoe TVD Maximum Allowable Shut In Casing Pressure (MASICP) = (16 – 14.5) x 0.052 x 6,000 = 468 psi Kick Intensity = 15.0 – 14.5 = 0.5 ppg Underbalance due to kick intensity = 0.5 x 0.052 x 10,000 = 260 psi As you can see, when the well is in underbalance condition (260 psi), the shoe will not be broken because the MASICP is more than underbalance pressure (468 > 260). We know that 0.5 ppg kick intensity we will have 208 psi (468 – 260 = 208 psi) before shoe broken. It means that gas bubble can replace mud in equivalent to 208 psi before fracturing the shoe. With this relationship, we can determine height of gas kick by the following equation. Height of gas kick = remaining pressure, psi ÷ (mud gradient, psi/ft – gas gradient, psi/ft) Height of gas kick = 208 ÷ (0.754 – 0.1) = 318 ft. Determine gas kick volume base on height of gas kick
We need to separate into two cases and compare the smallest volume.
Gas at the bottom
1st case –
Volume of gas kick = Annular capacity between open hole and BHA x Height of gas kick Volume of gas kick (bbl) = 0.0226 bbl/ft x 318 ft = 7.2 bbl
2nd case – Gas right below casing shoe
For this case, we need to convert gas at the shoe to the bottom condition by applying Boyle’s Laws. Volume of gas kick = Annular capacity between open hole and 5” DP x Height of gas kick Volume of gas kick (bbl) = 0.0459 bbl/ft x 318 ft = 14.6 bbl
Convert to the bottom hole condition
Volume at the bottom = (volume of gas kick at shoe x Leak off test) ÷ formation pressure Leak off test = 0.052 x 16 x 6,000 = 4,992 psi Formation pressure (gas kick condition) = 0.052 x 15 x 10,000 = 7,800 psi Volume at the bottom = (14.6 x 4992) ÷ 7800 = 9.3 bbl We can compare the kick volume from two cases like this. 1 st case : kick volume = 3.9 bbl 2nd case : kick volume = 7.2 bbl The smallest number must be selected to represent maximum kick volume therefore kick volume is 7.2 bbl.
Let’s apply U-Tube concept
After learning about U-tube concept, let’s get a example in order to understand clearly about physical meaning of U-tube. This is very important concept so you need to clear about it. Mud weight inside drill pipe is 9.8 PPG is all the way to bit and mud weight in the annulus is 9.2 PPG all the way to surface. Hole depth is 10,000’MD/8500’TVD. The well is shut in and drill pipe pressure is equal to 0 psi. Determine casing pressure. According to U-tube concept, both sides (casing and drill pipe) have the same bottom hole pressure so we can write the equation to describe the U-tube concept as shown below; SP (casing) + HP (casing) = BHP = SP (drill pipe) + HP (drill pipe) At drill pipe side: BHP = 0 psi (Drill pipe Pressure) + 0.052×9.8×8,500 (Hydrostatic Pressure at drill
pipe side) = 4,331 psi At casing side: BHP = 4,331 psi = (Casing Pressure) + 0.052×9.2×8,500 (Hydrostatic Pressure at
casing) With this relationship (SP (casing) + HP (casing) = BHP = SP (drill pipe) + HP (drill pipe) ),we can solve casing pressure. 4331 = Casing Pressure + 4066 Casing Pressure = 4331 – 4066 = 265 psi
Oil Field Conversion Part 1 – Area, Circulation Rate, Impact Force Working in the oil filed, you may need to convert some unit values to another unit valves. I have some conversion unit specially used in the drilling and working over industry. I have 3 parts of the oil field conversion unit. This is the first part which is the conversion of Area, Circulation Rate, Impact Force. Square inches x 6.45 = Square centimeters Square inches x 645 = Square millimeters Square centimeters x 0.155 = Square inches Square millimeters x 0.00155 = Square inches Circulation Rate Barrels/min x 42 = Gallons/min Cubic feet/min x 0.000472 = Cubic meters/sec Cubic feet/min x 7.48 = Gallons/min Cubic feel/mm x 28.32 = Liters/min Cubic meters/sec x 15850 = Gallons/min Cubic meters/sec x 2118 = Cubic feet/min Cubic meters/sec x 60000 = Litres/min Gallons/min x 0.0238 = Barrels/ruin Gallons/min x 0.134 = Cubic feet/min Gallons/min x 3.79 = Litres/min Gallons/min x 0.00006309 = Cubic meters/sec Litres/min x 0.00001667 = Cubic meters/sec Litres/min x 0.0353 = Cubic feet/min Litres/min x 0.264 = Gallons/min Impact Force Pounds x 0.0000445 = Dynes Pounds x 0.454 = Kilograms Pounds x 4.448 = Newtons Dynes x0.00000225 = Pounds Kilograms x 2.2 = Pounds Newtons x 0.2248 = Pounds
Oil Field Conversion Part 2 – Length,Mud Weight,Power The second part of unit conversion is the conversion for Length,Mud Weight and Power specially used in the oil field. Feet x 0.305 = Meters Inches x 25.4 = Millimeters
Inches x 2.54 = Centimeters Centimeters x 0.394 = Inches Millimeters x 0.03937 = Inches Meters x 3.281 = Feet Mud Weight Pounds/gallon x 7.48 = Pounds/cu ft Pounds/gallon x 0.12 = Specific gravity Pounds/gallon x 0.1198 = Grams/cu cm Grams/cu cm x 8.347 = Pounds/gallon Pounds/cu ft x 0.134 = Pounds/gallon Specific gravity x 8.34 = Pounds/gallon Power Horsepower x 1.014 = Horsepower (metric) Horsepower x 0.746 = Kilowatts Horsepower x 550 = Foot-pounds/sec Horsepower (metric) x 0.986 = Horsepower Horsepower (metric) x 542.5 = Foot-pounds/sec Kilowatts x 1.341 = Horsepower Foot pounds/sec x 0.00181 = Horsepower
Oil Field Coversion Part 3 Oil Field Conversion Part 3 – Pressure,Velocity,Volume,Weight The last part of unit conversion is the conversion for Pressure,Velocity, Volume and Weightspecially used in the oilfield. . Pressure Atmospheres x 14.696 = Pounds/sq inch Atmospheres x 1.033 = Kilograms/sq cm Atmospheres x 101300 = Pascals Kilograms/sq cm x 0.9678 = Atmospheres Kilograms/sq cm x 14.223 = Pounds/sq inch Kilograms/sq cm x 0.9678 = Atmospheres Pounds/sq inch x 0.068 = Atmospheres Pounds/sq inch x 0.0703 = Kilograms/sq cm Pounds/sq inch x 0.006894 = Pascals Velocity Feet/sec x 0.305 = Meters/sec
Feet/mm x 0.00508 = Meters/sec Meters/sec x 196.8 = Feet/mm Meters/sec x 3.28 = Feet/sec Volume Barrels x 42 = Gallons Cubic centimeters x 0.00003531 = Cubic feet Cubic centimeters x 0.06102 = Cubic inches Cubic centimeters x 0.000001 = Cubic meters Cubic centimeters x 0.000264 = Gallons Cubic centimeters x 0.001 = Litters Cubic feet x 28320 = Cubic centimeters Cubic feet x 1728 = Cubic inches Cubic feet x 0.02832 = Cubic meters Cubic feet x 7.48 = Gallons Cubic feet x 28.32 = Litters Cubic inches x 16.39 = Cubic centimeters Cubic inches x 0.0005787 = Cubic feet Cubic inches x 0.00001639 = Cubic meters Cubic inches x 0.004329 = Gallons Cubic inches x 0.01639 = Liters Cubic meters x 1000000 = Cubic centimeters Cubic meters x 35.31 = Cubic feet Cubic meters x 264.2 = Gallons Gallons x 0.0238 = Barrels Gallons x 3785 = Cubic centimeters Gallons x 0.1337 = Cubic feet Gallons x 231 = Cubic inches Gallons x 0.003785 = Cubic meters Gallons x 3.785 = Liters Weight Pounds x 0.0004535 = Tons (metric) Tons (metric) x 2205 = Pounds Tons (metric) x 1000 = Kilograms
Kick Tolerance Concept and Calculation for Well Design Kick tolerance is the maximum gas volume for a given degree of underbalance which the circulation can be performed without exceeding the weakest formation in the wellbore. This article is the extended version
of Kick Tolerance Calculation which will explain more on this topic. It is very critical that drilling personnel understand its importance to well design and drilling operation. There are two important factors used for determining the kick tolerance • Kick Intensity – It is the different between the maximum anticipated formation pressure and planned
mud weight. For example, the planned mud weight is 13.0 ppg and the possible kick pressure is 13.5 ppg. Therefore, the kick intensity is 0.5 ppg (13.5 – 13.0). A zero kick intensity (swabbed kick scenario) should be used for a know area where you have less uncertainty about an overpressure zone. • Kick Volume – It is a gas influx entering into the wellbore from the formation. Gas kick is always used
for well control calculation because it is the worst case scenario. The kick volume should be realistic figure which personal can detect the influx on the rig. In a larger hole, it allows bigger influx volume than a small hole. Maximum Allowable Annular Surface Pressure (MAASP) and Kick Tolerance
Weakest formation point in the open hole is assumed to be at the shoe depth of the previous casing. The well bore will be fractured if a summation of hydrostatic and surface pressure exceeds the weakest pressure (Leak Off Test pressure). The maximum surface pressure before breaking the formation is called “Maximum Allowable Shut In Casing Pressure” (MASICP). Make it simpler for your understanding. MASICP is the total of kick tolerance budget. It consists of pressure from kick intensity and hydrostatic pressure loss due to gas. Kick Tolerance Example Calculation
Previous casing shoe (9-5/8” casing) at 6,000’ MD/ 6,000’ TVD Predicted formation pressure at TD (10,000’MD/10,000’TVD) = 14.0 ppg Pore pressure uncertainty = 1.0 ppg Planned mud weight = 14.5 ppg (0.754 psi/ft) Gas gradient = 0.1 psi/ft LOT = 16.0 ppg Hole size = 8-1/2” Drill Pipe = 5” BHA + Drill Collar = 7” Length of BHA+Drill Collar = 400 ft Annular capacity between open hole and BHA = 0.0226 bbl/ft
Annular capacity between open hole and 5” DP = 0.0459 bbl/ft
Calculation Steps Maximum anticipated pressure = 14.0 + 1 = 15.0 ppg Maximum Allowable Shut In Casing Pressure (MASICP) = (LOT – MW) x 0.052 x Shoe TVD Maximum Allowable Shut In Casing Pressure (MASICP) = (16 – 14.5) x 0.052 x 6,000 = 468 psi Kick Intensity = 15.0 – 14.5 = 0.5 ppg Underbalance due to kick intensity = 0.5 x 0.052 x 10,000 = 260 psi As you can see, when the well is in underbalance condition (260 psi), the shoe will not be broken because the MASICP is more than underbalance pressure (468 > 260). We know that 0.5 ppg kick intensity we will have 208 psi (468 – 260 = 208 psi) before shoe broken. It means that gas bubble can replace mud in equivalent to 208 psi before fracturing the shoe. With this
.
relationship, we can determine height of gas kick by the following equation
Height of gas kick = remaining pressure, psi ÷ (mud gradient, psi/ft – gas gradient, psi/ft) Height of gas kick = 208 ÷ (0.754 – 0.1) = 318 ft. Determine gas kick volume base on height of gas kick
We need to separate into two cases and compare the smallest volume.
What does the negative vertical section mean? by DRILLINGFORMULAS.COM on SEPTEMBER 24, 2009
Vertical Section is the horizontal distance of wellbore that moves in the direction of the target per each station or in total. For instance, in the figure below, vertical section is the distance from survey to survey point and it’s measured in the same direction of the vertical section direction.
The two factors that affect vertical section are as follows: 1. The Incremental horizontal displacement (? HD) 2. Vertical section direction (VSD) is the azimuth that is used to reference to the vertical section. Normally, VSD is the azimuth of the last target. The simple mathematics as Average Angle Method calculation demonstrates the relationship of the VS as below:
VS = cos (VSD – Az avg) X ?HD VS: Vertical Section VSD: Vertical Section Direction Az avg: Average Azimuth between 2 points (Az1 + Az2) ÷2 ?HD: Delta Horizontal Displacement In order to get the Positive Vertical Section or Zero Vertical Section, a well path must have difference of angle between VSD and Az avg, (VSD – Az avg), within a range of +90 to 90 degree. On the other hands, the negative Vertical Section can occur because the difference of angle between VSD and A zavg, (VSD – Az avg), is out of range of +90 to 90 degree AZI.
Barrels of slug required for desired length of dry pipe by DRILLINGFORMULAS.COM on SEPTEMBER 27, 2009
What is slug? Slug: It is heavy mud which is used to push lighter mud weight down before pulling drill pipe out of hole. Slug is used when pipe became wet while pulling out of hole. Normally, 1.5 to 2 PPG over current mud weight is a rule of thumb to decide how much weight of sl ug should be. For example, current mud weight is 10 PPG. Slug weight should be about 11.5 to 12 PPG. Generally, s lug is pumped to push mud down approximate 200 ft and slug volume can be calculated by applying a concept of U -tube (See Figure below).
Volume of slug required for required length of dry pipe can be calculated by this following equations: Step 1: Determine hydrostatic pressure required to give desired drop inside drill pipe: Hydrostatic Pressure in psi = mud weight in ppg x 0.052 x ft of dry pipe Step 2: Determine difference in pressure gradient b etween slug weight and mud weight: Pressure gradient difference in psi/ft = (slug weight in ppg – mud weight in ppg) x 0.052
Step 3: Determine length of slug in drill pipe: Slug length in ft = Hydrostatic Pressure in psi (in step 1) ÷ Pressure gradient difference in psi/ft (step 2) Step 4 Slug volume required in barrels: Slug volume in barrel = Slug length in ft x drill pipe capacity in bbl/ft Example: Determine the barrels of slug required for the following: Desired length of dry pipe = 200 ft
Drill pipe capacity = 0.016 bbl/ft
Mud weight = 10.0 ppg
Slug weight = 11.5 ppg
Step 1 Hydrostatic pressure required: Hydrostatic Prssure in psi = 10.0 ppg x 0.052 x 200 ft Hydrostatic Prssure in psi = 104 psi
Step 2 differences in pressure gradient between slug weight and mud weight: Pressure gradient difference in psi/ft = (11.5 ppg – 10.5 ppg) x 0.052
Pressure gradient difference in psi/ft = 0.078 psi/ft
Step 3 length of slug in drill pipe: Slug length in ft = 104psi ÷ 0.078 Slug length in ft = 1,333 ft
Step 4 Slug volume required in barrels: Slug volume required = 1333 ft x 0.016 bbl/ft Slug volume required = 21.3 bbl
Well Control Formulas Part 1 by DRILLINGFORMULAS.COM on SEPTEMBER 16, 2010
I would like to share with you about well control formulas that might be advantageous for you in the future. I seperate into several parts for you to easy to follow.
Before going into all calculations, I would like to emphasize about rounding rules that we will use for well control calculation.
1. Kill Mud Density: We must round up to one decimal place from a calculated kill mud density. For example, if we have the calculated kill mud density of 13.32 ppg, we will round it up to 13.4 ppg.
2. Leak Off Test (LOT): We must round down to one decimal place from a calculated Leak Off Test value. For example if we have the theoretical LOT of 15.57 ppg, we will round down to 15.5 ppg. When any of the above values have been calculated, the rounded numbers must be used in subsequent calculations.
Well Control Course Equations Part 1 Pressure (P) – psi Pressure (psi) = Force (lb) / Area in Square Inch (in 2) Pressure Gradient (G) – psi/ft Mud Gradient ( Psi/ft ) = Mud weight ( PPG) x 0.052 Hydrostatic Pressure (HP) – psi
Hydrostatic Pressure (HP) = Mud weight (PPG) x 0.052 x TVD (ft) You may have seen this triangle before but I need to emphasize on this because it will let you see all relationship of the
.
hydrostatic pressure
If you want to solve for MW or TVD, fill in the k nown information in these equations below;
Bottom Hole Pressure (BHP) – psi Under static condition Bottom Hole Pressure (BHP) = Hydrostatic Pressure (HP) + Surface Pressure (SP)
Under dynamic condition, use the following equation. Bottom Hole Pressure (BHP) = Hydrostatic Pressure (HP) + Surface Pressure (SP) + Frictional Pressure (FrP)
Note: Frictional pressure acts opposite way of flow direction. Formation Pressure (FP) – psi After get Shut In Drill Pipe Pressure, you can calculate the formation pressure from this following relationship;
Formation Pressure (FP) = Hydrostatic Pressure (HP) + Shut-In Drill Pipe Pressure (SIDPP)
Well Control Formulas Part 2
Equivalent Circulating Density (ECD) , ppg Equivalent Circulating Density (ECD) ,ppg = (annular pressure loss, psi) ÷ 0.052 ÷ true vertical depth (TVD), ft + (current mud weight, ppg)
Leak-off Test Equivalent Mud Weight (LOT), ppg Leak off test (ppg) = (Leak off test pressure in psi) ÷ 0.052 ÷ (Casing Shoe TVD in ft) + (Mud Weight used for LOT in ppg)
Maximum Initial Shut-In Casing Pressure (MISICP), psi This calculation is based on shoe fracture which is equal to Leak Off Test Pressure. MISICP (psi) = [LOT (ppg) – Current Mud Weight (ppg)] x 0.052 x Shoe TVD (ft)
Kill Mud Weight to Balance Formation (KMW), ppg KWM (ppg) = [Shut In Drill Pipe Pressure (SIDP), psi ÷ (0.052x True Vertical Depth (TVD) of the well, ft)] + Original Mud Weight (ppg)
Slow Circulation Rate (SCR), psi SCR (psi) = Initial Circulating Pressure (psi) – Shut In Drill Pipe Pressure (psi)
Well Control Formulas Part 3
Annulus Capacity Factor (ACF),bbl/ft
Final Circulating Pressure (FCP), psi Surface To Bit Strokes, strokes
Circulating Time, mins
Capacity Factor (CF), bbl/ft
Opened End Pipe Displacement, bbl/ft Closed end pipe displacement, bbl/ft
Well Control Formulas Part 4
Well control formulas part 4 consists of Height of Influx, rate of gas migration, Barite Requirement For Weight-up ,Volume Gain From Slug, Triplex Pump Output, Pump Output, Pump Pressure With New Pump Strokes, and Boyle’s Law
Height of Influx, ft
Approximate gas migration rate, ft/hr
Sacks of Barite Required For Weight-up, sx
Volume Gain From Slug, bbl
Triplex Pump Output (volume), bbl/stroke
Pump Output, bbl/min New Pump Pressure With New Pump Strokes, psi
Boyle’s Law – Gas Pressure and Volume Relationship
Well Control Formulas Part 5 This part of well control formula series (part#5) will show you following equations: mud increment for volumetric, lube increment for lubricate and bleed, bottle capacity required for koomey unit, volume of usable fluid, and snubbing force for snubbing operation. Later on, I will show you how to apply equations to particular situation. Anyway this is part 5 and total will be 8 parts.
Mud Increment for Volumetric Method (MI), bbl Lube Increment for Lubricate and Bleed Method (LI), bbl
Bottle Capacity Required, gal
Volume of Usable Fluid, gal
Snubbing force for snubbing operation Snubbing Force (SF) = Force at wellhead (Fp) + Frictional Force – Buoyed weight of string(Wb) Basically, you can simply think l ike this. Total force to overcome pressure at wellbore is a summation of force at wellhead and frictional force minus buoyed weight of string.
Force at wellhead (Fp) can be determined by one of following equations.
OR
Well Control Formulas Part 6
This part of well control formulas will demonstrate you more about s ome equations frequently used in snubbing operation. In Well Control Formulas Part 5 , I show just only some snubbing formulas and this part will show the rest of them.
Buoyed Weight of Open Ended Tubulars (Wb),lb For this formula, you just use the buoyancy factor and multiply it with weight of pipe in the air.
Buoyed Weight of Closed Ended Tubulars without fluid in the pipe (Wb),lb This formula below is different from the 1st formula because it is used for the closed ended pipe. W eight in the air will be subtracted with buoyancy weight of pipe ran in hole.
Note: 24.5 is conversion factor to make the unit in gallon.
Buoyed Weight of Closed Ended Tubulars after filling the pipe (Wb),lb -> in this case, there is different fluid weight in pipe and annular
The Balance Point for closed ended and unfilled pipe is the point where the weight of pipe in the fluid equates to force created by wellhead pressure.
Note: OR
This is the second case for balance point calculation. The Balance Point for closed ended pipe and the pipe is filled with fluid.
Maximum Down Force on Jacks Effective Area of Snubbing Jacks, square inch Hydraulic Pressure to Snub, psi
Oil Field Abbreviation Mostly Used in the Rig This is may not relate to drilling formula but it may be good for new people to k now about oil field abbreviations. If you have more than what I have, please feel free to add more by putting in the blog c omment.
