This is a very good book for well control “Wild Well Control’s Technical Data Book” which is a quick reference book of formulas, charts and tables.
I’ve found that it is very useful because it contains a lot of useful information as formulas, table, technical specification, etc.
You can download this electronic version by clicking the following link.
The diverter is an annular preventer with a large piping system underneath. It is utilized to divert the kick from the rig and it can be used when the conductor pipe is set. It is not used if you drill riserless. The large diameter pipe typically has two directions diverting the wellbore fluid out of the rig (see the figure below for more understanding).
The diverter should be used only when the well cannot be shut in because of fear of formation breakdown or lost circulation. Use of the diverter depends on the regulations and operator policies.
The diverter is normally installed on a conductor casing with large diverter pipe pointing to a downwind area. Typically, the selective valves located at each diverter line can be operated separately so the personnel on the rig can divert the flow into the proper direction. It is designed for short periods of high flow rate but it cannot hold a lot of pressure. With high flow rate, the erosion can be happened easily so the bigger of diverter line the better. Additionally, the straight diverter lines are the most preferable.
In the market, there are several models provided by service providers as
Hydril Pressure Control FSP* 28-2000 Diverter
http://www.ge-energy.com/products_and_services/products/capital_drilling_equipment/hpc_fsp_28_2000_diverter.jsp
Hydril Pressure Control FS™ 21″ 500-psi Marine Riser Diverter
http://hydrilpressurecontrol.com/pressureControl/diverters/diverters-FS.php
Reference book: 
Well Control Books
I’ve got the useful SHELL well control kill sheet. It is really handy for drilling people.
Please find the download at the end of the blog post.
There are 5 parts in the kill sheets.
Bull heading
Subsea Kick Control
Surface Kick Control
Conventional Circulation
Reverse Circulation
I wish this kill sheet would be beneficial for your work on the rig.
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 order 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 the 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)
Well control quiz ebooks here -> 
http://amzn.to/WjtEvd
Reference book: Well Control Books
This article will demonstrate how to perform volume metric well control. There are a total of 5 steps as listed below;
Step 1 – Calculation
Three calculations must be determined before conducting volumetric well control.
1. Safety Factor (SF) – The Safety Factor (SF) in an increase in bottom hole pressure which we allow to happen naturally when gas influx migrates up with the shut in well. SF is important because it will allow the bottom hole pressure to be over formation pressure so the well is not in underbalance condition while conducting later steps. Typically, SF is around 50 – 200 psi. If the initial shut in casing pressure is very close to maximum allowable surface pressure. Personnel must select small safety factor to prevent fracturing formation.
2. Pressure Increment (PI) – It is pressure used as a working pressure while conducting Volume Metric well control. This pressure will be equal amount of hydrostatic pressure of mud bled during each step.
3. Mud Increment (MI) – It is volume of mud bled off from the annulus to reduce hydrostatic pressure by amount of Pressure Increment. It is very important that the rig must have an accurate measurement to measure small amount of mud bled from annulus. Mud Increment is determined by the following equation:
Where;
Mud Increment is in bbl.
PI is pressure increment in psi.
ACF is annular capacity factor in bbl/ft
MW is mud weight in ppg.
Step 2 – Allow Casing Pressure To Increase To Safety Factor Plus Pressure Increment
After the first step is completed, the 2nd step is to wait until casing pressure increases by an amount equal to Safety Factor (SF) plus Pressure Increment (PI). At this stage, the bottom hole pressure will increase by surface pressure but hydrostatic pressure is still the same.
For example, if SF is 100 psi and PI is 100 psi, we need to wait until casing pressure increase by 200 psi.
Step 3- Hold Casing Pressure Constant While Mud Increment Is Bled Off
Since we have the overbalance in step-2, in order to keep raising casing pressure due to gas migration, hydrostatic pressure must be taken out by bleeding off mud volume. This step will bleed off amount of mud equal to mud increment. Bleeding mud with constant casing pressure is performed to ensure that the bottom hole pressure is decreased by a loss of hydrostatic pressure only. Failure to keep casing pressure constant while bleeding off mud results in reduction of the bottom hole pressure. This can lead to more severe well control problem.