ACF – Annular Capacity Factor
AV – Annular Velocity
BF – Buoyancy Factor
BHA – Bottom Hole Assembly
BHP – Bottom Hole Pressure
BOP – Blow Out Preventor
BOPE – Blow Out Preventer Equipment
BPUTS – Bring Pumps Up To Speed
CC – Circulate and Condition mud
CLF – Choke Line Friction
CMW – Current Mud Weight
CP – Casing Pressure
DC – Drill Collar
Dh – Diameter of hole in inches
DP – Drill Pipe
DPP – Drill Pipe Pressure
ECD – Equivilant Circulating Density
EOB – End of Build
ESP – Estimated Stuck Point or Electical Submersible Pump
FCP – Final Circulating Pressure
FD – Fluid Density
FIT – formation integrity test
FOSV – Full Opening Safety Valve
FP – Formation Pressure
FrP – Friction Pressure
FV – Funnel Viscosity
GPM – Gallons Per Minute
HHP – Hydraulic Horse Power
HP – Hydrostatic Pressure
IBOP – Inside Blow Out Preventer
ICP – Initial Circulating Pressure
ISICP – Initial Shut-in Casing Pressure
KLF – Kill Line Friction
KMW – Kill Mud Weight
KOP – Kick Off Point
Lbs. – Pounds
LC – Lost Circulation
LCM – Lost Circulation Material
Len – Length in feet
LOT – Leak Off Test
MAASP – Maximum Allowable Annular Surface Pressure
MASP – Maximum Anticipated Surface Pressure
MD – Measured Depth
MGS – Mud Gas Separator
MI – Mud Increment
MISICP – Maximum Initial Shut-in Casing Pressure
MOP – Margin of Over Pull
MW – Mud Weight in ppg
NP – Neutral Point
OBM – Oil Based Mud
OMW – Original Mud Weight
OPT – Optimum
PG – Pressure Gradient
PI – Pressure Increment
POH – Pull Out Hole
PP – Pore Pressure
PPG – Pounds Per Gallon
RIH – Run In Hole
ROH – Run Out Of Hole
RPM – Rounds Per Minute
RSS- Rotary Steerible System
SCR – Slow Circulating Rate
SG – Specific Gravity
SICP – Shut-in Casing Pressure
SIDPP – Shut-in Drill Pipe Pressure
SOBM – Synthetic Oil Based Mud
SP – Surface Pressure
SPM – Strokes Per Minute
SPM Valve – Side Pocket Mandrel Valve
SPR – Slow Pump Rate
TDS – Top Drive System
TIH – Trip In Hole
TOC – Top Of Cement
TOF – Top Of Fish
TOH or TOOH – Trip Out Of Hole
TOL – Top Of Liner
TVD – True Vertical Depth
WL – Water Loss or Wire Line
WOB – Weight On Bit
WOC – Wait On Cement
WOO – Wait On Orders
WOW – Wait On Weather
YP – Yield Point
What factors must be considered when designing a casing/tubing string? Casing and tubing selection are one of the critical tasks that engineers must carefully decide which type of casing/tubing will be used in the wellbore in order to meet the objective of each well. I would like to share my knowledge about the selection criteria for casing/tubing string design.
Oilfield Tubing
The factors must be contemplated when designing a casing and/or tubing string as listed below;
• Reservoir fluid type (oil, gas, or combine) • Depth of casing and tubing string
• Formation Pressure gradient and fracture gradient • Reser voir temperature • How much reserves of reservoir • How long of production life of wells • Economic consideration • Strategy of completion technique as conventional completion, monobore completion, monobore horizontal completion, etc. • Production plan as production rate, how plateau rate be maintained, secondary recovery plan, etc. • Bottom hole reservoir pressure and expected s urface pressure during future production plan • Level of sour gas as H2S and CO2 • Hydrocarbon zones are required to be c overed by cement • Tubing size needed to achieve production and stimulation plan • Artificial lift equipment requirements • Future workover plan • Physical property of material • Clearances needed for fishing • Type of connection
Weight of slug required for desired length of dry pipe with set volume of slug You can determine how much slug weight required in order to achieve desired length of dry pipe with certain slug volume that you will use.
Please follow these steps of calculation below;
Step 1 Determine Length of slug in drill pipe in ft: Length of slug in drill pipe in ft = s lug volume in bbl ÷ drill pipe capacity in bbl/ft
Step 2 Determine hydrostatic pressure required to give desired dry pipe drill pipe: Hydrostatic Pressure in psi = mud weight in ppg x 0.052 x desired length of dry pipe
Step 3 Determine slug weight needed in ppg: Slug weight in ppg = (Hydrostatic Prssure (from step 2) ÷ 0.052 ÷ Length of slug in ft (step1)) + mud weight, ppg, in hole
Example: Determine slug weight required for the following data: Desired length of dry pipe = 200 ft Mud weight in hole = 12.0 ppg Drill pipe capacity = 0.016 bbl/ft Volume of slug = 20 bbl
Step 1 – Determine Length of slug inside drill pipe in ft: Slug length = 20 bbl ÷ 0.016 Slug length = 1250 ft
Step 2 – Determine hydrostatic pressure required to give desired dry pipe drill pipe Hydrostatic Pressure in psi = 12.0 x 0.052 x 200 Hydrostatic Pressure in psi = 124.8 psi
Step 3 – Determine slug weight needed in ppg: Slug weight in ppg = (124.8 ÷ 0.052 ÷ 1250) + 12.0
Slug weight in ppg = 13.92 ppg Please find the excel sheet used to calculate Weight of slug required for a desired length of dry pipe with a set volume of slug.
Pipe Displacement Calculation
Pipe displacement, normally in bbl/ft, is steel volume to displace fluid volume. When we either pull out of hole or trip in hole for any kind of pipes such as drill pipe, casing or tubing, you should know how much fluid to displace steel volume. For example, when we pull out of hole, a trip sheet must be monitored all time. We must know how much fluid will fill the hole each stand of drill pipe pulled out. If the volume of displacement less than theoretical displacement value, we may have problem due to swabbing formation into wellbore.
This post will demonstrate how to calculate plain pipe displacement with this following formula:
Pipe Displacement in bbl/ft = (OD in2 – ID in2 ) ÷ 1029.4
Where, OD is out side diameter of pipe in inch. ID is inside diameter of pipe in inch. This formula is good for plain pipe diplacment such as casing and tubing. It’s not accurate enough for drill pipe because this formula does not account for tool joint di splacement therefore you need drill pipe specification sheet for its displacement.
Example: Determine pipe displacement in bbl/ft of 9-5/8” casing 40 ppf, OD = 9.625 in, ID = 8.835 in Pipe Displacement of 9-5/8” casing 40 ppf in bbl/ft = (9.6252 – 8.8352 ) ÷1029.4 Pipe Displacement of 9-5/8” casing 40 ppf in bbl/ft = 0.01417 bbl/ft
How are pressure and pit volume doing during the first circulation of the driller’s method?
When we perform the first circulation of driller’s method, the casing pressure will increase due to gas expansion and the maximum casing pressure will be observed when the gas influx reaches surface. When gas is moved upward during circulation, the gas will expand due to pressure decrease (refer toBoyle’s gas law P1V1 = P2V2). The higher gas is moved up inside annulus, the higher expansion will be. Therefore, the sys tem
hydrostatic pressure will be decreased. For this reason, the casing pressure will increase in order to maintain constant bottom hole pressure. Let take a look at the equation
Bottom hole pressure constant = Casing Pressure (increase to compensate for loss hydrostatic pressure) + Hydrostatic Pressure (decrease due to gas expansion). When the gas in the mud starts coming out on surface, the casing pressure will continually decrease. If the gas kick in the annulus is totally out of hole, casing pressure sh ould be equal to Shut-In Drillpipe Pressure (SIDPP). Casing pressure sometimes may be slightly more than SIDPP due to safety factor that you add while circulating. In addition, pit volume will increase until gas reaches surface due to gas expansion. When g as reaches surface, the pit volume will start to decrease. The plot below demonstrates pressure profile of both casing pressure and tubing pressure during 1st circulation of driller’s method.
Note: you need to understand that this article is based on the following assumptions; • Water base mud • Well bore influx (kick) = gas
Surge Pressure, Swab Pressure and Trip Margin You may have heard about Surge Pressure, Swab Pressure and Trip margin in the drilling business. Today, I would like to share my knowledge about these terminologies.
What is surge pressure? Surge Pressure: When pipe moves downward with mud c irculation through drill string, additional bottom hole pressure called “Surge Pressure” is created. If surge pressure is too much, many problems will occur as formation brake down, partial mud loss and lost circulation.
What is swab pressure? Swab Pressure: If a drill string , casing string or logging tool is being pulled out of hole too fast, due to bigger diameter almost same hole size, BHA/ bit, casi ng or logging tool will possibly swab mud out of hole, like pulling small a piston of syringe. For this reason, hydrostatic pressure of bottom hole will be reduced. Pressure reduction created by this situation is called “Swab Pressure”. If swab pressure is too much, kick (wellbore influx) may be into the hole and well control must be conducted in order to secure well.
What is Trip Margin? Trip Margin: It is an increase in the hydrostatic pressure of mud that compensates for the reduction of bottom pressure due to stop pumping and/or swabbing effect while pulling pipe out of hole. Trip Margin is calculated by following equation:
How do we calculate trim margin? The formula used to calculate trip margin is listed below;
Trip Margin (PPG) = (Margin needed (Psi) – Present Margin (Psi))/ (0.052xTVD (ft))
Cement Transition Period in The Oil Well Can Cause Well Control Situation
When cement is in transition period (forming the bond), you will lose some hydrostatic pressure because cement becomes solid phase therefore water in the cement will provide hydrostatic pressure. In many cases happened, there is no issue while performing the cement job however once the cement is set after period of time, there is a casing
.
pressure indicating that there is hydrocarbon in the annulus
This example will demonstrate you why the well is in underbalance condition while waiting on cement. Well information: Previous 9-5/8” casing shoe at 4000’ ft. The vertical well (8.5” hole) is drilled to TD at 10,000ft with 12.1 ppg mud and the pay zone is at 9,800’ TVD with reservoir pressure of 11.6 ppg. The cement is planned to cover 3,500 ft in the annulus above the casing shoe. Water used to mix cement is 8.3 ppg weight.
Will the well go underbalance during the cement in transition period? Formation pressure at 9,800 ft Formation pressure at 9,800 ft = 0.052 x 11.6 x 9800 = 5,911 psi
Total hydrostatic pressure in the annulus Hydrostatic pressure of drilling mud at 6,500 ft = 0.052 x 12.1 x 6,500 = 4,090 psi
When cement in transition period, only water in cement will provide hydrostatic pressure. So we can calculate hydrostatic pressure of water in cement Hydrostatic pressure of water in cement = 0.052 x (9800 – 6,500) x 8.3 = 1,424 psi While cement is in the transition period, total hydrostatic pressure in the annulus is equal to hydrostatic pressure of mud plus hydrostatic of water in cement Total hydrostatic pressure in the annulus = 4,090 + 1,424 = 5,514 psi
You will see that during the transition period total hydrostatic pressure in the annulus is less thanformation pressure therefore the well. For this case, the well will flow during transition period.
Amount of cuttings produced per foot of hole and total solid generate generated d After learning about capacity calculation, calculation, we can apply the capacity calculation to determine how much barrels of cutting produced per foot of hole drilled and total solid generated in pounds. Please read and understand the following formulas: Use formula#1 and #2 for #2 for calculating amount of cutting generated per feet drilled. drilled. Formula#1 for BARRELS of cuttings drilled per foot of hole drilled: Barrels of cutting per foot drilled = Dh 2 x (1 – (1 – % % porosity) ÷1029.4 Where: Dh is hole diameter in inch. Example: Determine barrels of cuttings drilled for one foot of 6-1/8 inch hole with 25% (0.25) porosity: Barrels/footage drilled = 6.1252 x (1 – (1 – 0.25) 0.25) ÷1029.4 Barrels/footage drilled = 0.02733 bbl/footage drilled Formula#2 for CUBIC FEET of cuttings drilled per foot of hole drilled: Cubic feet of cutting per foot drilled = Dh 2 x 0.7854 x (1 – (1 – % % porosity) ÷144 Where: Dh is hole diameter in inch. Example: Determine barrels of cuttings drilled for one foot of 6-1/8 inch hole with 25% (0.25) porosity Cubic feet/footage drilled = 6.125 2 x 0.7854 x (1 – (1 – 0.25) 0.25) ÷144 Cubic feet/footage drilled = 0.153462 cu ft/footage drilled Moreover, you also apply sample density and volume relationship to determine total solids generated. Use the following formula to calculate total solid generated.
Wcg = 350 x Ch x L x (l – (l – porosity) porosity) x Cutting density Where; Wcg = solids generated in pounds Ch = capacity of hole in bbl/ft
L = footage drilled in ft Cutting density = cutting density in gm/cc Example: Determine Example: Determine the total pounds of solids generated generated in drilling 100 ft of 6-1/8 inch hole (0.03644 bbl/ft). bbl/ft). Density of cuttings = 2.20 gm/cc. Porosity = 25%: Wcg = 350 x 0.03644 x 100 x (1 – (1 – 0.25) 0.25) x 2.2 Wcg = 2104.41 pounds
How To Determine Hole Size By Fluid Caliper This article will demonstrate you how to determine hole size by fluid caliper . First of all, you need to know what is the fluid caliper is. The fluid caliper is one si mple way to calculate hole diameter. The concept is based on hole volume, annular capacity, and inner capacity. You pump any substance and when you seen it on surface , you back calculate the hole size based on strokes pumped. It is quite tricky to explain so I would like you to see the example below which it will make you clear about what I say.
7” casing shoe is set at 5000’MD/4500’TVD 7” casing 23 ppf, ID 6.33 inch 4” drill pipe is used to drill the well and its ID is 3.34 inch. 4-3/4” 43/4” drill collar is used as BHA and its ID is 2.5 inch. The length of drill collar is 500 ft. This hole section is used water based mud and the bit size is 6- 1/8” Drill to section TD at 10,000’MD/9,000’TVD then drop carbide once TD is reached. Pump output is 0.1 bbl/stroke. Surface line from pumps to rig floor is 20 bbl. Carbide is detected by a gas sensor on surface after 4,000 strokes pump.
With the given information, determine what is the hole size of the open hole section.
. 1st step – step – Determine Determine Inner Capacity and Annular Capacity of All Parts The basic drilling formulas that you need to know are inner are inner capacity and annular and annular capacity calculation
Inner capacity of 4”DP
Inner capacity of 4”DP = 0.01084 bbl/ft
Inner capacity of 4-3/4”DC 4- 3/4”DC
Inner capacity of 4-3/4”DC 4-3/4”DC = 0.00607 bbl/ft
Annular capacity between 4” DP and 7” Casing
Annular capacity between 4” DP and 7” Casing = 0.02383 bbl/ft
I assign “d” is the open hole diameter. Annular capacity between 4” DP and open hole
Annular capacity between 4 3/4” DP and open hole
2nd step – step – Determine Determine Volume of All Parts
Volume in 4”DP = Inner capacity of 4”DP x length of 4” DP Volume Volume in 4”DP = 0.01084 x 9,500 = 103 bbl
Volume in 4-3/4”DC 4- 3/4”DC = Inner capacity of 44 -3/4”DC x length of 44 -3/4”DC Volume in 4-3/4”DC 4-3/4”DC = 0.00607 x 500 = 3 bbl
Volume between 4”DP and 7” Casing = Annular capacity between 4” DP and 7” Casing x length of 4” DP inside 7” casing Volume between 4”DP and 7” Casing = 0.02383 x 5,000 = 119 bbl
Volume between 4”DP and open hole = Annular capacity between 4” DP and open hole x length of 4” DP inside open hole
Volume between 4-3/4”DC 4-3/4”DC and open hole = Annular capacity between 44-3/4”DC 3/4”DC and open hole x length of 4-3/4”DC 4-3/4”DC inside open hole
3rd step – step – determine determine hole size. The total volume pump is equal to total volume in the system.
With the pump output of 0.1 bbl/stroke, 4000 strokes equate to 400 bbl.
In the following equation, I account for the s urface volume from the pump to the rig floor.
Solve the equation to get d, d is equal to 6.97”.
Answer: You will get the hole size based on the fluid caliper of 6.97 inch.
I wish this article will give you idea on how t o calculate hole size based on the fluid caliper.
Washout Drill Pipe Experience
I would like to share experience about washout drill pipe. We ob served pressure gradually dropped from 4,100 psi to 3,600 psi (500 psi pressure loss) with same pumping rate 250 GPM. There was no mud weight or mud properties change at that time. Then, we tried to switch to another pump but the same problem still occurred so there must be something wrong down hole or surface. When we observed pressure loss, we stopped rotating, j ust only circulating, and figured out where the washout was.
Note:
It’s a good practice not to rotate while we are losing pressure because we can snap drill pipe easily due to washout.
At this stage, when we saw the pressure loss, we need to know where pressure loss occurred.
1. Check surface equipment:
Closed IBOP, pressure up surface equipment with mud pump to 3000 psi and held for
5 mins. Everything was OK, no pressure loss. Therefore, there was nothing wrong with surface line and It should be down hole.
2. Check MWD signal:
You may not see the change in si gnal so you need to recycle pump to ensure whether signal is
good or not. We found that the signal generated by tool was weaken at the same flow rate of 240 GPM. This indication showed us that washout location was above MWD tool. We were pretty sure that we had washout drill pipe downhole and we decided to pull out of hole to find washout. This was what we found. Internal washout at pin end of drill p ipe resulted in pressure loss.
We laid down washout drill pipes and made up TDS and attempted to circulate with 240 GPM to see if pressure continued dropping. Pressure came back close to where it should be. Everything was OK then we ran back in hole to continue drilling operation. Pl ease remember that if you pull many stands of drill pipe before you see washout when you make up TDS and circulate pressure may not be like what you previously have.
Depth of Washout
Washout in drill string can cause big problem later such as parted drill string. When we see stand pipe pressure decrease without changing any parameters as flow rate, mud properties, etc, you may need to consider following items before you decide to pull out of hole for washout.
1. Check surface line: You may need to close stand pipe valves or IBOP and then pressure up to see leaking in the surface.
.
If you see pressure drop, you can fix the surface problem. Anyway you still need to test system again
2. Check drillstring: You may pump the same flow rate and s ee how your MWD tool down hole response. I f y MWD tool response gets weaker signal so it means that you have washout s omewhere above MWD tool. If not, you may have washout below that such as bit, mud motor, etc.
You may consider finding washo ut depth by using two following formulas listed below: Method 1: The concept of this method is to pump plugging material to plug the wash out. We will count how many strokes pump till pump pressure increases then we can calculate back where the washout is by applying internal capacity concept and pump output concept.
Depth of washout in ft= (strokes pumped till seeing pressure increase x pump output in bbl/stk) ÷ drill pipe capacity in bbl/ft Determine washout depth from following information:
Internal drill pipe capacity = 0.00742 bbl/ft Pump output = 0.0855 bbl/stk Pressure increase was noticed after 400 strokes.
Depth of washout, ft = 400 stk x 0.0855 bbl/stk ÷ 0.00742 bbl/ft Depth of washout = 4609 ft
Method 2: The concept of this method is to pump material that can be easily observed from drill pipe pass through wash out into annulus and over the surface. We can calculate the depth of washout bases on the combination volume of internal drill pipe volume and annulus volume. Note: The materials can be easily observed when it comes across the shakers are as follows: carbide, corn starch, glass beads, bright colored paint, etc.
Depth of washout in ft = (strokes pumped till observed material on surface x pump output in bbl/stk) ÷ (drill pipe capacity in bbl/ft + annular capacity in bbl/ft) Determine depth of washout from following information: Internal drill pipe capacity = 0.00742 bbl/ft Pump output = 0.0855 bbl/stk Annulus capacity = 0.0455 bbl/ft The material pumped down the drill pipe was noticed coming over the shaker after 2500 strokes. Depth of washout, ft = (2500 x 0.0855) ÷ (0.00742+0.0455) Depth of washout = 4039 ft If you want to subtract volume from bell nipple to shale shaker, you can subtract the volume out of total volume pumped. Therefore the formula will be
Depth of washout, ft = (strokes pumped till observed material on surface x pump output in bbl/stk – volume (bbl) from bell nipple to shale shaker) ÷ (drill pipe capacity in bbl/ft + annular capacity in bbl/ft) Example: Internal drill pipe capacity capacity = 0.00742 bbl/ft Pump output = 0.0855 bbl/stk Annulus capacity = 0.0455 bbl/ft The material pumped down the drill pipe was noticed coming over the shaker after 2500 strokes. Volume from bell nipple to shale shaker = 10 b bl Depth of washout in ft = (2500 x 0.0855 – 10) ÷ (0.00742+0.0455) Depth of washout = 3850 ft
ANYWAY PLEASE REMEMBER. If you know that your wash out is down hole, practically, we need to p ull out of hole ASAP after we determine washout situation. The more you pump, more washout will be occurred.
Hydrostatic Pressure (HP) Decrease When POOH
When pulling out of hole, volume of steel will be out of hole and mud volume will replace the steel volume. If we don’t fill hole, hydrostatic pressure will decrease. There are 2 cases of pulling pipe which are pull dry and pull wet. Each condition is different in calculation concept because mud volume to displace pipe volume is different. This topic shows you how to calculate hydrostatic pressure loss for both cases of pulling pipe, pull dry and pull wet. Moreover, there is the Excel sheet for calculating pressure decrease due to pulling out of hole.
Case#1: When pulling DRY pipe When pulling dry, we will consider volume of s teel out of hole only.
Step 1: Determine Total Pipe Volume
Step 2: Determine Hydrostatic Pressure Decrease
Example: Determine the hydrostatic pressure decrease when pulling DRY pipe out of the hole: Number of stands pulled = 10 Pipe displacement = 0.0055 bbl/ft Average length per stand = 91 ft Casing capacity = 0.0873 bbl/ft Mud weight = 12.0 ppg
Step 1: Determine of pipe displacement in Barrels = 10 stands x 91 ft/std x 0.0055 bbl/ft displaced Barrels displaced = 5.01 bbl
Step 2: Determine HP, psi decrease = 5.01 barrels x 0.052 x 12.0 ppg ÷ (0.0873 bbl/ft – 0.0055 bbl/ft) Hydrostatic pressure decrease = 38.2 psi
Case#2: When pulling WET pipe When pulling wet, we will consider volume of steel out of hole and volume of mud in drillpipe as well. Therefore, pulling wet will decrease hydrostatic more than pulling dry pipe.
Step 1:
Barrels displaced = number of stands pulled per stand in ft
x average length x {pipe disp inbbl/ft + {(% volume in drill pipe out of hole ÷ 100) x pipe cap in bbl/ft)}
Step 2:
Determine hydrostatic pressure in psi decrease = barrels displaced x 0.052 x
mud weight, ppg ÷ ((casing capacity in bbl/ft) – (Pipe disp in bbl/ft + pipe cap in bbl/ft)) Example: Determine the hydrostatic pressure decrease when pulling WET pipe out of the hole: % of volume in drill pipe out of hole = 100 Number of stands pulled = 10 Pipe displacement = 0.0055 bbl/ft Average length per stand = 91 ft Pipe capacity = 0.01876 bbl/ft Mud weight = 12.0 ppg Casing capacity = 0.0873 bbl/ft
Step 1: Barrels displaced = 10 stands x 91 ft/std x {(.0055 bbl/ft + (100 ÷ 100) x 0.01876 bbl/ft)} Barrels displaced = 22.08 bbl
Step 2: hydrostatic pressure in psi decrease = 22.0766 barrels x 0 .052 x 12.0 ppg ÷ ((0.0873 bbl/ft) – (0.0055 bbl/ft + 0.01876 bbl/ft)) HP decrease, psi = 218.52 psi
Calculate inner capacity of open hole/inside cylindrical objects
From the previous post, you learn how to calculate annular capacity and this post shows you how to use the same principle to calculate inner capacity of open hole / inside cylindrical objects such as tubulars, drill pipe, drill collars, tubing, casing etc.
There are several formulas to calculate inner capacity depending on unit of inner ca pacity required. Please read and understand the formulas below:
Formula#1) Calculate inner capacity in bbl/ft
Inner Capacity in bbl/ft = (ID in.) 2 ÷1029.4
Example: Determine inner capacity in bbl/ft of a 6-1/8 in. hole: Inner Capacity in bbl/ft = 6.1252÷1029.4 Inner Capacity in bbl/ft = 0. 0364 bb l/ft
Formula#2) Calculate inner capacity in ft/bbl
Example
: Determine inner capacity in ft/bbl of 6-1/8 in. hole:
Inner Capacity in ft/bbl = 1029.4 ÷ 6.1252 Inner Capacity in = 27.439 ft/bbl Inner Capacity in ft/bbl = 1029.4 ÷ (ID in.)
Formula#3) Calculate inner capacity in gal/ft
Inner Capacity in gal/ft = (ID in.) 2 ÷24.51
Example: Determine inner capacity in gal/ft of 6-1/8 in. hole: Inner Capacity in gal/ft = 6.1252÷ 24.51 Inner Capacity in = 1.53 gal/ft
Formula#4) Calculate inner capacity in ft/gal Inner Capacity in ft/gal = 24.51 ÷ (ID in.) 2 Example: Determine inner capacity in ft/gal of 6-1/8 in. hole: Inner Capacity in ft/gal = 24.51 ÷ 6.1252 Inner Capacity in ft/gal = 0.6533 ft/gal
Determine the volume of mud to fill up the inner of the cylindrical objects by the following equation. Inner Volume = Inner Capacity x Lenght Example: Inner capacity = 0. 0364 bbl/ft Length = 3000 ft
Volume = 0. 0364 x 3,000 = 109.2 bbl.
Post Shut-In Procedures while Drilling
There are several figures that must be recorded after the well has been properly shut in in case of a well control situation.
Shut-In Casing Pressure (SICP): Read and record the shut-in casing pressure (casing gauge).In order to get the proper pressure reading, the casing gauge should be installed upstream of the closed choke.
Shut-In Drillpipe Pressure (SIDP): Read and record the shut-in drillpipe pressure. You must remember that whether you have a float in drilling string or not.
If there is no a float is in the drills tring, the shut in drill pipe pressure can be read directly from the standpipe manifol d.
If there is a float in the drillstring, you need to bump the float i n order to determine the correct shut in drill pipe pressure. I will write about how to bump float to record the shut in drill pipe pressure later.
Time: Record the time that the well control situation is occurred and keep an accurate time log for the entire well kill operation
Closing Pressure: Record the closing pressure of BOP. In order to prevent well bore fluid leaking through BOP
.
elements, the closing pressure should be high enough
Pit Gain: Read and record the pit gain. Pit volume gained is very critical for the maximum casing pressure calculation. You should check the volume gained from mud logger and drill er in order to get the accurate figure. I don’t recommend you to ask only one person to get this fi gure. It is better to have another data source to compare with. After the well is properly secured and all information is gathered, the supervisor on the rig should inform his supervisor to find the proper method to kill the well.
Maximum pit gain from gas kick in water based mud In water based mud, you can not only estimate the maximum surface casing pressure, but you are also be able to determine the maximum pit gain due to gas influx. The following formula demonstrates how to figure out the maximum pit gain from gas influx in water based mud system.
Where
Maximum Pit Gain in bbl P is formation pressure in psi. V is original pit gain in bbl. C is annular capacity in bbl/ft. Kill Weight Mud in ppg Let’s take a look at this following example in order to get more understanding regarding this topic.
Drill well with water based mud.
Pit gain = 20 bbl
Initial shut in casing pressure = 600 psi
Initial shut in drill pipe pressure = 500 psi
Current mud weight = 12.5 ppg
Hole depth = 6,000’MD/4,800’TVD
Hole diameter = 12-1/4 inch
Drill pipe = 5 inch
According to the data, you need to figure out the Kill Mud Weight , formation pressure, and annular capacity.
Kill Weight Mud = current mud weight + (shut in drill pipe pressure ÷ (0.052 x TVD))
Kill Weight Mud = 12.5 + (500 ÷ (0.052 x 4800)) = 14.5 ppg
Note: Please read the following link about kill weight mud -> well control formulas Formation pressure = surface pressure + hydrostatic pressure
Formation pressure = 500 + (0.052 x 12.5 x 4800) = 3620 psi
Note: Please read the following link about formation pressure -> Formation Pressure from Kick Analysis
Determine annular capacity: Annular capacity = (12.252 – 52) ÷ 1029.4 = 0.1215 bbl/ft Note: if you would like to understand annular capacity, please check out the following links -> Annular Capacity
Once you get all parameters required, you can add all of them into the equation like this.
Maximum Pit Gain = 98.5 bbl
Volumetric Well Control – When It Will Be Used Volumetric well control method is a special well control method which will be used when the normal circulation cannot be done. It is not a kill method but it the method to control bottom hole pressure and allow influx to migrate without causing any damage to the well.
There are several situations where you cannot circulate the well as follows:
• Pumps broken down
• Plugged drill string/bit
• Drill string above the kick
• Drill string is out of the hole completely
With the volumetric method, the volume of gas influx will allow migrating and casing pressure will increase till a certain figure then a specific amount of mud will bleed off to compensate the increase in casing pressure. The volumetric method will allow the kick to surface while the bottom hole pressure is almost constant. Successful use of volumetric method requires personnel understand three basic concepts –
1. Boyle’s Law – Boyle’s law states that at constant temperature, the absolute pressure and the volume of a gas are inversely proportional in case of constant temperature within a closed system. The illustration below demonstrates volume and pressure as per Boyle’s Law.
In term of mathematical relationship, Boyle’s Law can be stated as
P1 x V1 = P2 x V1
Where;
P1 = pressure of gas at the first condition V1 = volume of gas at the first condition P2 = pressure of gas at the second condition V2 = volume of gas at the second condition 2. Hydrostatic pressure – Hydrostatic pressure is pressure created by column of fluid. Two factors affecting
hydrostatic pressure are height of fluid and density of fluid. Pressure at the bottom hole equals to hydrostatic pressure plus surface pressure
Pressure (bottom hole) = Hydrostatic Pressure + Surface Pressure
We will apply this concept to see how the gas bubble will increase the bottom hole pressure.
If the gas bubble is not allowed to expanded, the gas bubble in the well migrates up will act on the mud column below and increase bottom hole pressure. Increasing in the bottom hole pressure equates to hydrostatic pressure below the bubble.
Bottom hole pressure = Gas bubble pressure + Hydrostatic pressure below the bubble
If we don’t want increase in bottom hole pressure, mud need to be bled off the well while the gas migrating up and the casing pressure must increase to compensate loss of hydrostatic pressure from bleed off.
In the volumetric control, there are two ways to control bottom hole pressure while allo wing the gas migrating up to surface.
1. Wait and let gas migrate. The migration of gas will increase bottom hole pressure and casing pressure. 2. Bleed off mud from the annulus. Mud that is bled off must be equal to the increase in bottom hole pressure. Both steps above must be carefully performed perform in a sequence. We will go to the detailed procedures in later post.
3. Relationship of height an d fluid volume as determined by annular capacity – In order to determine volume of mud that equates to requi red hydrostatic pressure, we need to understand annulus capacity. It tells us how many bbl per foot in annulus and it can be calculated by this following formulas: Annular Capacity Factor (ACF) = (OD2-ID2) ÷ 1029.4 Where;
ACF = Annular Capacity Factor in bbl/ft
OD = Outside Diameter of Annular in inch
ID = Inside Diameter of Annular in inch
Once the ACF is know, we can determine Mud Increment (MI) which is the volume of mud bled off from the annulus to reduce the annular hydrostatic pressure by the amount of the pressure required.
Mud Increment (MI) can be calculated by this following equation:
Mud Increment (MI) = (PI x ACF) ÷ (0.05 2 x MW) Where;
PI = Pressure Increment in psi
ACF = Annular Capacity Factor in bbl/ft
MW = Mud Weight in the well in ppg
Cutting Settling in Deviated Wells Cause Stuck Pipe
Cutting settling in deviated wells – typically a well which has inclination more than 35 degree is classified as a
deviated well. How does it happen?
For the deviated wells, cuttings tend to set at the low side of the wellbore and form a cutting bed.
When there is a lot of cutting bed, it will slide down and pack the string. Moreover, while pulling out of hole, BHA will move some cutting bed and fi nally the cutting bed will pack BHA and drill string( stuck pipe ).
Warning signs of cutting setting in deviated wells
• Drilling with high angle well (more than 35 degree).
• While drilling with a mud motor, cutting cannot be effectively removed due to no pipe rotation.
• Increase in torque and drag (you must have a trend to see if torque/drag is abnormal)
• Increase in pump pressure without changing any mud p roperties.
Indications when you are stuck due to cutting bed in deviated wells
• The stuck pipe can happen while drilling and tripping out of hole. Most of the time, it will happen while POOH.
• Increase in torque and drag while drilling.
• Increase in drag while tripping out.
• Circulation pressure is higher than normal. Sometimes, it is impossible to circulate.
What should you do for this s ituation?
1. Attempt to circulate with low pressure (300 -400 psi). Do not use high pump pressure because the annulus will be packed harder and you will not be able to free the pi pe anymore. 2. Apply maximum allowable torque and jar down with maximum trip load. Do not try to jar up because you will
.
create worse situate
3. Be patient, and attempt until the pipe is free, then circulate and work pipe until the wellbore is clean.Do not continue operation until the hole is properly clean. Check cutting at shale shakers, torque/drag and pump pressure in order to ensure hole condition.
Preventive actions:
1. Ensure that annular velocity is more than cutting slip velocity
2. Ensure that mud properties are in good shape.
3. Consider pump hi-vis pill. You may try weighted or unweighted and see which one gives you the best cutting removal capability.
4. If you pump sweep, ensure that sweep must be return to surface before maki ng any connection. For a good drilling practice, you should not have more than one pill in the wellbore.
5. Circulate hole clean prior to tripping out of hole. Ensure that you have good reciprocation while circulating.
6. Circulate 5-10 minutes before making another connection in order to clear cutting around BHA.
7. Record drilling parameters and observe trend changes frequently.
8. Maximize ROP and hole cleaning.
Possible Kick (wellbore influx) Indications Part1 Possible Kick Indications mean that there is possibility to ge t influx into wellbore. The i ndications can be either kick or just formation react while drilling. You need to remember that just only a single possible indicator cannot may not good enough to identify underbalanced condition in wellbore and the possible kick indicators must be used collectively. Therefore, drilling team on the rig needs to closely monitor the well and prepare appropriate action plans.
The possible kick indications are as follows;
If the
• Change in drilling breaks (ROP change) -
differential between formation pressure and hydrostatic
pressure created by drilling mud decreases, there is possibility to increase rate of penetration because the hold
.
down effect is decreased
• Increase drag and torque – Increasing in drilling torque and drag are usually noticed while drilling into overpressured shale formation because underbalanc hydrostatic pressure exerted by drilling fluid column cannot to hold back the f ormation intrusion into wellbore. Shale normally has low permeability so formation fluid will not come into wellbore. Anyway, if we drill ahead pass high shale pressure into overpressured high permeability zones such as sand or carbonate, the formation fluid will flow into wellbore resulting in kick. This is very important to record frequently drilling torque and drag because it could be your well control indicator. • Decrease in Shale Density – Typically, shale density will increase as we drill deeper. If we see decrease in shale density, it may indicate that your well is in underbalance condition because high pressure zones (abnormal pressure) develop within large shale section. Practically, density of shale must be measured frequency and plot against drilling depth. You can see from a chart if there is any deviation in trend that could be an indication of change in pore pressure.
• Increase in cutting size and shape – Pieces of formation may break apart and fall into wellbore because of underbalance situation. Because rocks pieces broken by underbalance condition are not ruined by bit, they will be more angular and bigge r than normal cutting. Larger of cutting size will be result in di fficulty to circulate them out of wellbore, hence, there will be more hole fill and torque and drag will increase. In addition, without a proportional increase in ROP (rate of penetration), cutting volume coming over shale shakers will increased noticeably.
Possible Kick (wellbore influx) Indications Part2 Decrease in d-Exponent Value
Normally, trends of d-Exponent will increase as we drill deeper, but this value will decrease to lower values than what we expect in transition zones. By closely monitored d-Exponent, d-Exponent chart will b e useful for people on the rig to notify the high pressure transition zones.
Change in Mud property
Without any chemical added into drilling fluid system, its property change due to increasing in water and/or chloride content indicates that formation fluid enters into the wellbore.
For some mud, when salt water enters into the wellbore and mix with drilling fluid, the mud viscosity will increase.
In water base mud with low Ph salt saturated, the mud viscosity will decrease because of water from formation mixing with mud.
On the other hand, water contamination in oil base mud will result in viscosity increases.
Increase in Temperature from Returning Mud
By observing trend of temperature coming from mud return, temperature trend showing deviation from the normal temperature trend can be an indication of abnormal pressure zones, especially while drilling into trans ition zones.
There are some factors that you need to account for when you try to evaluate mud temperature changes as listed below;
• Surface temperature conditions
• Elapsed time since tripping
• Mud chemicals used
• Wellbore geometry
• Circulating rate
• Cooling effect when drilling fluid flows through a long riser (deep water consideration)
Increase in trip, connection and/or background gas
Gas in mud, normally called gas cut mud, does not be a sign of a well flowing because it could be gas coming from formation. Nonetheless, personnel on the rig should keep in mind as a possible kick indicator. Hence, flow show and PVT (pit volume total) must be closely monitored.
Gas in the mud can come from one or more of the reasons listed below:
• Drill into a formation that contains gas or hydrocarbon.
• Temporally reduce in hydrostatic pressure due to swabbing effect.
• Pore pressure in a formation is greater than the hydrostatic pressure provided by drilling fluid in a wellbore.
On the rig site, a ll kind of gas indi cations as trip, connection and/or background gas, must be fully monitored all time. It is the best practice to monitor in a chart fo rmat because we can look for the trend changes easily than just looking at one data point.
I wish you enjoy reading about the possible well control indicators.
Shale Instability Causes Stuck Pipe Shale instability happens when shale formation becomes unstable and finally formations break apart and fall into an annuls.Water in the mud absorbed by shale formations causes swelling effect on formations. When there is a lot of water, shale will not be able to hold their particles together and finally falls apart into the well. Finally shale particles will jam a drill string.
The shale instability is a chemical reaction which is time dependent. It means that you may not see it on d ay one, you may see it after you have been drilling for days.
.
The three figures below will help you get more understanding about shale instability and stuck pipe
(Day#1: Water is absorbed by shale)
(Day#2: Shale swelling due to water and shale starts falling apart.)
(Day#4: A lot of shale falls down and causes stuck pipe)
Warning signs of shale instability
• Torque and drag increase. An over pull may be observed.
• Mud properties became worse. You will see an increase in plastic viscosity, yield point (drilling mud becomes thicker).
• Pump pressure increases.
• Observe soft shale over shale shakers.
Indications when you stuck due to shale instability
• When it happens, you may observe very high pump pump pressure at small rate and sometimes circulation may be impossible.
• Most of the time it will happen when pulling out of hole. However, it can be possibly occurred while drilling as well.
What should you do for this situation?
1. Attempt to circulate with l ow pressure (300-400 psi). Do not use high pump pressure because the annulus will be packed harder and you will not be able to free the pipe anymore.
2. If you are drilling or POOH, apply maximum allowable torque and jar down with maximum trip load.
3. If you are tripping in hole, jar up with maximum trip load without applying any torque.
4. Attempt until pipe free and circulate to clean wellbore.
Preventive actions
1. For water For water based mud – mud – you you may need to add some salts that compatible with a mud formula in order to reduce chemical reaction between water and shale. Moreover, you should consider adding some coating polymers to prevent water contact with formation. 2. Use oil based mud instead of water based mud because oil will not react with shale. 3. Keep good flow rate to ensure good hole cleaning.
4. Perform back reaming and/or wiper trip.
5. Keep good mud properties. properties.
Mechanism of Accumulator (Koomey Unit) This topic describes how an accumulator (Koomey Unit) Unit) works. First of all, I will start with accumulator bottles. The accumulator bottles are used to store hydraulic pressure for closing/opening all blow out preventers. Each bottle, which has a rubber bladder inside, has a storage volume of 10 gallons. The rubber bladder inside is precharged to 1,000 psi with Nitrogen (N2). Each bottle will be pressured up 200 psi over the pressure charge pressure. At this stage, 1.7 gal of hydraulic fluid is used in order to compress N2 to minimum system pressure pressure of 1,200 psi (200 psi over pre charge pressure), called “minimum operating pressure”. Hydraulic Hydraulic oil will be pumped into the bottle until pressure in the bladder reach 3,000 psi, called “Operating Pressure”. Volume of hydraulic fluid used to pressure up from 1200 psi psi to 3000 ps,which is called “Useable Fluid”, is equal to 5 gallons, Note: I will show you how to use Bolye’s Law to figure out usable fluid later.
Accumulator Pressure Pressure Charging System System
In an accumulator unit as shown in the figure below as an example, there are one electric pump and two pneumatic pumps, which will be automatically pumped hydraulic fluid, which is stored in a reservoir tank when pressure in bottles is below set pressure in order to maintain bottle pressure at 3,000 psi. psi.The The electric pump is mainly used to maintain pressure. Pneumatic pumps will be use in case of 1) the electric pump failure and 2) helping the electric pump to increase bottle pressure quicker.
Note: you may see different set up depending on the rig but the concept is the same. Hydraulic fluid under pressured is divided into two following ways:
1. The first way is u sed for controlling an annular preventer. Hydraulic under pressure of 3 ,000 psi in bottles passes a pressure regulator (in the figure is a regulator “A”) in order to regulate pressure from 3,000 to 500-1500 psi for operating annular preventer. Pressure used to operate the annular preventer must be less than pressure used to operate rams preventer because high pressure will damage a rubber seal inside of the annular preventer.
2. Another way is used to control rams preventers (VBR’s rams, blind/shear rams, pipe rams) and HCR valves. Hydraulic under pressure of 3,000 psi in bottles passes a pressure regulator (in the figure is a regulator “B”) in order to reduce pressure from 3,000 to 1,500 psi for operating rams preventers and HCR valves. The regulated hydraulic fluid under pressure of 1,500 goes to a manifold which is used to divide hydraulic pressure in many ways to operate equipment. This is normally called “Manifold Pressure”.
All pressure activated equipment as annular preventer, VBR’s and HCR valves have two hydraulic fluid ports. One is for opening equipment and another one is for closing equipment. You can operate the BOP equipment by pushing remote switches or handles at the accumulator unit. In case of opening equipment, pressured hydraulic fluid will be transmitted to the open port and hydraulic power will drive an internal mechanism inside equipment in order to open equipment. Fluid in closing side will be pushed out and g o back to a reservoir tank. On the contrary, in case of closing equipment, the process is quite as same as opening process but only fluid flow direction is opposite.
Pressure Drop Across a Bit Pressure across a bit occurs when the drilling mud passing through the jet nozzles. This pressure drop is important for drilling hydraulic optimization (maximum hydraulic horse power or impact force) and hole cleaning. The pressure drop at the nozzle area is a function of total flow area of the b it, flow rate and mud density.