Every bleed off volume (mud increment) will reduce the bottom hole pressure by the amount of Pressure Increment. Once the bleed off is complete, the bottom hole pressure will be over balance by the safety factor.
Step 4 – Wait For Casing Pressure To Increase By Pressure Increment
At this step, we must wait to gas to migrate up until the surface casing pressure increase by Pressure Increment. When this step finishes, the bottom hole pressure will increase by the amount of Pressure Increment therefore the bottom hole pressure will be over balance by the amount of Safety Factor plug Pressure Increment.
Step 5 – Repeat Step 3 and Step 4 Until The Gas Migrates To Surface
The rest of volumetric well control is to repeat step#3 and step#4 until the gas finally migrates all the way to surface. During each step of bleeding off, the gas bubble expands and its pressure decreases. By the time, the gas reach at surface, the gas pressure will greatly reduce and its volume increases according to Boyles’ Laws.
Well control quiz ebooks here => http://amzn.to/WjtEvd
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 than formation pressure therefore the well. For this case, the well will flow during transition period.
Ref books: 
Cementing Technology Books
Formulas and Calculations for Drilling, Production and Workover, Second Edition
I would like to share these 3 VDO’s demonstrating how Pipe Rams, Variable Bore Rams and Shear Rams work.
This eliminate confusion when the new people in the oilfield read and try to understand about these rams.
Pipe Rams – You will see that the pipe rams will work only on size of the drill string.
Shear Rams – Both rams will be pushed against each other resulting cutting the string of the pipe.
Variable Bore Rams (VBR) - Most of the rigs prefer to use the VBR instead of the fixed pipe rams because its flexibility to work with various pipe size in the wellbore.
You can read more details about the rams preventer via this article -> Ram Preventers as Well Control Equipment
We wish you would enjoy learning this topic.
Well control quiz ebooks here -> http://amzn.to/WjtEvd
Reference book: Well Control Books
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.
1st case – Gas at the bottom
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.
We wish this article could help you get more understanding about Kick Tolerance.
Ref book: Formulas and Calculations for Drilling, Production and Workover, Second Edition
These are some footage showing some oil drilling rigs were blown out and got fired. I would like to share these VDO clips to raise awareness of well control.
Oil Rig Blowout
Chesapeake Energy Nomac Rig 17 Blowout Fire
Workover Rig Blows Out Tubing
BWD Rig 136 Blowout , Rawdatain, north Kuwait
Actinia Oil Rig Blowout – shallow gas blowout
Camera captured the shallow blowout to the rig floor
Drilling rig Accident: Blowout, Rig Burns down (Ensign #59)
BBC Stephen Fry And The Great American Oil Spill
If you are interested in well control articles, please check out our link -> http://www.drillingformulas.com/category/well-control/
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.
The following VDO will demonstrate you the mechanism of each type of drilling float valve.
Riser margin in the mud weight increase below mud line to compensate bottom hole pressure in case of an accident disconnect or a failure marine riser close to the BOP stack at sea bed.
The riser margin is described by a following equation:
Where;
ρrm is riser margin, ppg
ρdf is drilling fluid density equivalent to formation pressure, ppg
ρsw is sea water density, ppg
L is riser length from sub sea BOP to rig floor, ft
D is true vertical depth of the well, ft
DW is water depth, ft
Note: When you consider adding the riser margin, you need to make sure that formation strength is sufficient. Additionally, you must not add trip margin and riser margin to the system because it is way over safety factor. If trip margin is higher than the riser margin, you must use the trip margin.
Example: Determine riser margin for this case.
Drilling fluid weight equivalent to formation pressure = 9.2 ppg.
Sea water weight = 8.6 ppg
Length of riser to the rig = 8000 ft
Well TVD = 13,000 ft
Water depth = 8,000 ft
ρrm = 1.2 ppg
Riser margin for this case is 1.2 ppg.
Reference book: Well Control Books
This is very bad news “ Hercules Jackup Rig 265 Blows Out In Gulf Of Mexico and 44 People Evaculated”. The details that I gather from several sources on the internet. This is the reason why well control is very important to us.