Pressure drop across the bit can be determined by the following equation:
Where:
Pb = pressure drop across a bit, psi
Q = flow rate, gpm
W = mud weight, ppg
A = total flow area, square inch
Please use the following information to deter mine pressure drop across a bit
Flow rate = 800 gpm
Mud weight = 9.0 ppg
Total Flow Area = 0.3728 square inch
Pb = 3446 psi
Ram Preventers as Well Control Equipment In the previous topic, we discuss about the annular preventer and today we would like to give you more details regarding ram preventers. The ram preventers were invented by James Smither Abercrombie and Harry S. Cameron in 1922.
This preventer consists of two rams which extend into the center of the wellbore in order to shut the well in (see the image below). The ram preventers can be hydraulically or manually operated. When people would like to shut the well in using the ram preventer, they will go to the hydraulic option first. If the hydraulic is not properly operated, the manual system will be utilized.
In order to provide the wellbore sealing, the rams must compose of top seals and packers which are made of the special elastomer. For more understanding, please take a look at the diagram of Cameron BOP below.
(Courtesy of Cameron)
When the well is shut in, the packer will seal around drillstring or tubular and the top seal will be pushed against the BOP body. With both top seals and packer, the well is securely shut in when
In the drilling industry, there are four types of rams preventers which are Pipe Rams, Variable Bore Rams (VBR), blind rams and blind-shear rams.
Pipe Rams – it closes around the drill string or tubular in order to restrict the flow. The size of the rams must
match with drill string size in o rder to properly shut the well in. The rams are designed to hold pressure from the bottom only. Personnel should not close the ram in tool joint or open hole (closing without pipe in the well)
(Pipe Rams – Courtesy of Cameron)
Variable Bore Rams (VBR) – It is similar to the pipe rams but it can use with a wider range of outside diameter
of pipe. You can see that the packer can be varied depending th e force push against the rams. Please see the image below for more understanding.
(Variable Bore Rams (VBR) – Courtesy of Cameron)
Blind Rams – This rams are used to close the wellbore when there is no drilling string in the wellbore and the
blind rams cannot shear the pipe. Most operators and drilling contractors don’t consider using this rams but they prefer blind-shear rams because the blind-shear rams can cut the pipe.
Blind Shear Rams – The blind shear rams have two applications – 1 seal the wellbore without pipe in the
.
wellbore, 2 cut the pipe prior to shutting the well in
(Blind Shear Rams – Courtesy of Cameron
Buoyancy Factor Calculation
Buoyancy Factor is the factor that is used to compensate loss of weight due to immersion in drilling fluid.
Before explaining any further, I will explain you about the basic concept of Buoyancy. Buoyancy is the upward force that keeps things afloat. The ne t upward buoyancy force equals to the amount of the weight of fluid
displaced by the body volume. This force will make objects lighter when it immerses in fluid. For example, we feel ourselves lighter when we are in swimming pool because this is the effect of buoyancy.
In drilling operation, we need to know how much weight of string of drill pipe, completion string, etc in d rilling fluid. Therefore, Buoyancy Factor is value that we need to know and be able to calculate this value. Please follow the formulas below to calculate Buoyancy Factor in different mud weight units, ppg and lb/ft3. Buoyancy Factor using mud weight in ppg Buoyancy Factor (BF) = (65.5 – mud weight in ppg) ÷65.5
Example: Determine the buoyancy factor for a 13.0 ppg fl uid: BF = (65.5 – 13.0) ÷ 65.5 BF = 0.8015 Buoyancy Factor using mud weight in lb/ft 3 Buoyancy Factor (BF) = (489 – mud weight in lb/ft 3) ÷489
Example: Determine the buoyancy factor for a 100 lb/ft3 fluid: BF = (489 – 100) ÷489 BF = 0.7955 How to use the Buoyancy Factor
In order to figure out the actual weight of drilling string in mud, the air weight of drilling string times the buoyancy factor equal to actual weight in mud, called buoyed weight.
For example , determine the string weight in 13.0 ppg mud. Air weight of string is 350 klb.
The buoyancy factor for a 13.0 ppg fluid: BF = (65.5 – 13.0) ÷ 65.5 BF = 0.8015 The bouyed weight of drill string in 13.0 ppg mud = 350 x 0.8 ydraulic
Horse Power Calculation Hydraulic Horse Power is a measure of the energy per unit of time that is being expended across the bit
nozzles. It is commonly calculated with the equation HHP=P*Q/1714, where P stands for pressure in pounds per square in., Q stands for flow rate in gallons per minute, and 1714 is a conversion factor necessary to yield HHP in terms of horsepower. Bit manufacturers often recommend that fluid hydraulics energy across the bit nozzles be in a particular HHP range, for example 2.0 to 7.0 HHP, to ensure adequate bit tooth and bottom-of-hole cleaning
(the minimum HHP) and to avoid premature erosion of the bit itself (the maximum HHP). Ref: http://www.glossary.oilfield.slb.com Hydraulic Horse Power (HPP) formula as follow: HHP= (P x Q) ÷1714 where HHP = hydraulic horsepower P = circulating pressure, psi Q = circulating rate, gpm Example : Determine Hydraulic Horse P ower with these following data:
circulating pressure = 3500 psi circulating rate = 800 gpm HHP= (3500 x 800) ÷1714 HHP = 1633.6 015 = 280.5 Klb.
Mud Weight or Mud Density
Mud weight or mud density is one of the important drilling fluid properties because it balances and controls
formation pressure. Moreover, it also helps wellbore stability. Mud weight is measured and reported in pounds per gallon (PPG) , pound per cubic feet (lb/ft3) , or grams per milliliter (b/ml) .
You can learn about how to covert pressure into mud weight here. Mud weight is normally measured by a conventional mud balance; however, if you have some air i nside a fluid phase, reading from the conventional mud balance will give you an inaccurate number. Therefore, the most accurate method to measure the mud weight is with a pressurized mud balance.
Conventional Mud Balance
The pressurized mud balance looks like the convention one, but it has a pressurized sample cup. When you press mud sample in the cup, any gas in fluid phase is compressed to very small volume so the mud weight measurement is more accurate.
Pressurized Mud Balance fluid density? 1. Well control - The well will be in an underbalance condition What will be happened if there is insufficient drilling so any formation fluids – gas, oil, and water- will enter into the wellbore. 2. Wellbore collapse (wellbore instability) – the wellbore will possibly become unstable, if the hydrostatic
pressure provided by a mud column is below formation pressure. What will be happened if the mud weight is too high? 1. Lost circulation – If the hydrostatic pressure from mud column exceeds formation strength, it will cause
formation to break. Once the formation is broken, the drilling fluids will lose into the induced formation fractures. 2. Decrease in rate of penetration – The more density you have while drill ing, the less ROP will be. Practically,
while drilling, low mud weight is used at the beginning and weight will be increased as the well is drilled deeper in order to optimize ROP. 3. Stuck pipe – Since there are differences between the formation pressure and the hydrostatic pressure, there
will be a lot of chances that a drill string will get differentially stuck across permeable rocks. 4. Formation damage – The more mud weight is i n the well, the more mud filtration invades into porous
formations. The invaded mud will cause damage to formation rocks.
Funnel Viscosity The funnel viscosity is time in second of drilling mud flowing through the Marsh Funnel Viscosity. The Marsh funnel is dimensioned so that the outflow time of one quart of freshwater (956 cc) at a temperature of 70 F +/- 5 F
.
(21 C +/- 3 C) in 26 +/- 0.5 seconds
Marsh Funnel
For all drilling mud, especially oil base mud, temperate always affects on the viscosity of base fluid. The base fluid will be less thick when the temperature increases. It means that the funnel viscosity will decrease.
The funnel viscosity measures at only one rate of shear but the temperature each time of measurement is not constant. This is the reason why the viscosity measured fromthe Marsh Funnel does not represent the true drilling mud viscosity. On the drilling rig, this measurement of the mud viscosity is still useful because it is a quick and simple test for observing trends of drilling mud. In order to use the funnel viscosity effectively, personnel must record the values frequently.Please remember that only single point of the funnel viscosity cannot tell you anything about a condition of drilling mud.
Rheology
You may have heard people talking about “Rheology” but you don’t have an ideal what it is. Let I explain you about it. Rheology is the study of flow and deformation of fluid. There are several rheology values such as gel strength, plastic viscosity (PV), and yield point (YP). This following information is determined by the rheological measurements from a mud test. • Equivalent circulating density • Hydraulic efficiency • Hole cleaning efficiency • Surge and Swab pressure • Pressure loss in the system • Pressure required to break circulation • etc Typically, PV and YP will increase as mud weight increases. In addition, mud weight has more effect on PV than YP.
Yield Point (YP) Yield Point (YP) is resistance of initial flow of fluid or the stress required in order to move the fluid. You can simply say that the Yield Point (YP) is the attractive force among colloidal particles in drilling mud. Practically, you can calculate the YP by this following formula. Yield Point (YP) = Reading from a viscometer at 300 rpm – Plastic Viscosity (PV)
A unit of YP is lb/100 ft2. You can determine the Plastic Viscosity (PV) by this formula. Plastic Viscosity (PV) = Reading at 600 rpm – Reading at 300 rpm
For example, you have these values from the viscometer.
Reading at 600 rpm = 56 Reading at 300 rpm = 35 Plastic Viscosity (PV) = 56 – 35 = 21 CP Yield Point (YP) = 35 – 21 = 14 lb/100 ft2. The YP indicates the ability of the drilling mud to carry cuttings to surface. Moreover, frictional pressure loss is directly related to the YP. If you have higher YP, you will have high pressure loss while the drilling mud is being circulated.
In water-based mud, the YP will be increased with following items; • High temperature – the high temperature environment tends to increase the YP in the water base mud. • Contaminants such as carbon dioxide, salt, and anhydrite in the drilling fluids
• Over treatment the drilling mud with lime or caustic soda In oil-based mud, the causes of increasing in YP are listed below; • Drill solid – the more drill solid you have, the more YP will be. • Treatment CO2 in the mud with lime (CaO) – The lime (CaO) will chemically react with CO2 to form Calcium
Carbonate (CaCO3) which will increase the YP. • Low temperature – in the oil base system, the low temperate will increase the viscosity and the YP. Please
keep in mind that this is opposite to the water base system. Operational impacts of the YP are as follows; Equivalent Circulating Density (ECD) – The ECD typically increases when the YP increases. Hole Cleaning - When you drill a large diameter hole, the YP in the drilling mud must be high in order to help
hole cleaning efficiency. In order to get the most optimized valve of PV for each a particular drilling campaign. It isvery difficult to say how high of PV should be because it depends on several factors. Especially, if you are drilling in the new field, you
.
may need to start with general YP values, and then you will learn once you have experience in a particular field
API Fluid Loss Test for Drilling Mud API Fluid Loss Test (low-pressure, low-temperature filtration test) is a test to measure a filtration of drilling mud with ambient temperature and 100 psi differential pressure. The API fluid loss testing equipment is shown
below.
How will you test the drilling mud?
• Place a filter
• Add the sample in the testing chamber
• Place the chamber in the testing kit
• Apply 100 psi p ressure
• Record volume for 30 minutes at the end of the test the volume of filtrate will be recorded.
• Record thickness of filter cake
If you don’t know what the filter cake (mud cake) is, I will give you short brief about it. The filter cake is solid particles, which are deposited against permeable zones due to d ifferential pressure between hydrostatic pressure and formation pressure.
If the drilling mud has good fluid loss property, you will get a thin and impermeable mud cake. Please keep in mind that this test is ba sed on the surface condition, and it may be error because it does not simulate downhole conditions. The API fluid loss test can lead you to the wrong conclusion because at the surface condition, the test demonstrates very good fluid loss and very thin filter cake. When the drilling mud is i n downhole condition, wellbore temperature and pressure will change the fluid property dramatically. The best way to test the fluid loss is to simulate wellbore temperature and pressure, and it will be discussed in the HPHT fluid loss late
Filter Cake of Drilling Mud
Filter cake is a layer formed by solid particles in drilling mud against porous zones due to differential pressure between hydrostatic pressure and formation pressure and it is always occurred while drilling the wells.
For our drilling operation, we would like to have the filter cake that is impermeable and thin. Practically, the filter cake should be less than or equal to 1/16 inch. If you have bad drilling fluid, which results in a thick filter cake in the wellbore, you will possibly face with a stuck pipe situation and high torque/drag. How will the filter cake impact on drilling operation? Differential sticking – If you have t he thick filter cake, a contact area between drilling string or any kind of
tubular will be increased. When d rilling into permeable zones that are severely overbalance, your drilling string will have high chance to get differentially stuck across them. Moreover, not only can the drilling string get stuck, the logging tool may be differentially stuck across the permeable zones as well. Torque and drag – Under dynamic conditions such as drilling, working pipe, etc., if your mud is not in good
shape, and it causes the t hick filter cake across the wall of the wellbore, you will see the i ncrease in torque. Let’s analyze about a drag issue, with thick wall filter cake, you will face with high drag while tripping out of hole or
.
logging
HTHP Fluid Loss Test for drilling mud You have learned about the API fluid loss test from the previous topic, and you know that the API fluid lost test does not represent the down hole condition. The new fluid loss test, named “HTHP fluid loss test”, is created in order to simulate the downhole condition. Just for your information, HTHP stands for “High Temperature High Pressure” The HTHP test is similar to the API test because it tells us about drilling mud filtration into the formation under a static condition over certain period of time. For the HTHP test, you can vary both temperature and pressure to represent your expected downhole condition. You can see the HTHP test kit as a figure below:
HTHP filter lost kit
The HTHP testing equipment has a heating jacket so you can heat up the drilling fluid sample to the expected wellbore temperature. Typically, the recommended temperature in the heating jacket should be above the estimated temperate about 25F to 50F . You don’t want the testing temperature too high or low because it will
not represent downhole condition very well. Therefore, with the recommended temperature, the drilling mud will not be over or under treated. Moreover, while performing the test, it must be under pressure and the test should be conducted at 500 psi differential pressure . The HTHP test is performed for 30 minutes, like the API fluid lost test.
Solid Content in Drilling Mud Solid content is a fraction total solid in drilling mud, and it always increases while drilling ahead because of drilling solid (cuttings), mud chemical additives and weighting material. When we talk about the solid content, we always mean soluble and insoluble solid content in the drilling fluid system. There are three types of solid contents as listed below; - Soluble material such as salt - Insoluble high gravity solid (HGS) as weighting agents (barite, calcium carbonate, hematite, etc.) - Insoluble low gravity solid (LGS) or drilled solid as solids particles from cuttings
The drill solids are the worst solid content in the drilling fl uid because it gradually deteriorates mud properties. Moreover, if its particle size is less than 5 microns, these drill solids could not be removed by mechanical methods, and they will stay in the mud forever. Generally, the drill solids will take 6-7 percent of total mud volume. Since the drilled solid content is very important, it must be checked daily. For good drilling practices, the drilled solid should be tested twice a day by retorting. The upper limit of the drill solid faction should be 6 -7 % by volume or approximately 55 – 60 lb/bbl. Please remember that th is figure is general rule of thumb. Practically, you can drill with more solid content for a while but over all performance will be down.
Another value besides the LGS and HGS that you must contemplate is the average density of solids in the drilling fluid. I will explain why this figure is important and what it tells us. The weighting materials as barite, Calcium Carbonate, etc have a specific gravity value about 4.2. However, the drilled solids as clay and silt ha ve a less specific gravity about 2.6. The average solid density means the relative concentrations of both the weighting agent and the drilled solid. Normally, the acceptable value of the average solid density is about 3.8 or higher. If you see this value below 3.8, it indicates that there may be too much low gravity solid in the mud.
pH in drilling mud pH is a value representing the hydrogen ion concentration in liquid. W e use it to indicate a cidity or alkalinity of drilling mud especially water base mud . Let’s talk about general of the pH. The pH is presented in a numerical value (0-14) which means an inverse measurement of hydrogen concentration in the fluid. The pH formula is listed below;
pH = -log10[H]
Where: H is the hydrogen i on concentration in mol.
According to the pH formula, the more hydrogen atoms present, the more acidity of substance is but the pH valve decreases. Generally speaking, the pH of 7 means neutral. Fluids with a pH above 7 are considered as alkaline. On other hand, the fluids with pH below 7 are defined as acidic.
In the drilling mud, there are three main chemical components involving in Alkalinity of drilling fluid which are bicarbonate ions (HCO3-), hydroxyl ions (OH-), and carbonate ions (CO3-2). As you may not know about what i s the Alkalinity. The Alkalinity means ions that will reduce the acidity. So as to get accurate measurements for the pH, you need to use a pH meter instead of using a pH paper because it can give you more accurate figures. However, you need to ensure that the pH meters should be calibrated frequently.
Cutting Settling in a Vertical or Near vertical Wellbore Causes Stuck Pipe Cutting settling in vertical or near vertical wellbore – typically the wells classified as vertical or near vertical
wells has inclination less than 35 degree. How does it happen? Cuttings in the wellbore are not removed from the annulus enough because there is not enoughcutting slip velocity in and/or drilling mud properties in the wellbore is bad. When pumps are off, cuttings fall down due to gravitational force and pack and annulus. Finally, it results in stuck pipe.
Note: In order to clean annulus effectively, the annular velocity must be more than cutting slip velocity in dynamic condition. Moreover, mud properties must be able to carry cutting when pu mps on and suspend cutting when pumps off. Warning signs of cutting setting in vertical well
• There are increase in torque /drag and pump pressure.
• You may see over pull when picking up and pump pressure required to break circulating is higher without any parameters changes.
Indications when you are stuck due to cutting bed in vertical well
• When this stuck pipe caused by cutting settling is happened, circulation is restricted and sometimes impossible. It most likely happens when pump off (making connection) or tripping in/out of hole.
What should you do for this s ituation?
1. Attempt to circulate with low pressure (300 -400 psi). Do not use high pump pressure because the annulus will be packed harder and you will not be able to free the pipe anymore.
2. Apply maximum allowable torque and jar down with maximum trip load. Do not try to jar up because you will create worse situate.
3. Attempt until the pipe is free, then circulate and work pipe until the wellbore is clean. Check cutting at shale shakers, torque/drag and pump pressure in order to ensure hole condition.
Preventive actions
1. Ensure that annular velocity is more than cutting slip velocity.
2. Ensure that mud properties are in good shape. 3. Consider pump hi-vis pill. You may try weighted or unweighted and see which one gives you the best cutting removal capibility.
4. If you pump sweep, ensure that sweep must be return to surface before making any connection. For a good drilling practice, you should not have more than one pill in the wellbore.
5. Circulate hole clean prior to tripping out of hole. Ensure that you have good reciprocation while circulating.
6. Circulate 5-10 minutes before making another connection in order to clear cutting around BHA.
7. Record drilling parameters and observe trend changes frequently.
8. Maximize ROP and hole cleaning.
Differential Sticking Causes Stuck Pipe Differential Sticking is one of the most common causes of pipe stuck. It can happen when there is differential
pressure (overbalance pressure) pushing a drillstring into filter cake of a permeable formation. Point To Optimize Drilling Hydraulics Typically, drilling hydraulics optimizations (maximum jet impact and maximum hydraulic horsepower) are based on an assumption of a fixed system. In real operation, you cannot fix flow rate to drill all the way to TD because the system pressure loss is changed because of hole depth, drillin g mud properties, wellbore conditions, etc.
There are two ways of optimizing drilling hydraulics which are optimization at the beginning of the run and at
the end of the run. Drilling Hydraulics Optimized at the Beginning of the Run
If the system is designed to meet the maximum hydraulic horsepower at the beginning of the well and th e pump pressure is maintained constant at the designed value, when the well is getting deeper, the flow rate must be reduced to maintain the pressure. With this situation, it will cause the jet velocity and hydraulic horsepower
.
dropping (see the curve below) at the end
Drilling Hydraulics Optimized at the End of the Run
For this case, the end of the run (the deepest depth) is the condition where we design to maximize hydraulic horse power. We know the pressure which we will maintain to get the best hole cleaning at the end. At the beginning of the run, the hydraulic horsepower will not be at the maximum point (see the curve below).
Decide the Optimum Point of the Bit Run for drilling hydraulics optimization
First of all, you ne ed to keep in mind t hat the calculation for drilling hydraulics optimization is valid only for a fixed depth. Therefore, you need to work withi n a certain range. Practically, operating within 15 – 20 % deviation from the theoretical value is acceptable because either hydraulic horsepower or impact force will not be changed significantly. Moreover, the best point to optimize hydraulics is at the end of the bit run because it gives the best hole cleaning at the deepest depth and makes the best performance of the bit.
Four factors causing the differential sticking are as follows: Permeable formation as sand stone, lime, carbonate, etc. Overbalance – typically mud weight in the well is more than formation pressure. More overbalance in the
wellbore, more chance of getting differential sticking. Filter cake – Poor and thick filter cake increases chances of sticking the drill string. Pipe movement – if the drillstring is station for a period of time, the filter cake will tend to develop around
permeable zones and the drillstring. Therefore, potential of getting differentially stuck is increased. Warning signs when you get stuck due to differential sticking
• There are high over balance between wellbore and formation. Especially, when there is highly depleted formation, the chance of getting differentially stuck is so high.
• Torque, pick up and slack off weight increase when the drill string is being moved. Once it happens, you may not be able to pull or rotate pipe.
Stuck identification for differential sticking
• Drill string is in station for a period of time. The differential sticking is happened when there is no pipe movement for long time.
• Circulation can be established without increasing in pressure.
• BHA is across the permeable zone.
Let’s see how much differential force from this situation
Formation pressure = 3800 psi
Hydrostatic pressure =4500 psi
Cross area of stuck pipe = 1500 square inch
You can determine how much differential force based on a following formula:
Force = Differential Pressure x Cross Section Area Where
Force is in lb.
Differential pressure is in psi.
Cross section area is in square inch.
Force = (4500 – 3800) x 1500 Force = 1,050,000 lb This is massive !!!
If we assume a coefficient friction of 0.5, you can determine how much tension you need to free the pipe by this following formula: From the basic of physic, F= coefficient friction x N
where:
F is force to pull. N is reactive force. For this scenario, N is equal to differential force.
F = 0.5 x 1,050,000 = 525,000 lb
You need overpull of 525,000 lb to fee the pipe from this situation. This is still massive What should you do for this s ituation?
1. Apply torque into drill string and jar down with maximum allowable trip load
2. Jar up without apply torque in the drill string.
3. Spot light weight pill to decrease hydrostatic pressure. If you want to the light weight pill, you must ensure that the overall hydrostatic pressure is more than formation pressure. Otherwise, you will face with a well control situation.
Preventive actions are as follows:
1. Do not use too high mud weight
2. Do not stop moving string for a period of time, especially, when the BHA is across formations.
3. Keep mud in good shape. Under specification drilling mud will create thick mud cake which can be a big impact for the differential sticking.
4. Minimize length of BHA and use spiral drill collar and heavy weight drill pipe to reduce contact area.
7 Ways to Strengthen a Wellbore Strengthen a wellbore while drilling is the most effective technique to do to the wellbore before bad losses will be happened. Techniques of wellbore-strengthen are similar to lost circulation concepts. The wellbore-strengthen techniques emphasize on lost circulation prevention, increase in overall formation fracture gradient and elimination of fracture elongation. However, the lost circulation concepts focus on preventing l osses of drilling fluid. In the drilling industry, 7 effective ways to strength the wellbore are as follows; 1. High fluid loss slurry – with high fluid loss slurry, the slurry will easily lose liquid component into the formation
and leave solid behind. The solid will be pushed into fracture spaces and create impermeable zones. 2. Granular loss-circulation material – By adding the g ranular loss-circulation material ahead of the time, the
material in the drilling fluid will plug off fractures that will result in higher formation strength and stop mud loss. 3. Smear effect – You are able to see this effect when drilling with casing. While rotating, the casing smears filter
cake and cutting into the borehole wall. This effect creates a plastic-like sealant at the wall of wellbore that helps prevent the wellbore collapse. 4. Heating the wellbore – By heating up formation around the wellbore, the formation will be expanded and it will
increase rock stress. Therefore, the well becomes stronger. 5. Chemical sealant – It acts like an epoxy. When it is pumped into the wellbore, the chemical component will go
inside pore spaces and create walls across the fractures in the wellbore therefore the overall formation strength will be greater and loss circulation will be ceased. 6. Ultra-low fluid loss chemical – This particular chemical is mostly utilized to prevent lost circulation in
permeable zones. With properly adding into drilling fluid, the chemical will reduce the initial spurt loss of mud therefore a filter cake will be almost impermeable. The impermeable filter cake around the wellbore will prevent losses into permeable formations. 7. Rigid-plug forming treatment – This is a special liquid chemical and when it is mixed with drilling mud, it will
create cross-linked polymer just like latex rubber which will plug wellbore fractures in order to prevent lost circulation problem. Wellbore-strengthening techniques are very important because they will prevent the lost circulation, one of critical problems in drilling operation. Therefore, you need to understand all concepts to achieve drilling free operation.
Why Slug Does Not Work? Slug is typically used to push mud in the drill string down therefore pipe will dry while pulling out of hole. Dry pipe while pulling out has some advantages as minimizing crew to expose to drilling mud when breaking a connection, reducing time to handle the drill string, etc. Sometimes, even you already pump slug but you still have wet pipe instead of dry pipe. You may wonder why the slug does not work very well. The following reasons why the slug does no t do its job are as follows: • Slug volume is not enough to slug the pipe. Recommended volume is around 25- 40 bbl.
• You should chase slug by pumping mud at least surface volume from mud pump to a rotary table. Otherwise, you will not get desired slug volume in the drillstring because it is still left in the surface volume.
• Weight of slug is not sufficient. As a normal practice, the slug weight should have at least 2 ppg over your current mud weight.
• There is something inside the drill string so the slug could not push mud in the drill string down.
What is slug mud? How much volume and weight of slug mud should be?
Slug Mud: It is heavy mud which is used to push lighter mud weight down before pulling drill pipe out of hole.
Slug is used when pipe became wet while pulling out of hole.
Normally, 1.5 to 2 PPG over current mud weight is a rule of thumb to decide how much weight of slug should be. For example, current mud weight is 10 PPG. Slug weight should be about 11.5 to 12 PPG. Normally, slug is pumped to push mud down approximate 200 ft (+/2 stands) and slug volume can be calculated by applying a concept of U-tube (see a figure below)
Volume of slug can be calculated by this following equation:
This equation expresses that the higher slug volume, the deeper of dry in drill pipe is met. As p er the above equation, length of dry pipe can be substituted by 200 ft.
In normal practice, slug volume pumped to clean drill pipe is around 15-25 bbl depending on drillpipe size. Moreover, it also depends on situations because sometime mud in annulus side may be heavier than measured MW due to cutting, drilling solid contaminated in mud, hence more slug volume is needed.
Drilling Formula – Slug Calculation in Barrels for Length of Dry Pipe 4 steps in finding a slug calculation in bbls for a Length of Dry Pipe. 1 – Find the hydrostatic pressure it takes to drop inside the drill pipe. HP psi = Mud Weight ppg x 0.052 x length of DRY pipe in feet 2 – Find the difference in pressure gradient between slug weight and mud weight. Pressure Gradient Change psi = (slug weight ppg – mud weight ppg) x 0.052 3 – Calculate length of slug in drill pipe. Slug Length ft = pressure in psi / change in pressure gradient psi-ft 4 – Calculate the slug volume in barrels. slug volume bbls = slug length ft x drill pipe volume bbl-ft Let’s complete an example given the following information: - Desired length of dry pipe, 3 stands = 276 ft - Mud weight = 12.5 ppg - Drill Capacity 4.5 in = 0.01422 bbl/ft - Slug weight = 14.5 ppg 1. HP psi = 12.5 ppg x 0.052 x 276 feet = 179.4 psi 2. Pressure Gradient Change psi = (14.5 ppg – 12.5 ppg) x 0.052 = .104 psi 3. Slug Length ft = 179.4 psi / .104 psi-ft = 1725 feet 4. slug volume bbls = 1725 ft x .01422 bbl-ft = 24.53 barrels
Stuck Pipe Introduction This topic will give you o verview of stuck pipe and how people classify stuck pipe. Definition of stuck pipe
Stuck pipe is a situation when the drill string cannot be moved from the well. The drill string may be partially moved and you may be able to circulate and rotate the pipe. Personnel on the rig must be able to identify the cause of stuck pipe in order to figure out the right way to free the pipe.
Stuck pipe categories
There are 3 categories of stuck pipes as follows: 1. Pack off and bridging: Pack off and b ridging are occurred when there is something in the wellbore as
formation cutting, junk, etc accumulating around drilling string/BHA and that stuff blocks the annulus between drill string and the wellbore. You should remember that either big or small debris can stick the pipe. According to statistics around the world, pack off and bridging is the most frequent cause of stuck pipe situation in the world. It normally occurs when the mud pumps are off for an extended period of time such as when pu lling out of hole. It is quite a tough job to free the pipe in case of packoff or bridging and the chance of success is lower than differential or wellbore geometry sticking mechanism.
2. Differential sticking: Differential sticking happens when drill string i s pushed against permeable formations
by differential pressure between hydrostatic and formation pressure. The frictional force between drillstring and formation is so high that you will not be able to move the pipe. The differential sticking tends to easily happen when drilling through depleted reservoir is conducted. Moreover, this stuck mechanism almost always happens when the drill string has been stopped moving for a long time.
3. Wellbore geometry: Wellbore geometry stuck pipe mechanism occurs when the shape of the well and the
bottom hole assembly (BHA) don’t match each other. Therefore, the drill string are not able to pass through that section.
Well ballooning (wellbore breathing or micro fracture) This topic describes about well ballooning. You may hear several terms besides well ballooning as wellbore breathing or micro fracturing phenomenon. What is well ballooning?
The well ballooning effect is a natural phenomenon occurring when formations takedrilling mud when the pumps are on and the formations give the mud back when the pumps are off. What is mechanism of well ballooning?
While pumps are on, if Equivalent Circulating Density (ECD) exceeds formation fracture, micro fractures are created and drilling mud will lose into small induced formation fractures. The micro fractures can be propagated and it may cause a l ot of mud volume losses down hole. Micro fracture will not cause severe losses or totally losses.
When pumps are off, the ECD will reduce because annular pressure loss becomes zero. The induced micro fractures will close and the drilling mud will flow back into a wellbore.
The ballooning can happen into any weak formations, not only at the casing shoe. Sometimes, mud flow back from formations can bring gas or formation water with the mud therefore you may see gas peak or mud contaminated with water while circulating bottom up.
How to Identify Well Ballooning It is not simple to identify well ballooning because the well acts almost like well control situation (taking kick). Therefore, this topic describe how to identify well ballooning and important rules when you face with well ballooning situation. These following guidelines will help you identify ballooning. • Drilling mud losses – you must have mud loss into formation in order to have mud fl ow back when pumps off.
• Flow back when pump off and flow rate decrease over time – you must line the well up into a trip tank and
monitor well. Tracking volume flow back every minutes help you understand if flow back t rend decreases. The key thing is “flow back rate must reduce over time”. If not, you will have well control situation instead. Monitoring well takes time and personnel must be patient.
• The more mud you lose, the faster flow back is and the longer time will take before the well is static (flow completely stop).
• Mud flow back from formations can bring gas or reservoir water with the mud therefore you may see gas peak or mud contaminated with formation water at the same depth while circulating bottom up. There are important rules that you should know about well ballooning as listed below.
• Treat the well as kick until you are 100% sure that the ballooning occurs. • Mud loss into formations must be happened first before you can have flow back.If you have flow back but you don’t lose any mud, this is not ballooning. • In a ballooning well, flow back rate will decrease over time but in a well control well, flow back rate will increase over time.
Kill Weight Mud Kill Weight Mud or Kill Drilling Fluid Density is the mud weight requ ired to balance formation pressure. The kill weight mud may be pumped into the well at different time depending on kill methods(Driller’s method, Wait and Weight, Bull head, etc). How to determine kill weight mud?
With the following equation, you can determine this figure.
Kill Weight Mud (KWM) = Current Mud Weight + (SIDPP ÷ 0 .052 ÷ Well TVD)
Where,
Kill Weight Mud (KWM) in ppg Current Mud Weight in ppg SIDP stands for “Shut In Drill Pipe Pressure” in psi. Well TVD is true vertical depth of the well in ft. If your drilling string has a solid float, you will not be able to read SIDPP right away. So you need to bump the float to get SIDPP. You can read more detail about it via this > float bumping procedure. Example
Drilling with 9.5 ppg mud and current depth at 9 500’MD/9000’TVD. The well takes influx. Operation is stopped and the well is shut in.
Shut in drill pipe pressure = 550 psi.
Shut in casing pressure = 700 psi.
The kill weight mud required to balance formation pressure:
KWM = 9.5 + (550 ÷ 0.052 ÷ 9000)
KWM = 10.7 (round up number)
Why do we need to use SIDPP?
When you take a kick (wellbore influx), the density of fluid in the annulus is very hard to predict because it is a mixture between drilling mud and influx. Therefore, you don’t know exactly what the density in the a nnulus is. Moreover if you take gas kick, shut in casing pressure will increase over time, and you will NOT be able to identify the right shut in p ressure to determine formation pressure.
Looking at the drill pipe side, there is only one pure fluid column so you know exactly its density. With the precise mud density, you can apply hydrostatic pressure concept in order to get the formation pressure and kill weight mud (the equation is showed at the beginning of the topic
Determine how many feet of free pipe without free pipe constant table
You may sometimes find the table for Free Point Constant for your stuck pipe calculation so you use the formula from the previous post to determine Free Point Constant and apply it into free pipe formula to determine where the depth of stuck pipe is. *** This calculation is based on vertical well assumption.***
The steps of calculation are as follows:
1 ) Determine the free point constant (FPC) by this following formula: FPC = As x 2500
where: As = pipe wall cross sectional area, sq in. As = (OD2-ID2) x 0.7854
OD and ID are inch unit
2) Determine depth of stuck pipe by this following formula:
Depth of stuck pipe = (Pipe stretch in inch x free point constant (FPC)) ÷ Pull force in thousands of pounds
Please see the example below to demonstrate you how to apply those 2 formulas above into real d rilling operation.
Example#2: Determine the free point constant (FPC) and the depth the pipe is stuck using t he following information:
3-1/2” tubing # 9.5 lb/ft
3-1/2” tubing ID = 2.992 inch
20 inch of stretch with 25 Klb of pulling force
a) Determine free point constant (FPC):
FPC = (3.52 – 2.9922) x 0.7854 x 2500 FPC = 6475.5
b) Determine the depth of stuck pipe:
Feet of free pipe (ft) = (20 inch x 6475.5) ÷ 25
** 25 is the kilo-force to pull to 20 inch ** Feet of free pipe (ft) = 5,180 ft
Pressure Required to Break Circulation in Annulus From the previous post, we learn about how to determine break circulating pressure inside drill string. This post we will learn about how to calculate pressure required to break circulation in annulas. Formula to calculate pressure required overcoming the mud’s gel strength in the annulus as follow: Pgs = y ÷ [300 x (Dh, in. - Dp, in.)] x L
where Pgs = pressure required to break gel strength, psi L = length of drill string, ft y = 10 mm. gel strength of drilling fluid, lb/100 sq ft Dh = hole diameter, in. Dp = pipe diameter, in. Let’s take a look at the example below and understand how to determine pressure required to break circulation in the annulus by using following information
L = 11,500 ft
y = 12 lb/100 sq ft
Dh = 6.5 in.
Dp = 4.0 in.
Referring to the formula above, all parameters can simply input into the formula to get the break circulation pressure in the annulus.
Pgs = 12 ÷ [300 x (6.5 - 4.0)] x 11,500 ft Pgs = 184.0 psi
How to Prevent Well Ballooning This topic will you describe how to prevent well ballooning. There are several items that you can manage in order
.
to prevent or minimize well ballooning
Trying not to lose fluid or to minimize drilling mud loss into formation is the best way to prevent well ballooning. As you may know from the previous topic, well ballooning basic, before ballooning will happen, you must have downhole losses. Then, flow back will occur when pumps are off.
There are several ways that can help you on this issue as listed below: Manage Equivalent Circulating Density (ECD)
• Develop pumping schedule to minimize ECD and still have good hole cleaning
• Select proper BHA and drill size – this directly affects annular pressure loss.
• Drilling mud properties – do not have high rheology mud while drilling. Moreover, good mud cake will seal porous formation and minimize losses down hole. Try to keep mud properties in good shape and treat mud
.
ahead of the time if needed
• Utilize pressure while drilling (PWD) to monitor downhole pressure
Understand Formations and Rocks
• Understand formation strength and how much – this point will affect you how to design the well. You don’t want to drill with high mud weight to control formation pressure down below but take a chance to break formation at the top.
• Know where depleted zones are – the depleted zones have more chance of drilling mud to lose. Minimize overbalance and keep good mud properties will help to minimize losses
Good Drilling Practices Bring pumps up slowly and stage-by-stage increment Don’t try to surge wellbore while t ripping in hole, working pipe, etc. Slowly rotate drill string for few seconds to break gel prior to slowly bringing pumps up to speed.
Balanced Cement Plug Calculation
You already learn about balance cement plug and I would like to show how to calculate balance cement plug. Let’s start with the concept so you can imagine how the calculation should be. 1. Determine volume of cement that you need. 2. Determine height of cement and spacer when pipe in hole. 3. Determine displace volume to balance the hydrostatic both sides. When the displacement is completed, you should have equal height of cement/spacer/mud. You can see the figure below for more understanding.
4. When you pull cement stinger, you will have the balance set properly like this.
Example for the balanced cement calculation The operator plans to set abandonment plug in the open hole across the pay sand.
Well information is
listed below:
• 7” casing shoe is set at 6000’MD/5500’TVD. • 7” casing grade 23 ppf BTC, ID = 6.366 inch. • Drilling fluid: 10.0 ppg oil based mud • Hole size = 6.25” based on caliper log. • Hole TD = 12,000’MD/10,000’TVD • Pay sand is from 9000 – 9500 ft • The planned cement length is 1,000 ft. • The planned bottom of cement plug is 9,600 ft. • Spacer: 50 bbl of spacer and weight of spacer 10.5 ppg. • Cement stinger: 1200 ft of 2-7/8” tubing. • 2-7/8” tubing ID is 2.44 inch. • Drill pipe size: 4” DP and ID of drill pipe is 3.35 inch. • Use 0% excess • Cement weight 16.0 ppg
Determine how much cement that we should need and how the displacement plan should be. 1.
How much cement do we need for this job?
2.
Hole capacity of the well = 6.252 ÷ 1029.4 = 0.0379 bbl/ft
Volume of cement = length of cement x hole capacity Volume of cement = 1000 x 0.0379 = 37.9 bbl
2. How height of cement while the cement string in the well?
Cement stringer (2-7/8” tubing) capacity = 2.4412 ÷ 1029.4 = 0.0058 bbl/ft
Annular capacity between hole and cement stinger= (6.252 – 2.8752) ÷ 1029.4 = 0.03 bbl/ft
Since there is pipe in the hole, the top of cement (TOC) will be higher.
The TOC is calculated by the foll owing formula:
Length of cement with pipe = Cement Volume ÷ (Drill pipe capacity + Annular capacity)
Where;
Length of cement with pipe is in ft.
Cement Volume in bbl.
Drill pipe capacity in bbl/ft. Annular capacity in bbl/ft. Length of cement with pipe = 37.9 ÷ (0.03+0.0058) = 1,059 ft
It means that height of cement is 1,059 ft, therefore TOC when pipe in hole is 8541 ft (9600-1059).
3. Height of spacer while the cement string in the well
The plan is to pump 50 bbl of spacer; therefore, there might be some spacer up above the cement stinger.
Volume of spacer from top of cement to top of cement stinger (Spacer volume1)
Spacer volume1 = annular capacity between hole and cement stinger x le ngth of cement stinger from TOP to top of stinger.
Spacer volume1 = 0.03 x (8541-8400) = 4.23 bbl.
The rest of spacer which is 45.77 (50-4.23) bbl is in between drill pipe and hole.
Length of spacer between drill pi pe and hole = spacer volume ÷ annular capacity between hole and 4” DP
Annular capacity between hole and 4” DP = (6.252-42) ÷ 1029.4 = 0.0224 bbl/ft
Length of spacer between drill pipe and hole = 45.77 ÷ 0.0224 = 2043 ft
So the top of spacer is equal to top of stinger minus length of spacer between drill pipe and hole.
Top of spacer = 8400 – 2043 = 6357 ft.
4. Volume of space to that has equal height of spacer in the annulus
The volume of spacer inside string is equal to volume of spacer in cement stinger plus volume of spacer in 4” DP.
Volume of spacer in cement stinger = cement stinger capacity x length from top of stinger to top of cement
Cement stringer (2-7/8” tubing) capacity = 2.4412 ÷ 1029.4 = 0.0058 bbl/ft
Volume of spacer in cement stinger = 0.0058 x (8541-8400) =0.8178 bbl.
Volume of spacer in 4” DP = 4”DP capacity x length from top of stinger to top of spacer 4” DP capacity = 3.352 ÷ 1029.4 = 0.0109 bbl/f t
Volume of spacer in 4” DP = 0.0109 x (8400 – 6357) = 22.27 bbl
Total spacer volume in the string = 22.27 + 0.8178 = 23.1 (round up figure) bbl. 5. Volume of mud displacement
In order to balance hydrostatic pressure, volume of mud displacement is volume from surface to top of spacer. Volume of mud displacement = capacity of 4” DP x top of spacer Volume of mud displacement = 0.0109 x 6357 = 69.3 bbl. Pumping steps for balanced cement plug are as follows:
1. Pump 50 bbl of spacer. 2. Pump 37.9 bbl of cement. 3. Pump 23.1 bbl of spacer . 4. Pump 69.b bbl of drilling mud. ** You may under displace 2-3 bbl to create cement falling effect in drill pipe. ** 5. Pull slowly above TOC 6. Circulate bottom up 7. Pull out of hole to surface.
Final cement in place after pulling the cement stinger out of hole is below.
Good Practice To Tag Top Of Cement After complete the cement balanced plug job, you should need to go back in hole and attempt to tag to see where the actual TOC is.
You should be careful when you try to find the top of cement otherwise you may not have a big problem. These procedures are good drilling practice which you can adapt for your operation. 1. First of all, you need to know where the calculated TOC is. 2. Trip in hole to approximately 1-2 stands above TOC.
3. Make up top drive or kelly depending on the rig set up. 4. Bring pump up to slow rate. This depends on how the BHA is set up. I cannot specific flow rate. 5. Slowly wash down and monitor the weight. 6. Wash down until you see solid weight tagged on a driller gauge. What will be happened if you don’t wash down to tag the top of cement? The BHA may be in t he green cement (cement is not properly set up) and when the pump is turn on, the cement will flash set. Finally, the drill string will get stuck.