July 23rd, 2013
Forty-four workers were evacuated from a natural gas platform in the Gulf of Mexico on Tuesday after a blowout occurred, according to officials.
Crew members aboard the Hercules 265 were preparing the well for production when they hit an unexpected pocket of gas.
No injuries were reported.
Officials had said earlier that 44 workers were evacuated.
While gas is flowing from the well, “no oil is being released,” according to the Bureau of Safety and Environmental Enforcement.
The platform, about 60 miles southwest of Grand Isle, Louisiana, is leased by Houston-based Walter Oil & Gas Corporation. The company did not respond to CNN’s requests for comment Tuesday.
A light sheen about a half-mile wide was spotted by environmental inspectors, but was “dissipating almost immediately,” the safety bureau said.
Source: CNN http://www.cnn.com/2013/07/23/us/gulf-rig-evacuation/index.html?hpt=us_c2
UPDATE: July 24th, 2013
Hercules 265 is now on fire.
The fire started about 10:50 p.m. local time yesterday.
Experts from Wild Well Control Inc. were to assess the well site overnight and develop a plan to shut down the flow of gas, said Jim Noe, executive vice president of Hercules Offshore Inc., owner of the drilling rig where the blowout occurred.
Noe stressed that gas, not oil, was flowing from the well. He said it is an important distinction because gas wells in relatively shallow areas — this one was in 154 feet (47 meters) of water — sometimes tend to clog with sand, effectively snuffing themselves out. “That is a distinct possibility at this point,” he said. “But until we have our Wild Well Control personnel on the rig, we won’t know much more.”
Tuesday’s blowout occurred near an unmanned offshore gas platform that was not currently producing natural gas, said Eileen Angelico, spokeswoman for the bureau. The workers were aboard a portable drilling rig known as a jackup rig, owned by Hercules, which was a contractor for exploration and production company Walter Oil & Gas Corp.
Walter Oil & Gas reported to the BSEE that the rig was completing a “sidetrack well” — a means of re-entering the original well bore, Angelico said.
The purpose of the sidetrack well in this instance was not immediately clear. A spokesman for the corporation didn’t have the information Tuesday night. Industry websites say sidetrack wells are sometimes drilled to remedy a problem with the existing well bore.
“It’s a way to overcome an engineering problem with the original well,” Ken Medlock, an energy expert at Rice University’s Baker Institute said. “They’re not drilled all the time, but it’s not new.”
Walter Oil & Gas Corp., the owner of the well, initially said it appeared that some of the shear rams on the rig’s blowout preventer failed to close and seal off the well. The company later said it is still investigating the incident and wouldn’t know the cause of the blowout, or why the well continues to flow, for some time.
“The crew was concerned for their safety, so once gas was detected and they felt like they did all they could do to shut in the well, they evacuated,” Mr. Noe said.
I’ve collected several sources of Hercules 265 Blows Out. You can read the update here.
CIMB: Fire subsides after gulf rig partially collapses
A Gulf of Mexico drilling rig partially collapsed off the coast of Louisiana after catching fire because of a ruptured natural gas well, U.S. regulators said on Wednesday.
The blaze broke out after a blowout on the Hercules 265 natural gas platform at around 10:45 p.m. local time Monday.
Eileen Angelico, a spokeswoman for the Bureau of Safety and Environmental Enforcement, said no one was on board when the fire started and it was not known what sparked it. She said an investigation into the cause of incident was “well under way.”
Yahoo NEWS: Gulf rig partially collapses in fire off Louisiana: U.S. government.
HOUSTON (Reuters) – A shallow-water Gulf of Mexico drilling rig has partially collapsed off the coast of Louisiana after catching fire because of a ruptured natural gas well, U.S. regulators said on Wednesday.
The U.S. Bureau of Safety and Environmental Enforcement said beams supporting the derrick and rig floor on the Hercules Offshore jackup rig had crumpled over the rig structure.
A third firefighting vessel was en route to the scene, though no sheen was seen on the water’s surface during overflights conducted on Wednesday morning, the regulator said.