Abnormal Pressure from Anticline Gas Cap I got a question about how an anticline gas cap can create the abnormal pressure.The anticline with gas cap can be the potential high pressurized zone. Because of reservoir connectivity between fluid underneath gas and gas reservoir, it can generate abnormal pressure. This example below demonstrates you how this situation could
.
happen
Well#1 was already drilled into oil reservoir at 6500’MD/6000’ TVD and its formation pressure is 0.52psi/ft.
The second well, well#2, is planned to drill into the g as cap, which has reservoir connectivity to the well#1, at 5400’MD/4800’ TVD and a geologist estimates gas cap thickness of 950 ft and pressure gradient is 0.1 psi/ft. What is minimum mud weight to be able to successfully drill well#2?
Firstly, I would like to share which basic concepts I will use for this case .
Hydrostatic Pressure Pressure gradient Convert pressure to equivalent mud weight Equivalent Mud Weight
You need to determine formation pressure of well#1.
Well#1: Well depth: 6,500’MD/6,000’TVD and Pressure gradient: 0.52 psi/ft Formation pressure of well#1 = 0.52 x 6000 = 3120 psi
Convert pressure to equivalent mud weight = 3120 ÷ (0.052 x 6000) = 10.0 ppg You may think that 10.0 ppg should be good mud weight to drill well#2. –> Wrong answer. Let’s take a look at the well#2.
Pressure at the bottom of gas cap = formation pressure of well 1 @ 6000’TVD –hydrostatic pressureof reservoir fluid Pressure at the bottom of gas cap = 3120 psi – 0.52 x (6000 – 5750) = 2990 psi
Determine the reservoir pressure at the top of gas cap:
Pressure at the top of gas cap = Pressure at the bottom of gas cap – hydrostatic of gas gradient Pressure at the top of gas cap = 2990 – (0.1×950) = 2895 psi
Since we know the formation pressure, we can calculate to equivalent mud weight (EMW). EMW of well#2 = 2895 ÷ (0.052 x 4800) = 11.6 ppg
You need mud weight at least 11.6 ppg to drill well#2 successfully. Conclusion: This case clearly shows you that the anticline gas cap can be high pressurized zone and you may
not be able to drill the well with the same mud weight as the adjacent drilled into the same reservoir.
What are Lead and Tail Cement?
In some cementing operation, operators will pump 2 cement slurries, normally called “Lead Cement” and “Tail Cement”. Both lead and tail cement have pro and con as described below.
Lead cement: Lead cement is in the top section of cement, where has lower both pressure and temperature (see
figure above). It has lower density and strength than Tail cement; however, it is also cheaper than Tail cement. Tail cement: Tail is pumped after lead cement because it must be settled at the lower section of well bore, where
needs high strength cement (see figure above) . It has higher strength than le ad cement, but it is more expensive than lead cement. Float Bumping Procedures To Get Shut In Drill Pipe Pressure by DRILLINGFORMULAS.COM on AUGUST 25, 2010
In order to get the correct value of drill pipe pressure, you need to have the correct floating bumping procedure. In this section, I will show you how to bump the float correctly.
These following procedures will demonstrate you how to bump the float correctly in order to get S DPP.
1. Ensure well is properly shut in. No l eak or whatever. 2. Record shut in casing pressure (SICP) 3. Pump as slowly as possible (5-10 stroke per minute) at constant pumping speed down into the drill pipe and keep monitoring the drill pipe pressure and the casing pressure. 4. You will see the drill pipe pressure increase while pumping. At this stage, you need to monitor carefully for a “lull” in the drillpipe pressure, which will occur when the float is opened. The drillpipe pressure showing when the lull is first seen is your shut in drill pipe pressure (SIDPP). 5. You also need to verify that the float has been opened by continuing to pump down the drillpipe slowly until you see an increase in the casing pressure. It should happen very quickly after the lu ll was seen on the d rillpipe gauge. 6. Shut down the pumping operation as soon as increase in casing pressure is detected. 7. Check the shut-in casing pressure again. If there is any excess casing pressure, you may bled-off some pressure in small increments until it equates or a little bit above SCP in steps no 2.
If you see trapped pressure on drill pipe after bumping the float , you can calculate the actual shut i n drill
pipe pressure with this following formula. Shut in drill pipe pressure = shut in drill pipe pressure after bumping the float – Shut in casing pressure increase while bumping float
Lag Time and Its Importance for Well Control Operation
Drilling personnel need to fully understand about the lag time. Lag time is time delay from pressure adjustment made on a choke valve or a choke HCR to show up on the drill pipe pressure gauge. Does it sound confuse? Let’s me explain more about it. When you adjust a choke position, you will not be able to see changes on the drill pipe gauge right away because drilling fluid is compressible so you need to be patient and wait a little bit until you see the changes on the drill pipe gauge.
How can we know how many seconds for the lag time?
We can roughly estimate the lag time about 2 seconds per 1,000 MD . This number is just a rule of thumb. If you want the actual lag time, you can determine it by performing a choke drill. You really need to know about the lag time otherwise you can get confused a lot when you attempt to adjust drill pipe pressure.
Driller’s Method in Well Control
Driller’s method is one of several methods to kill the well. The main idea of driller method is to kill the well with
constant bottom hole pressure. The Driller’s Method of well control requires two complete and separate circulations of drilling fluid in the well.
The first circulation removes influx with original mud w eight. When starting to bring pumps up to speed,
casing pressure must be held constant until kill rate is reached. Then drillpipe p ressure is held constant to maintain constant bottomhole pressure which is normally equal to, or slightly greater than pore pressure. Drillpipe pressure will be held constant until influx is removed from annulus. If the wellbore influx is gas, it will expand when it comes close to surface therefore you will see an increase in pit volume and casing pressure. After the kick is totally removed from the well, when the well is shut-in, drillpipe and casing pressure will be the same value. If not, it means that there is influx still left in the wellbore or trapped pressure.
Before going to the second circulation, we need to know kill mud weight which can be calculated from initial shutin drillpipe pressure. The calculation part will be discussed as in next section.
Second circulation kills well with kill mud. When the required kill mud weight is mixed, it is the time to start the
second circulation of driller method. We start with bringing pumps to kill rat e by holding casing pressure constant. While circulating with the kill mud, casing pressure must be held constant until kill mud reaches the bit. After that, we need to hold drill pipe pressure constant then continue circulating with constant drill pipe pressure until kill mud weight reaches at surface. Then shut down pumping operation and observe drillpipe and casing pressure. If the well is successfully killed, both drillpipe and casing pressure will be zero. If not, there is some influx still in the well.
Water Kick and Oil Kick Indications All of well control articles in this website are based on gas kick assumption. Therefore, all the responses as bottom hole pressure, surface pressure, gas volume, maximum pit gain, etc are influenced by gas e xpansion and gas migration. In reality, you may face with water influx or oil influx which is quite different than gas influx.
The following indications showing water or oil kick are listed below:
• When the well is shut in, casing pressure will not increase because water and oil don’t migrate. • When bumping the float, it is quite clear to see where the float is opened in o rder to obtain shut in drill pipe pressure. • While circulating influx out of the wellbore, casing pressure will not increase too h igh because water and oil don’t expand like gas. Actually, dealing with water kick or oil kick is a lot easier than gas kick because you don’t need to deal with gas migration, and gas expansion. Moreover, surface equipment will not be exposed to high pressure.
To confirm if this kick is water kick, you need to collect mud sample at the bottom and perform mud check. If the influx is water, electrical stability will d ecrease, viscosity will increase, and oil water ratio will decrease.
On the other hand, if the oil influx is suspected, you should see the following indications from the mud check: oil water ratio will increase, electrical stability may increase, and crude oil sample may be seen in the drilling mud.
For a good well control practice, you should treat all of well control as gas kick because it is the worst case scenario.
Pressure Loss and Equivalent Circulating Density Review – Reverse Circulation We still have the same question as the previous post, Pressure Loss and Equivalent Circulating Density Review, but this case we will d o reverser circulation, circulating from annulus to tubing , and see how much pressure and equivalent circulating density at bottom hole.
Data Given Reverse circulate total of 3 time bottom up from annulus to tubing with 12.7 ppg mud at 10,000′MD/10,000 TVD.
Pump pressure = 1000 psi Annulus friction loss = 50 psi Inside tubing friction loss = 925 psi Surface line friction loss = 25 psi Determine pressure at bottom hole.
We still apply the concept of frictional pressure so reverse circulation is calculated by this following equation: Pressure at bottom hole (reference at annulus side) = Hydrostatic Pressure + Pressure from pump- Annular Pressure Loss Note: Hydrostatic pressure and pressure from pump force downward to bottom hole but annulus pressure forces upward direction. Pressure in the well at 10,000’ = 1000 + (0.052×10,000×12.7) – 50 = 7554 psi OR you can referrence to the tubing side as well.
Pressure at bottom hole (reference at tubing) = Hydrostatic Pressure + Annular Pressure Loss in tubing + surface line pressure loss Note: All pressure force downward to bottom hole so all pressure term must be sum together. Pressure at bottom hole (reference at tubing) = (0.052×10,000×12.7) + 925+25 = 7554 psi. Determine Equivalent Circulating Density at bottom hole. ECD = Current mud weight in PPG + (annular pressure loss /(0.052xTVD)) = Total Pressure at Bottom Hole /(0.052xTVD)
ECD =7554 / (0.052 x 10,000) = 14.53 PPG.
The point that I want you to think of between this example and the previous example,Pressure Loss and Equivalent Circulating Density Review, is about the different o f bottom hole pressure and ECD between forward circulation and reverse circulation. You will see that reverse circulation results in a lot of pressure at bottom hole. Hence, you must keep in mind this concept and try to figure out how much pressure at bottom hole should be fo r both forward circulation and reverse circulation. Otherwise, you can accidentally break wellbore due to high ECD.
How to Predict Formation Pressure Prior to Drilling Formation pressure can be predicted from 3 information sources prior to drilling as follows; 1. Seismic Data
Seismic is the way to predict formation types by sending sound waves that penetrate into subsurface structure. Then, sound waves reflected back from formation are recorded as raw data. Geologists are able to predict geological structures and potential pressured zoned by interpreting the sound waves. With current 3D seismic modeling, the pressured zones are accurately predicted.
2. Geological Data
Geological information demonstrates condition that possibly causes abnormal pressure zones. The subsurface structures associated with abnormal pressure characteristics are anticlines, charged zones, depleted zones, faults, massive shale and Salt formations.
Anticlines: Anticlines is the geological structure that looks like a dome. Anticlines with cap rock on top are good
geological structure because hydrocarbon can possibly trapped below it. While drilling into top structure of anticlines, abnormal pressured zones are expected. Charged Zones: Charged zones are shallow formations that have pressure connectivity from abnormal pressure
zones below. Because of upward movement of reservoir fluid from deeper zones, charged zones are normally abnormal pressure. Charge zones can occur by nature or man-made. Currently, new geophysical methodologies can be applied for find where the charged zones are prior to drilling.
Depleted Zones: Depleted zones are formations that have less pressure than original formation pressure
because some formations have been produced. Using historical data in conjunction with geological t echniques can determine where the possibly depleted zones are. Faults: Because each fault block may has different pressure gradient, while drilling across a fault, drilling
problem associated with pressure such as well control problem or lost circulation may possibly happen. Massive Shale: Shale is non permeable formation therefore it restricts movement of formation fluid. When a l ot
of overburden formation layers are accumulated over massive shale, shale is compacted and reservoir fluid naturally tries to come out from the pore space. However, due to shale property, impermeable formation, it does not allowed pore fluid to come out therefore formation pressure caused by formation fluid becomes over pressured. Salt Formations: There are several parts of the world where pure and thick layers of salt are present. Typically,
salt formations are laterally and upwards forced causing salt domes. Because salt is impermeable, it does not allow formation fluid pass through it; therefore, formations below a salt formation are normall y abnormal pressure. 3. Historical Data
The historical data from adjacent area is good information for prediction formation pressure. Historical information can be obtained from formation pressure, mud logging reports, drilling reports, drilling fluid re ports, Logging While Drilling (LWD), Pressure While Drilling (PWD), etc.
Understand About Formation Pressure Formation pressure is the pressure of fluid contained in pore space of rock and there are 3 categories of the formation pressure which are normal pressure, abnormal pressure and subnormal pressure.
1. Normal Pressure: Normal pressure is the hydrostatic of water column from the surface to the subsurface
formation. The concentration of salt in water affects the normal pressure. Higher salt concentration in water, higher specific gravity of water will be. Therefore, the normal pressure can vary from slightly salt 0.433 psi/ft (8.33 PPG) to highly concentrated salt 0.478 psi/ft (9.2 PPG) based on salt concentration in water. 2. Abnormal Pressure: The abnormal p ressure is the pressure greater than the pressure column of water.
Generally, the abnormal pressure zones are good reservoir which oil companies are looking for. This kind of pressure can create well control problem. 3. Subnormal Pressure: The subnormal pressure is the pressure that is less than normal pressure and it
possibly causes lost circulation problems. Looking at the drawing below, it demonstrates the comparison of formation pressure when drilling into each pressure regime. At the same True Vertical Depth (TVD), subnormal pressure shows least pressure in comparison to others. However, abnormal pressure gives the highest pressure at the same level of TVD.
Minimum strength to support casing string One function of cement is to support casing string and the shear strength of cement holds casing string once cement is set. You may think about other l oad supporting casing as compressive loading at coupling areas or thermal movement. They are the part of the supporting force as well but the most support is from the cement shear strength.
(Diagram above shows how shear strength of cement supports casing string)
We don’t normally measure shear strength of cement but we can apply knowledge from Civil engineer to estimate the shear strength from the compressive strength. Generally, cement has the shear strength approximately 1/12 of compressive strength. For instant, if the cement 1000 psi compressive strength, its shear strength is 83.3 (1000 x 1/12) psi. Let’s take a look into the detailed calculati on for more understanding.
The information given is listed below Casing 9-5/8”, 40 ppf (pound per foot), ID of casing = 8.835”
Casing is set at 3,200’MD/3,000’TVD Top of cement at 600’MD/550’TVD Previous casing shoe (13-3/8”) = 1000’MD/900TVD
(The diagram shows all figures as per the data)
We will use the pressure and force concept (Force = Pressure x Area).
1. The outer surface area of casing covered with cement is equal to circumference of casing multiplied by length of cement covering casing. Area = Π x D x L Where Area in square inch. Π (called pi) =22/7 D is diameter in inch. L is length of cement in inch Area = Π x 9.625 x (2600 x 12) Area = 943,420 square inch.
2. Casing weight = weight in ppf x total length of casing
Casing weight = 40 x 3200 = 128,000 lb 3. Shear force is required to support whole weight of casing Shear strength (lb/square inch) = Casing weight ÷ Area of casing covered by cement Shear strength (psi) = 128,000 ÷ 943,420 = 0.136 psi
We can estimate the compressive strength of cement based on 1/12 figure. Shear Strength ÷ Compressive Strength =1/12 Compressive strength = 12 x 0.136 = 1.63 psi The figure tells us that you need only 1.63 psi compressive strength to support whole casing string. Ps, This is rough estimation without any consideration regarding complex load, thermal movement, etc.
Annular Preventers – Well Control Equipment Annular preventers are the most versatile well control equipment and there are many names referring it as bag preventers, or spherical preventers. The annular preventers are able to seal around several size of drill pipe/drill collar, work string, wireline, tubing, etc. There are some models which can utilize wellbore pressure to provide additional sealing capability. The annular preventer consists of a body, a cap, a piston and a rubber packing element. The illustration below
.
demonstrates the drawing of an annular preventer
How the annular preventers work?
Close - When the hydraulic oil is pumped into the extend port, the element inside will be li fted and squeezed the pipe/tubular.
Open - On the other hand, if the hydraulic fluid is pumped into the retract port, the element will be pushed down resulting in releasing the tubular.
Nowadays, there are several manufactures providing this equipment such as Hydril, NOV (Shaffer) and Cameron. The models available in the market based on the manufactures are listed below:
Hydril – Hydril GL, GX, GK and Annu-Flex
Hydril GL http://hydrilpressurecontrol.com/pressureControl/BOP/annulars/annular-GL.php
Hydril GK http://hydrilpressurecontrol.com/pressureControl/BOP/annulars/annular-GK.php
Hydril Gx http://hydrilpressurecontrol.com/pressureControl/BOP/annulars/annular-GX.php
Hydril Anuflex http://hydrilpressurecontrol.com/pressureControl/BOP/annulars/annular-Annuflex.php
Cameron – Cameron DL
Cameron DL http://www.c-a-m.com/forms/Product.aspx?prodID=ecd6ef4e-19dc-4ea9-ad47-94689e36b61c
NOV (Shaffer) – SPHERICAL BOPS
SPHERICAL BOPS http://www.nov.com/Drilling/Drilling_Pressure_Control/Blowout_Preventers/Spherical_BOPs.aspx
In the market, the annular preventers have wide range of size and operating pressure and you can see from the technical specification from the link that we provide. It is very important that personnel must know how to operate and maintenance the annular preventers properly. Personnel must strictly follow the operating manual to prevent the premature failure.
Shut-In Procedure while Drilling
While drilling, a drilling team must be carefully check for well control indicators and if the positive kick indicator(s) indicated, crew must instantly know how to shut in the well in correct manner. The steps below, called “3S” shutin procedures, demonstrate how to properly shut the well in while drilling.
Drilling shut in procedures (3S) – HARD SHUT IN PROCEDURE1. Space Out – Stop drilling, pick up drilling sting off bottom and space out to ensure that tool joint is not located
at BOP elements. 2. Shut Down – Stop mud pumps 3. Shut In - Close an annular preventer or an uppermost pipe rams. Use trip tank to verify that the flow is totally
stopped and the well is completely shut in. Then inform supervisors as drilling representative, tool pusher, OIM.
Shut-In Procedure while Tripping Tripping out of the hole is a critical operation, which drilling team must keep close eye on well control situation that can occur anytime. Wellbore monitoring and hole filling equipment and must be working properly so that the kick can be quickly detected. You must be aware of and prepared for the well control situation every tripping operation.
While tripping, it can cause swabbing effect that may allow formation fluid entering i nto wellbore. The well may not start to flow since th e swabbing effect is just started. The swabbing effect will result in reducing the overall hydrostatic pressure. If the well is continually swabbed-in until the hydrostatic pressure in the wellbore less than formation pressure, the well will start flowing. Any time that you see short fill while tripping out, you need to go back to bottom and circulate bottom up to confirm wellbore condition.
When the well control situation is happened during tripping operation, the drilling crew must shut the well in right away using the following “3 S” shut-in procedures.
Stab Valve: Install Full-Open Safety Valve (FOSV) that must be in an open position in dri ll string. Make up to
drilling string and close the safety valve. Space Out: Space out to ensure that tool joint must no locate in BOP element. Shut-in well: Close the annular preventer or uppermost pipe rams. Open the upper choke line valve against a
fully closed manifold valve at a choke manifold. Line up to trip tank to confirm that the well is shut-in and flow has been stopped.
How to Identify Stuck Pipe Mechanism
When a stuck pipe situation is happened, personnel on the rig must correctly identify a stuck pipe mechanism. Why is it so important to determine the mechanism of stuck pipe?
If you know cause of stuck pipe, you will be able to free you pipe correctly. However, if you cannot correctly identify a root cause of stuck pipe, you drill string may be in the hole forever!!!
Many people in the oil field including me use the guideline from the famous stuck pipe prevention book, named “TRUE”, which is belong to Amoco. It is extremely useful and so easy to understand. This is the stuck pipe table.
How can you use the table?
1. Select the situations that you see and circle all the figures in the same row. 2. Add all figures for each column 3. The highest score indicates the stuck pipe mechanism Let’s see the example Pipe motion prior to sticking? – The pip can be moved down before sticking = Move down (1, 0, 2)
Pipe motion after sticking? – The pipe has restriction while moving down= Down Restricted (1, 0, 2) Pipe rotation after sticking? – The pipe can be rotated freely after sticking = Rotate Free (0, 0, 2) Circulating pressure after sticking? – The circulation can be done without any pressure changes = Circulation Free (0, 2, 2) Total score = (2,2,8)
Boyle’s Gas Law and Its Application in Drilling Understand Boyle’s Gas Law
Boyle’s law states that at constant temperature, the a bsolute pressure and the volume of a gas a re inversely proportional in case of constant temperature within a closed system. It may sound pretty hard to understand what it is.
Well, we can describe the statement above i nto simple mathematics as following formula:
Boyle’s Gas Law: P x V = constant
Or express Boyle’s law in another term: P1 x V1 = P2 x V2 Where; P = Pressure and V = Volume It sounds easy a little bit to understand.
Let’s apply Boyle’s law into our drillin g business
Calculate the volume of gas you will have on the surface, 14.7 psi fo r atmospheric pressure, when 1 bbl of gas kick is circulated out from reservoir where has formation pressure of 3,000 psi.
Boyle’s Gas Law: P1 x V1 = P2 x V2
P1= 3000 psi (reservoir pressure)
V1 = 1 bbl (volume at bottom hole)
P2 = 14.7 psi (atmosphere pressure)
V2 = ? (volume at surface)
P1 x V1 = P2 x V2
3000 x 1 = 14.7 x V2
V2 = 204 bbl
2 Types of Shut-In (Hard Shut In and Soft Shut In)
For the drilling industry especially when we talk about well control, there are 2 types of shut in which areHard Shut-in and Soft Shut-in . This post will describe both shut in types and I wish I would be helpful for you all Hard shut in: It means that while drilling choke line valves (HCR) are in the closed position; it will be opened
after the well is shut in. The hard shut-in is the fastest method to shut in the well; therefore, it will minimize volume of kick allowed into wellbore. Soft Shut In: It means that while drilling, the choke line valves (HCR) are in the opened position. When the well
control situation is occurred, you shut in BOP and then close choke valves to shut in the well. The soft shut in procedure allows fluid to flow through the surface choke line before the well will be completely shut in.This is the bad part of the soft shut in procedure because it doesn’t minimize the size of the wellbore influx. The shut in procedure is the company specific procedure. You need to follow your company policy to shut in
the well. Anyway, I personally recommend “HARD SHUT IN PROCEDURE” because it allows me to shut well in as quickly as possible and kick volume entering into a well bore will be minimized. Please also remember that less volume of kick you have in the well bore, the less problem you will see when you attempt to kill the well.
What is Tertiary Well Control?
Can you imagine if primary and secondary well control are failed? Well is flowing all the time so how can we deal with this situation? For this situation, you must use Tertiary Well Control . Tertiary Well Control is specific method used to control well in case of failure of primary and secondary well
control. These following examples are tertiary well control:
Drill relief wells to hit adjacent well that is flowing and kill the well with heavy mud. Note: this case you
can study from PTTEP Austraila Blow Out Incident. They use this method to control the well that was
firing on the platform.
Dynamic kill by rapidly pumping of heavy mud to control well with Equivalent Circulating Density (ECD)
Pump barite or gunk to plug w ellbore to stop flowing
Pump cement to plug wellbore
What is Secondary Well Control?
Referring to the previous section, primary well control is hydrostatic pressure bore that prevents reservoir influx while performing drilling operations (drilling, tripping, running casing/completion, etc). Whenprimary well control is failed, it causes kick (wellbore influx) coming into wellbore. Therefore, this situation needs special
equipment which is called “Blow Out Preventer ” or BOP to control kick.
Shut in Procedures and Their Importance
Shut in Well Procedures
The shut in procedure must be developed and practiced for every rig activity such as:
• Shut in while drilling • Shut in while tripping • Shut in while running casing, tubing, completion, etc. • Shut in while performing workover operation • Shut in while logging • Shut in while performing drill stem test
What is the main reason why we need to have the shut in procedure and frequently practice it?
The main reason to have the specific shut in procedure is to minimize kick volume entering into wellbore when well control situation occurs. Basically, the faster to recognize kick and shut in a well, it is the
better to manage a well control situation. The amount of wellbore in flux that enters the wellbore are minimized when personnel respond quickly to shut the well in. It is the fact that a small amount of kick entering into wellbore will result in lower i nitial shut-in casing pressure and lower casing pressure while circulating. What’s more, the lower pressure at surface will reduce the chance of breaking down hole formation, generally called underground blowout. Who is responsible for shutting the well in?
Drillers are responsible for shut in the well. If any positive kick indications are observed, they must shut in the well first and confirm whether the well is correctly shut in or not. After that, they must inform supervisors on the rig.
It is not good practice if they see the positive kick indication and then he lets supervisors know instead of shutting in the well because the kick will be allowed to come into wellbore a lot.
What is “Drilled Gas”? While drilling, there will be a certain amount of the gas in cuttings entering into drilling fluid when we drill through porous formations that contain gas. The gas showing on the surface due to drill ing through formations is called “Drilled Gas”. When gas from the cutting comes into drilling fluid, it will expand as it is circulated out of hole, hence, you will see the gas from the monitors at the flow line. Even though we h ave overbalance hydrostatic pressure exerted by mud column, gas showing on the surface by this mechanism always happens. You cannot rise mud weight up to make it disappear.
Drilled gas should be recorded in mud log chart against formation identification. In addition, the gas unit should represent changes in drilling rate (rate of penetration) through porous formation.
Practically, if we see a lot of drilling gas, we should stop drilling and attempt to circulate gas until it reaches to an acceptable
What is “Background Gas”? While we are drilling, there is a stable gas reading that is not connected with either bottoms up gas or drilled gas is generally called “Background Gas ”. The background gas always shows every time while drilling and i t is not a sign of considerable risk to well control situation. Nevertheless, we must always check changes in background gas value because it is able to help recognize underbalance situation while drilling, especially drilling into high pressure zone. Remember – PLEASE ALWAYS KEEP TRACKING YOUR BACKGROUND GAS level prior to drilling ahead
Importance of Choke Drill and Its Procedure
Choke drill is one of well control drills that will improve crew competency in driller’s method. The advantages from the choke drill are as follows: • Get more familiar to p ractice controlling the pressure via a choke on the rig
• Get more understanding about lag time • Practice the procedure to obtain the shut-in drill pipe pressure • Ensure the surface well control equipment as p ressure gauges, choke, BOP is ready for work • Get more practices when attempting to bring the pump up to kill speed, slow the pump down and change th e pump rate Choke Drill Steps are listed below: 1. Trip in hole above top of cement
2. Fill the pipe and circulate seawater or mud around for few minutes 3. Close annular preventer or upper rams preventer 4. Pressure up annulus to 200 psi (the pressure may be different depending on the company policy.) 5. Line up the pump 6. Pump slowly to bump the float and obtain shut in drill pipe pressure 7. Bring the pump to kill rate by holding casing pressure constant – personnel need to adjust the choke 8. Measure lag time for the drill pipe gage after the adjustment of choke is made.
9. Change circulation rate by holding casing pressure constant. Crew needs to adjust choke to achieve this. 10. Shut the pump down by holding casing pressure constant. 11. Bleed off pressure and line up for drilling operation
BOP Stack Organization and BOP Stack Arrangement
Blow Out Preventor (BOP) is a very important part of well control equipment and the first thing which we would like to discuss in this article i s the BOP stack organization. The BOP stack can be configured in various configurations which must be suitable for the operation. API has the recommended component codes for BOP as listed below: A = Annular Preventer
G = Rotating Head R = single ram type preventer with one set of rams, blind or pipe. Rd = double ram type preventer with two sets of rams, blind or pipe. Rt = triple ram type preventer with three sets of rams, blind or pipe. CH = high remotely operated connector attaching well head or preventers CL = low pressure remotely operated connector attaching; the marine riser to the BOP S = spool with side outlet for choke and kill lines M = 1000 psi How can I know the BOP configuration and rating from the codes? When you see the code, you need to read upwards from the bottom of BOP stack. Let’s take a look at the following example: 15M 13-5/8” – RSRRA
This BOP stacks has pressure rating of 15,000 psi with a bore size of 13 -5/8” inch. There are following BOP component from bottom to top
Rams – Spool – Rams – Rams – Annular ( see the figure below)
You need to keep in mind that the BOP stack is able to shut the well in and allow you to perform well control operations with the greatest flexibility. Considerations of how to arrange the BOP stack are as follows: • The BOP stack must be suitable for the drilling operation. • The stack should be able to serve the stripping operation not just only shut the well in. • Pressure rating must be higher than expected surface pressure on surface when the well control situation is happened. • Excessive BOP rams cause difficulty to handle and maintenance. Additionally, the cost of BOP stack is more expensive. • Sour gas and temperature on surface directly affects the element in the BOP’s/ • The best BOP stack arrangement is the one that is suite for the operation w
Do you have too much slug in the well? Slug is heavy drilling mud that is used to pump when you want to pull pipe dry. However, excessive volume of slug in the well can create higher mud weight and cause the problem. Today I would l ike to share my experience regarding slug in the well. The situation happened on the drilling rig like this.
The well was TD with 13.0 ppg mud and circulation was conducted until the shale shakers. After that we pull 10 stands wet and pumped 40 bbl of 15.0 ppg slug and came out of hole without any problem. Then we run the logging and we got stuck. We picked the fishing gear and grabbed the fish. We pulled out 10 stands wet and hole was taking proper fill. We pumped same amount of slug 40 bbl of 15.0 ppg and came out of hole. The decision was made by town to trip in hole to do the wiper trip.
Tripping was done with caution and break circulation was conducted every 3000 ft to break the gel. Prior to TD 100 ft, we made up top drive and slowly washed down to TD. W hile we were circulating, the mud weight ou t was varied from 13.2 ppg to 14.2 ppg. Additionally, we start losing mud while circulating.
Do you know what went wrong?
The two slugs in the well cause us trouble.
How do you know that?
Let’s do the math. W e have total volume in the system (downhole volume and surface volume) of 700 bbl and we have total of 80 bbl of 15.00 pgg of slug.
The following formula is used to determine the final mud weight in the system.
(V1 x D1) + (V2 x D2) = VF x DF
Where; V1 = volume of fluid 1 (bbl, gal, etc.) D1 = density of fluid 1 (ppg,lb/ft3, etc.) V2 = volume of fluid 2 (bbl, gal, etc.)
D2 = density of fluid 2 (ppg,lb/ft3, etc.) VF = volume of final fluid mix DF = density of final fluid mix V1 = 80 bbl (Total volume of slug in the well) D1 = 15.0 ppg (density of slug) V2 = 700 bbl (Total system volume) D2 = 13.0 ppg (density of drilling mud) VF = V1 + V2 = 80 + 700 = 780 (80 x 15) + (700 x 13) = 780 x DF DF = 13.2 ppg
From the equation above, it tells us that we have too much slug in the well which can increase 0.2 ppg of total mud weight. The increment of mud density will directly affect the equivalent circulating density. This is the reason why we have losses while circulating.
Conclusion: Always ensure that you don’t have a lot of slug in the system or you need to prepare to dilute to
maintain the mud weight.
What are Lead and Tail Cement? In some cementing operation, operators will pump 2 cement slurries, normally called “Lead Cement” and “Tail Cement”. Both lead and tail cement have pro and con as described below.
Lead cement: Lead cement is in the top section of cement, where has lower both pressure and temperature (see
figure above). It has lower density and strength than Tail cement; however, it is also cheaper than Tail cement. Tail cement: Tail is pumped after lead cement because it must be settled at the lower section of well bore, where
needs high strength cement (see figure above) . It has higher strength than l ead cement, but it is more expensive than lead cement.
Round trip ton-miles Calculation
All types of ton-mile service should be calculated and recorded in order to obtain a true picture of the total service received from the rotary drilling line. There are several types of ton miles as foll ows; 1. Round trip ton -miles 2. Drilling or “connection” ton-miles 3. Coring ton-miles 4. Ton-miles setting casing 5. Short-trip ton-miles For this time, I will show how to calculate round trip ton-mile.
Round Trip Ton-Miles Calculation
The formula for round trip ton-miles is listed below; RTTM = (Wp x D x (Lp + D ) + (2 x D) x (2 x Wb + Wc)) ÷ (5280 x 2000)
where RTTM = Round Trip Ton-Miles Wp = buoyed weight of drill pipe in lb/ft D = hole measured depth in ft Lp = Average length per stand of drill pipe in ft Wb = weight of travelling block in lb Wc = buoyed weight of BHA (drill collar + heavy weight drill pipe + BHA) in mud minus the buoyed weight of the same length of drill pipe in lb ** If you have BHA (mud motor, MWD, etc) and HWDP, you must add those weight into calculation as well n ot just only drill collar weight. ** 2000 = number of pounds in one ton 5280 = number of feet in one mile Example: Round trip ton-miles
Mud weight = 10.0 ppg Average length per stand = 94 ft Drill pipe weight = 13.3 lb/ft Hole measure depth = 5500 ft Drill collar length = 120 ft Drill collar weight = 85 lb/ft HWDP length = 49 lb/ft HWDP weight = 450 ft BHA weight from directional driller = 8,300 lb BHA length = 94 ft Travelling block assembly = 95,000 lb Solution:
a) Buoyancy factor:
BF = (65.5 – 10.0) ÷ 65.5 BF = 0.847 b) Buoyed weight of drill pipe in mud, lb/ft (Wp):
Wp = 13.3 lb/ft x 0.847 Wp = 11.27 lb/ft c) buoyed weight of BHA (drill collar + heavy weight drill pipe + BHA) in mud minus the buoyed weight of the same length of drill pipe in lb (Wc):
Wc = {[(120x85) + (49x450) + (8300)] x 0.847} – [(120+450+94) x13.3x 0.847] Wc = 26,866 lb Round trip ton-miles = [(11.27 x 5500 x (94+ 5500)) + (2 x 5500) x (2 x 95000 + 26,866)] ÷ (5280 x 2000) RTTM = 258.75 ton-mile
Drilling or Connection Ton-Miles Drilling or Connection ton-miles is ton-miles of work in drilling operations. These are the actual ton-miles of
work in drilling down the length of a section of drill pipe, usually around +/ - 31 ft, plus picking up, connecting, and starting to drill again. In order to figure out connection or drilling ton -miles, it takes 3 times of ton-miles for current round trip minus ton-miles for previous round trip. The formula for calculating drilling ton mile is listed below; Td = 3 x (T2 – T1)
Where; Td = Ton-miles for drilling T2 = Ton-miles for one round trip of last depth before coming out of hole. T1 = Ton-miles for one round trip of first depth that drilling is started.
Example; Please determine drilling tome-miles from 8000 ft to 9000 ft. Ton-miles for trip @ 9000 ft = 230 Ton-miles for trip @ 8000 ft = 195 Td = 3 x (T2 – T1)
Td = 3 x (230 – 195) Td = 3 x 35 Td = 105 ton-miles
Ton-miles while making short trip The ton-miles of work performed in short trip operation is also in term of round trips.
The ton-miles of work done in making a short trip is equal to the difference between round ton-miles of end depth and starting depth. The formula for short trip ton-miles is listed below;
Tst = T6 – T5
Where; Tst = ton-miles for short trip T6 = ton-miles for one round trip at the deeper depth T5 = ton-miles for one round trip at the shallower depth Example;
Please determine short trip ton-miles from 8000 ft to 8050 ft Ton-miles @ 8050 ft = 200 Ton-miles @ 8000 ft = 190 Tst = (200 – 190) Tst = 10 ton-miles
Ton-Miles for Setting Casing For the setting casing operation, the ton-miles calculation of this operation is similar to round trip ton -miles calculation. Nevertheless, buoyed weight of the casing will be used into calculation instead of buoyed weight of drill pipe and with the result will be multiplied by 0.5, because setting casing is just only one-way operation (1/2 round trip). Ton-miles for setting casing can be determined from the following formula:
Tc = {Wp x D x (Lcs + D) + D x Wb} x 0.5 ÷ (5280 x 2000)
Where; Tc = ton-miles setting casing Wp = buoyed weight of casing in lb/ft Lcs = length of one joint of casing in ft Wb = weight of travelling block assembly in lb D = depth of casing in ft 2000 = number of pounds in one ton 5280 = number of feet in one mile Example: Ton-Miles for Setting Casing
Mud weight = 10.0 ppg Casing weight = 25.0 lb/ft Depth of casing = 5200 ft Travelling block assembly = 95,000 lb Length of one joint of casing = 42 ft Solution:
a) Buoyancy factor:
BF = (65.5 – 10.0) ÷ 65.5 BF = 0.8473 b) Buoyed weight of casing in mud, lb/ft (Wp):
Wp = 25.0 lb/ft x 0.8473 Wp = 21.18 lb/ft c) Casing ton-miles
Tc = {21.18 x 5,200 x (42 + 5,200) + 5,200 x 95,000} x 0.5 ÷ (5280 x 2000) Tc = 50.73 tone-miles
Understand U-Tube Concept and Importance of U-Tube We can likely use the behavior of one of the fluid columns to describe behavior regarding what is happening in another side of fluid column, if two fluid columns are connected at bottom. Basically, this situation is simply described in common oil filed name as “U Tube”. In oil field especially drilling business, “U Tube” can be considered as a string of pipe(drill pipe and tubing) is in a wellbore and fluids are able to pass inside of string of pipe (drill pipe and tubing) and the annulus (area between wellbore and string of pipe). The figure below demonstrates “U Tube” in our drilling business.
Why is U-Tube very important?
It is very vital to keep a basic concept of U-Tube in mind.
If there are two different fluids between inside of string and annulus, fluids always flow from a higher p ressure area to a lower pressure. If the system is NOT closed, lighter fluid will be flown out and it will be s topped when system pressure is stabilized (see figure below) .
If the system is closed, pressure must be the same at the bottom point where both sides of U-tube are connected. Therefore, drill pipe pressure and casing pressure (annulus pressure) will be responded based on
fluid in each side and formation pressure at bottom hole (see figure below).
Please always remember that U-Tube concept can be widely applied in many drilling and workover application such as well control, cementing, etc.
Bottom Hole Pressure Relationship This post will show you Lean about bottom hole pressure relationship because this concept is very important for well control concept. The bottom hole pressure is sum of all the pressure acting on the bottom hole. We can describe the statement before as the following equation; Bottom Hole Pressure (BHP) = Surface Pressure (SP) + Hydrostatic Pressure (HP)
The image below demonstrates the relationship of bottom hole pressure.
Note: BHP created by hydrostatic column of drilling fluid i s the primary well control in drilling.
Looking more into details,
If BHP is more than FP (formation pressure), this situation is called “Overbalance”. If BHP is equal to FP (formation pressure), this situation is called “Balance”. If BHP is less than FP (formation pressure), this situation is called “Underbalance”. For more understanding, please follow this example below demonstrating the relationship of BHP, SP and HP.
Bottom Hole Pressure (BHP) = Surface Pressure (SP) + Hydrostatic Pressure (HP)
We assume that formation pressure is normal pressure gradient of water gradient (0.465 psi/ft) so formation pressure at 8000’ TVD = 8000 ft x 0.465 psi/ft = 3720 psi. Click here to learn how to calculate h ydrostatic pressure in oilfield. The first case: Hydrostatic column is water which is equal to formation pressure gradient so SP is equal to 0 psi The second case: BHP is still be water gradient but fluid column is oil (0.35 psi/ft) which is lower density than
water gradient (0.465 psi/ft). Therefore, in order to balance BHP, we need Surface Pressure (SP) of 920 psi (SP = 3720 – (0.35 x 8000)). The third case: BHP is still be water gradient but fluid column is gas (0.1 psi/ft) which is even lower density than
water gradient (0.465 psi/ft). Therefore, in order to balance BHP, we need Surface Pressure (SP) of 2,920 psi (SP = 3720 – (0.1 x 8000)). According to the example, Surface Pressure (SP) will compensate the lack of hydrostatic pressure (HP) in order to balance formation pressure (FP) .
Critical RPM to Avoid Excessive Vibration When you operate top drive, you may need to know critical RPM that you can go. If you rotate pipe more than the critical RPM, it will create a lot of vibration that can cause failure in your drilling equipment such as drill pipe, TDS, etc.
In order to find out how much critical RPM, you may need high-tech simulation but sometimes you don’t really have that information supplied from town. So you really need to be able to roughly estimate how much critical RPM is ( at least you get a idea fo r this limitation). This formula below shows you how to estimate the critical RPM and it has accuracy of 15% roughly.
Critical RPM = 33,055 x (OD 2 + ID2)
1/2
Where; OD = drill pipe outside diameter in inch
÷ (L)2
ID = drill pipe inside diameter in inch L = length of one joint of drill pipe in feet Example: Determine critical RPM from these following information
L = length of one joint of drill pipe = 32 ft OD = drill pipe outside diameter = 4.0 in. ID = drill pipe inside diameter = 3.5 in. Critical RPM = 33,055 x (42+ 3.52)1/2 ÷ (32)2 Critical RPM = 172 RPM
Please remember this is ONLY estimation of the critical RPM. If you have your service companies or you have specific programs to determine it, please use the value from those programs because it should consider many parameters than this simple formula. USE IT IN CASE OF YOU HAVE NOTHING AVAILABLE TO CALCULATE THE CRITICAL RPM
Determine height of light weight spot pill to balance formation pressure When you get differentially stuck, you may consider spotting light weight fluid to reduce force created by differential pressure between mud in wellbore and formation pressure. However, you really need to understand and be able to calculate how much light weight fluid you can put in hole that it will not create a well control situation by accidentally underbalance formation pressure. Please follow the steps below to determine how height of light weight spot pill in the annulus to balance formation pressure.
a) Determine the difference in pressure gradient in psi/ft between the mud weight and l ight weight spot fluid: Difference pressure in pressure gradient in psi/ft = (current mud w t in ppg – light weight spot pill in ppg) x 0.052
b) Determine height in ft of light weight spot fluid that will balance formation pressure in the annulus: Height ft in vertical = overbalance pressure with current mud weigh in psi ÷ difference in pressure gradient in psi/ft
This height is the maximum allowable height of light weight spot pill in the annulus. If you have higher length of light weight spot pill in the annulus, it may create well control situation.
Example: Use the following data to determine the height in ft of light weight spot pill that will balance formation pressure in the annulus:
Mud weight = 13.0 ppg
Light weight spot pill = 8.3 ppg
Amount of overbalance = 300 psi
a) Difference in pressure gradient in p si/ft: Difference pressure in pressure gradient in psi/ft = (13 ppg – 8.3 ppg) x 0.052
Difference pressure in pressure gradient in psi/ft = 0.2444
b) Determine the height in ft of light weight spot liquid that will balance formation pressure in the annulus: Height = 300 psi ÷ 0.244 psi/ft
Height = 1227 ft
You must ensure than height of light weight pill in the annulus must less than1227 ft in order to prevent
.
wellcontrol situation
Calculate Annular Capacity Annular capacity is one of basic values that you really need to understand. This post demonstrates you how to
calculate annular capacity between casing or hole and drill pipe, tubing, or casing. There are several formulas as shown below to calculate annular capacity depending on unit of annular capacity required.
Note: Dh is bigger ID and Dp is smaller OD. The examples below will show the Dh as hole size and Dp is drill pipe OD
a) Calculate annular capacity in bbl/ft
Annular capacity in bbl/ft = (Dh 2 – Dp2) ÷1029.4
Example: Hole size (Dh) = 6-1/8 in.
Drill pipe OD (Dp) = 3.5 in. Annular capacity in bbl/ft = (6.1252 – 3.5 2) ÷1029.4 Annular capacity = 0.0245 bbl/ft b) Calculate annular capacity in ft/bbl
Annular capacity in ft/bbl = 1029.4 ÷ (Dh 2 – Dp2)
Example: Hole size (Dh) = 6-1/8 in.
Drill pipe OD (Dp) = 3.5 in. Annular capacity in ft/bbl = 1029.4 ÷ (6.125 2 – 3.5 2) Annular capacity = 40.743 ft/bbl c) Calculate annular capacity in gal/ft
Annular capacity in gal/ft = (Dh 2 – Dp2) ÷ 24.51
Example: Hole size (Dh) = 6-1/8 in.
Drill pipe OD (Dp) = 3.5 in. Annular capacity in gal/ft = (6.125 2 – 3.52) ÷24.51 Annular capacity = 1.031 gal/ft d) Calculate annular capacity in ft/gal
Annular capacity, ft/gal = 24.51 ÷ (Dh2 – Dp2)
Example: Hole size (Dh) = 6-1/8 in.
Drill pipe OD (Dp) = 3.5 in. Annular capacity in ft/gal = 24.51 ÷ (6.125 2 – 3.5 2) Annular capacity in ft/gal = 0.97 ft/gal Annular volume can be determined by this following formula;
Annular volume in bbl = annular capacity (bbl/ft) x length of annulus (ft) Note: annular volume can be expressed in several unit depending on unit that you use in the calculation.
Example:
Annular capacity = 0.0245 bbl/ft Length of annulus = 1000 ft Annular volume = 1000 x 0.0245 = 24.5 bbl. ** Please remember that if you have several annular profile, you must calculate volume based on each annular profile in order to get total annular volume.
Frictional Pressure Loss Components in the Rig Circulating System Frictional Pressure Loss: Frictional Pressure Loss is pressure loss created by fluid flowing through the flow
path. It is a function of fluid property (density, viscosity, gel strength), velocity of fluid, characteristic of flow path (hole size/drill string size). Frictional pressure loss affects on pump pressure because higher frictional pressure loss, higher pump pressure is required to maintain the pump rate. In order to clearly demonstrate the pressure loss component in the drilling rig system, the diagram below describes pressure loss each flow path of drilling fluid in the total rig circulation system.
The Diagram of Frictional Pressure Loss in Circulation System
Parameters, which affect pump pressure, are as follows: 1. Fluid properties especially mud weight, viscosity, gel strength and yield point affects directly on pump
pressure. Higher mud weight, viscosity, gel strength and yield point, higher pump pressure requires to maintain pump rate.
2. Pump rate is another factor that affects di rectly on pump pressure. This is a basic concept when higher pump
rate is needed; higher pump pressure is required. 3. Hole size/drill string size: Smaller internal diameter of both hole and drill string, higher velocity of fluid flow is
created at same pump rate. Higher velocity creates more frictional pressure loss. High pump pressure is required in order to maintain pump rate because there is additional pressure loss due to smaller hole size and drill string. 4. BHA and Bit: Due to small inner area, BHA and bit can cause majority of pressure loss. Hence, BHA
design/selection and bit nozzle selection are critical for hydraulic design. 5. Well Depth: The deeper of the well is, the more pressure loss will occur . It means we need more pump
capacity to achieve the drilling goal. Depth of the well is based on geological targets underneath the earth by geologists. This part will influence on how to select the proper rig capacity in order to meet hydraulic proposes of the wells
How to Determine Mud Motor Failure
Mud motor failure downhole may be happened from time to time. The questions that are usually raised are things like “How do I know if th e mud motor fails down hole?” and “What indications will I see that this has happened?” etc. Due to this, I would like to share my personal experience regarding mud motor failure and its symptoms.
The following signs indicate that you may be faced with downhole mud motor breakdown. Frequent Mud Motor Stall – Motor stall happens when the rotor of the mud motor has stopped moving.
Typically, the motor stalls only with a high differential of pressure. However, if the motor doesn’t perform as normal, it will get stalled with by a small amount of differential pressure. For instance, a mud motor n ormally drills at 400 psi differential pressure, but if the motor is stalled out with only 100 psi you can suspect the problem is with the motor. Pressure fluctuation while rotating – As you know, differential pressure it a set parameter while rotating d own,
not based on the weight on bit (WOB). Rotating with a good mud motor won’t create pressure fluctuations,
whereas a bad mud motor will show fluctuation in stand pipe pressure and you may not be able to maintain constant pressure. Abnormally high surface pressure – A stator is made of rubber. When the stator rubber is worn out and
breaking into pieces, small parts of rubber can jam the flow path in the motor. This situation also results in h igh stand pipe pressure. Reduction in Rate of P enetration – If there are no changes in formation and drilling pa rameters, the decreasing
in ROP (Rate of Penetration) may be caused by failure of the d own hole tool. Moreover, if the took is severely damaged, you will be able to drill any footage. What should you do if the problem is clearly identified?
The only thing you can do is pull out of the hole and change a new tool. It is almost impossible to drill with a damaged mud motor unless you only have a few feet to the well target depth.
With the mentioned indicators of mud motor failure above, you should be able to identify your suspected problem and begin troubleshooting as soon as possible to minimize non-productive time on a drilli ng rig.
Pump Pressure and Pump Stroke Relationship There is relationship between pump pressure and pump stroke that you really need to understand and be able to determine pump pressure after adjusting new pump stroke. There are 2 formulas used to determine pump pressure as shown in the detail below: 1st formula for estimating new circulating pressure (simple and handy for field use) New circulating pressure in psi = present circulating pressure in psi x (new pump rate in spm ÷ old pump rate in spm) 2 Example: Determine the new circulating pressure, psi using the following data:
Present circulating pressure = 2500 psi Old pump rate = 40 spm New pump rate = 25 spm New circulating pressure in psi = 2500 psi x (25 spm ÷ 40 spm) 2 New circulating pressure = 976.6 psi 2nd formula for estimating new circulating pressure (more complex)
For the 1st formula, the factor “2” is used but i t’s just the round up figure. If you want more accurate figure, you need to figure out an exact figure. So the 2nd formula has one additional formula to calculate the factor based on 2 pressure readings at different pump rate. Please follow these steps to determine new circulating pressure
1. Determine the factor ”n” and the formula to determine factor “n” is below:
Factor (n) = log (pressure 1 ÷ pressure 2) ÷ log (pump rate 1÷pump rate 2)
2. Determine new circulating pressure with this following formula. New circulating pressure in psi = present circulating pressure in psi x (new pump rate in spm ÷ old pump rate in spm) n Note: factor “n” comes from the first step of calculation.
Example: Determine the factor “n” from 2 pump pressure reading Pressure 1 = 2700 psi at 320 gpm Pressure 2 = 500 psi at 130 gpm Factor (n) = log (2700 psi ÷ 500 psi) ÷ log (320 gpm ÷ 130 gpm) Factor (n) = 1.872 Example: Determine new circulating pressure by using these following information and the factor “n” from above example: Present circulating pressure = 2500 psi Old pump rate = 40 spm New pump rate = 25 spm New circulating pressure, psi = 2500 psi x (25 spm ÷ 40 spm) 1.872 New circulating pressure = 1037 psi
What is Drilling Ton-Mile (TM)?
Drilling Ton-Mile is the work of drilling line that is commonly measured as the cumulative of the load lifted in tons and the distance lifted or lowered in miles. When the predetermined ton-mile l imit is reached, drilling contractors will perform slip and cut drilling line to prevent drilling line fatigue. When drilling line is spooled on and off a drawworks drum during operation as drilling a well, running casing, coring, etc.The drilling line get worn out; therefore, drilling contractors must cut old section and replace with new section of drilling line at specific period based on ton mile calculation.
The most worn area is the end of drilling lin e where is constantly spooled over the draw works drum. A section o f drilling line, typically around 100 ft, is cut then the drilling line is re -attached to the draw works drum and the amount cut off is spooled back on the drum. This operation is called “slip and cut drilling line”.
Note: Ton-mile is the important figure that must be recorded correctly. However,the most important is to visually
inspect drilling line all time to see if there is any worn out wire. If you see the worn out line, you need to cut the drilling line even though the drilling line does not reach ton-mile limit yet.
All types of ton-mile service should be calculated and recorded in order to obtain a true picture of the total service received from the rotary drilling line. There are several types of ton miles as foll ows;
1. Round trip ton-miles 2. Drilling or “connection” ton -miles 3. Coring ton-miles 4. Ton-miles setting casing 5. Short-trip ton-miles
Positive Kick (Wellbore Influx) Indications Positive kick (wellbore influx) indications mean indications showing almost 100% kick (wellbore influx) into
wellbore. Positive Kick Indicators While drilling 1. Increase in flow show – Without any increasing in flow rate in, increase in return flow indicates something
coming into wellbore while drilling. Therefore, flow show instrument provided by the rigs or service companies must be checked and calibrated frequently. 2. Increase of active pit system (Pit gain) - Because drilling fluid system on the rig is a closed system,
increasing in flow show without adjusting flow rate in will cause pit gain in a pit system. Nowadays, with high technology sensors, detecting change in pit level is easily accomplished at the rig site. However, visually check the pit level is importance as well for double checking figure from the sensors. Sometimes, change in pit l evel may be detected after the i ncrease in flow show because it takes more time to accumulate volume enough to be able to detect by pit sensors. 3. Continue flowing while the pumps are off – When pumps are turned off, bottom hole pressure will decrease
due to loss of equivalent circulating density (ECD). If there is any flo w coming after pumps off, it indicates formation influx into wellbore. Positive Kick Indicators While Tripping
There are 2 positive kick indicators while tripping as listed below;
1. Trip log deviation such as short fill up while tripping out and excess pit gain while tripping in. For
tripping operation, it is very important to have a filling system via trip ta nk that provides continuous hole fill all time. With utilizing that system, we can compare fluid that is filled in or returned from wellbore with steel volume of tubular (drill pipe, drill collar, BHA, tubing, casing, etc). If drilling fluid volume is less than theoretical pipe displacement while tripping out or more return fluid while running in, you need to flow check and monitor the well. o If flow check indicates wellbore influx, crew must quickly shut the well in.
o If flow check does not show any influx, drill string must be run back to bottom in order to circulate at least bottom up to ensure hole condition.
2. Positive flow when pipe is static. Every time that pipe in static condition. Trip tank with correct filling system
must be monitored all time by both rig personnel and mud logger. If volume in trip tank increases, personnel must confirm flow check and prepare to shut the well in.
Loss of Hydrostatic Pressure due to Lost Return In case of totally lost return, the annulus must be fully filled with fluid, normally water, as fast as we can. Water filled in annulus causes loss of hydrostatic pressure in the wellbore. This post demonstrates how to de termine hydrostatic pressure reduction due to fully filling water i nto annulus. There are two main concepts , annular capacity and hydrostatic pressure, applied to determine loss of hydrostatic pressure. Please follow concepts below. Number of feet of water in annulus Ft of water added = water added in bbl ÷ annular capacity in bbl/ft Bottomhole (BHP) pressure reduction
In order to calculate bottom hole pressure reduction, we assume the column of water in annulus is true vertical depth.
BHP decrease in psi = (current mud weight in ppg – weight of water in ppg) x 0.052 x (ft of water added) Equivalent Mud Weight at TD EMW in ppg = current mud weight in ppg – (BHP decrease in psi ÷ 0.052 ÷ TVD ft of hole)
Example: Determine bottom hole pressure loss and equivalent mud weight at TD due to filling up water into annulus.
Mud weight = 13.0 ppg Water added = 140 bbl required to fill annulus Weight of water = 8.6 ppg ** Annular capacity = 0.1422 bbl/ft Hole TVD = 6,000 ft ** If you fill lighter mud in hole instead of water, please adjust water weight to your mud weight. Number of feet of water in annulus Feet of water in annulus = 140 bbl ÷ 0.1422 bbl/ft
Feet = 984.5 ft Bottomhole (BHP) pressure reduction
BHP reduction = (13.0 ppg – 8.6 ppg) x 0.052 x 984.5 ft BHP reduction = 225.3 psi Equivalent mud weight at TD EMW in ppg = 13.0 – (225.3 psi ÷ (0.052 x 6,000 ft))
EMW = 12.3 ppg
Pressure and force relationship and applications
Pressure is force divided by cross section area (see an image below).
We normally use pressure in many units such as psi (pound pe r square inch), Pascal, kg/m3, etc.
In drilling operation, we mostly use circular area so area can be calculated by this formula;
Area = ¶ x (radius)2 or ¶ x (diameter)2÷ 4 Where ¶= 22/7 = 3.143, so we can write a formula above in easy way
Area = 3.143 x (radius)2 or 0.7857 x (diameter)2 Pressure = force ÷ (3.143 x (radius) 2) or force ÷ (0.7857 x (diameter) 2)
Let’s try to apply pressure and force relationship in drilling operation. We plan to bullhead well and we still have drill string in the hole.
Drill string weight in the air = 45,000 lb Mud weight in hole = 12.0 ppg Bit size = 8.5” Drill pipe size = 5″
What is the maximum pressure at surface you can apply before drilling string will be blow out due to bullheading pressure.
Buoyancy factor = (65.5 – 12.0) ÷ 65.5 = 0.817 Buoyed weight of drill string = 45,000 x 0.817 = 36,765 lb
Area = 0.7857 x (diameter)2= 0.7857 x (8.5)2= 56.77 square inch Pressure = 36,765 lb ÷ 56.77 square inch= 647 psi. In order to perform safe bullheading operation with drill string in hole, you need to apply bullheading pressure less than 647 psi on surface.
Annular Velocity and Its Importance to Drilling Hydraulics Annular velocity is the speed of fluid moving up the annulus and it must be high enough to transport cuttings generated while drilling from the wellbore. However, if the annular velocity is too high, it can create hole wash out and excessive equivalent circulating density. When the drilling mud is circulated through a system, the moving speed is lower at location where the cross section area is bigger. Conversely, when the fluid flows through the small cross section area, the annular velocity at that point is higher.
The cross section area around drill collar and BHA has the smallest area so the annular velocity is the highest.
(Annular velocity around drill collar and BHA)
On other hand, the area around drill pipe has the biggest cross sectional area, hence, the speed of fluid around the drill pipe area is smallest.
(Annular velocity around drill pipe)
The annular velocity around drill pipe must be used to determine if it is good enough for hole cleaning because it is the lowest velocity in the wellbore. If the annular velocity around the drill pipe is good enough for hole cleaning purpose, it will definitely be sufficient for hole cleaning around drill collars, BHA and tool joints.
If you have some formations which can be easily washed out, you need to look at the annular velocity around drill collars, BHA and tool joints. The size of drill collars and BHA should be reduced if the flow rate can cause excessive wellbore erosion.
To adequately transport the cuttings from the wellbore, the annular velocity is affected by mud properties, rate of penetration, mud types, formation types, hole angle, size of cuttings, etc.
A formula for the annular velocity in an oilfield unit is shown below:
Where
Va = annular velocity, ft/min
Q = flow rate, gallon per minute
Dh = hole diameter, inch
Dp = outside diameter of drill pipe, inch
Pump Output Calculation for Duplex Pump and Triplex Pump Rig pump output , normally in bbl per stroke, of mud pumps on the rig is important figures that we really need to
know because we will use pump out put figures to calculates many things such as bottom up strokes, wash out depth, tracking drilling fluid, etc. In this post, you will learn how to calculate pump out put for triplex pump and duplex pump. Triplex Pump Output Formula
Triplex Pump Output in bbl/stk = 0.000243 x (liner diameter in inch) 2 X (stroke length in inch) Example: Determine the pump output in bbl/stk at 100% and 97% efficiency
Linner size = 6 inch Stroke length = 12 inch Triplex pump output: PO @ 100% = 0.000243 x 62 x 12 PO @ 100% = 0.104976 bbl/stk Adjust the triplex pump output for 97% efficiency: Decimal equivalent = 97 ÷ 100 = 0.97 PO @ 97% = 0.104976 bbl/stk x 0.97 PO @ 97% = 0.101827 bbl/stk
Duplex Pump Output Formula
Duplex Pump Output in bbl/stk = 0.000162 x S x [2(D)2 - d2]
Whrere: D = liner diameter in inch S = stroke length in inch d = rod diameter in inch Example: Determine the duplex pump output in bbl/stk at 100% and 85% efficiency
Liner diameter = 6 inch Stroke length = 12 inch Rod diameter = 2.0 in. Duplex pump efficiency = 100 %. PO @ 100% = 0.000162 x 12 x [2 (6) 2 -122 ] PO @ 100% = 0.13219 bbl/stk Adjust pump output for 85% efficiency: PO @ 85% = 0.132192 bbl/stk x 0.85 PO @ 85% = 0.11236 bbl /stk
Formation Integrity Test (FIT) Procedure and Calcualtion Formation Integrity Test is the method to test strength of formation and shoe by increasing Bottom Hole
Pressure (BHP) to designed pressure. FIT is normally conducted to ensure that formation below a casing shoe will not be broken while drilling the next section with higher BHP or circulating gas influx in a well control situation. Normally, drilling engineers in town will design how much formation integrity test pressure required mostly in ppg. The formula below demonstrates you how to calculate required FIT pressure.
Pressure required for FIT (psi) = (Required FIT in ppg – Current Mud Weight in ppg) x 0.052 x True Vertical Depth of shoe in ft Example:
Required FIT (ppg) = 14.5 Current mud weight (ppg) = 9.2 Shoe depth TVD (ft) = 4000 TVD Pressure required for FIT = (14.5-9.2) x 0.052 x 4000 = 1102 psi Formation Integrity Test (FIT) guideline is listed below: (note: this is just only guide line. You may need to follow your standard procedure in order to perform formation integrity test):
1. Drill out new formation few feet, circulate bottom up and collect sample to confirm that new formation is drilled to and then pull string into the casing.
2. Close annular preventer or pipe rams, line up a pump, normally a cement pump, and circulate through an open choke line to ensure that surface line is fully filled with drilling fluid.
3.Stop the pump and close a choke valve.
4. Gradually pump small amount of drilling f luid into well with constant pump stroke. Record total pump strokes, drill pipe pressure and casing pressure. Pump until casing pressure reaches the pressure required for formatin integrity test. Hold pressure for few minutes to confirm pressure.
5. Bleed off pressure and open up the well. Then proceed drilling operation.
Free BOP Drawing Template I’ve found the free BOP drawing template which might be advantageous for you all. This template was created by Benny Mason.
Valves and BOP component.
Riser, RAMs BOP, Annular Preventer, Spool
BOP stack, Small BOP for wireline and riser
Manifold and series of valves.
Calculate Specific Gravity (SG) in oilfield unit
You may need to calculate specific gravity from different density or p ressure gradient units. This post demonstrates you about specific gravity calculation and specific gravity formulas frequently used in oilfield business. 1. Calculate specific gravity using mud weight in PPG
Specific gravity formula : SG = mud weight in ppg ÷ 8.33 Example: Fluid = 13.0 ppg SG = 13.0 ppg ÷ 8.33 SG = 1.56 2. Calculate specific gravity using pressure gradient in psi/ft
Specific gravity formula : SG = pressure gradient in psi/ft ÷ 0.433 Example: pressure gradient = 0.50 psi/ft SG = 0.50 psi/ft ÷ 0.433 SG = 1.15
3. Calculate specific gravity using mud weight in lb/ft 3
Specific gravity formula : SG = mud weight in lb/ft 3 ÷ 62.4 Example: Mud weight = 90 lb/ft3 SG = 90 lb/ft3÷ 62.4 SG = 1.44
Well, we can call that “Blow Out Preventer” or BOP is Secondary Well Control . Please also remember that BOP must be used with specific procedures to control kick such as driller method, wait and weight, lubricate and bleed and bull heading. Without well control practices for using BOP’s, it will just be only heavy equipment on the rig. There are several types of “Blow Out Preventer” (BOP) which have different applications. I will talk about BOP categories later.
Fishing Drill Pipe Procedure – Screw in Drill Pipe Sometimes drillpipe is accidentally dropped into the well and you need to fish it out of the well. One easy option that may be feasible to perform is to use a drill string to screw into the drill pipe in the well.
Before going into a detailed procedure, you may need to check the following conditions.
• Tight clearance between hole and tool joint
• Tool joint at the top of fish is in a good condition
Data that you need to know before going to fish the drill string
• Fish length
• Top of fish
• Weight of fish in the mud
• Actual turn to fully engage when screw in
Detailed procedure for fishing drill pipe by screwing into the fish
Fish length = xxx ft
Expected TOF = xxx ft
Weight of the fish (BHA + DP) = xx Klb
1. Trip in hole 1 stand
2. Count the actual turn of drill pipe
3. Run in hole to xxx MD (200 ft above the Top Of Fish)
4. Make up top drive
5. Break circulate with 160 GPM using current drilling fluid in the well
• Record pressure
6. Record pick up and slack off weight without rotation
7. Record pick up and slack off weight with 20 RPM
8. Record torque with 20 RPM
- In the steps 5-8, you will get the base line values when the drill string does not engage with another part. 9. Slowly run in hole without rotation