More details => http://news.yahoo.com/gulf-rig-fire-natural-gas-flows-ruptured-well-145808123.html
Rig Zone: Natural Gas Well Bridged; Hercules Rig Fire Continues
The flow of natural gas has been contained at a natural gas well located in 154 feet of water 55 miles offshore of Louisiana at South Timbalier, Block 220, the Bureau of Safety and Environmental Enforcement (BSEE) said in a statement to the press July 25
More details here => http://www.rigzone.com/news/oil_gas/a/127991/Natural_Gas_Well_Bridged_Hercules_Rig_Fire_Continues
Rig Zone: Fire Out on Hercules Rig and Natural Gas Well, Gas Flow Halted
The natural gas well blowout and fire earlier in the week that spread to a jackup, causing part it to collapse, has gone out. The well owner and governmental organizations have set up a Unified Command to secure the well, the Bureau of Safety and Environmental Enforcement (BSEE) said in a release Friday.
Firefighting vessels remain on the scene, working with the well owner, the rig owner, the U.S. Coast Guard, Wild Well Control, and other relevant parties, BSEE said.
More details here => http://www.rigzone.com/news/oil_gas/a/128040/Fire_Out_on_Hercules_Rig_and_Natural_Gas_Well_Gas_Flow_Halted
BP is to appeal $1billion of compensation payments for its Gulf of Mexico oil spill, after lashing out at ‘absurd’ claims by US law firms cashing in on the disaster.
The British oil giant yesterday increased its estimate of the total bill for the 2010 disaster to an eye-watering £27.7billion.
Some £6.3billion of the total is made up of claims by people who say the accident cost them money, many of them fishermen, hoteliers and restaurant owners.
But BP is set to battle ‘fictitious’ claims by ‘greedy’ lawyers looking to use the oil company as a cash machine.
The explosion happened on 20 April 2010 triggering the worst oil spill in US history. BP says it will fight fanciful legal claims over the accident
‘No company would agree to a settlement that pays businesses that suffered no losses,’ said chief executive Bob Dudley.
‘We want everyone to know that we are digging in and are well-prepared for the long haul on legal matters.’
Mr Dudley took the reins at BP in 2010 after an explosion ripped through its Deepwater Horizon rig in the Gulf of Mexico, killing 11 people and triggering the worst oil spill in U.S. history.
He replaced gaffe-prone predecessor Tony Hayward, who infamously enraged Americans as the disaster unfolded by declaring: ‘I’d like my life back.’
And Mr Dudley has proved a far more popular figure in the US, particularly given his roots in the Gulf Coast state of Mississippi.
Many of the claims are from businesses directly affected by the accident
But the American sought to show he was no pushover, warning that BP would take its appeal against ‘absurd’ claims all the way to the Supreme Court if necessary.
He pointed out his duty to protect the interests of investors in BP, a major component of the pension funds that will help millions of Britons through their retirement.
‘BP shareholders, of which there are many in the UK – and the dividends from this company are so important here – should be unhappy, just as they should be in the US,’ he said.
Mr Dudley added that the Gulf of Mexico compensation process was ‘curious and somewhat out of control’.
He lashed out at America’s litigation culture, saying that inflated claims against BP were a symptom of a wider problem.
He cited a claim by residents of Oklahoma against weathermen who failed to predict the devastating tornado that ripped through the US state earlier this year, killing 23 people and injuring 377 more.
And he said he was recently invited to join a £15million lawsuit against Southwest Airlines over its failure to provide free drinks coupons that it had advertised.
‘There’s something wrong with this system,’ he said.
‘The precedent is not good for America.’
Mr Dudley’s comments have been spurred by a sudden surge in claims by law firms winning compensation not just for their clients, but for themselves.
The compensation fund is administered by a judge, meaning BP has no control over who is deemed eligible for a payment.
Since BP agreed to settle, administrators of the settlement fund have paid an average £527,000 to more than 300 law firms, adding up to more than £160million in total.
But in the past week the average claim by a law firm has spiralled to nearly £1million, while one firm secured a £10million payment for itself.
The cash windfalls come on top of any fees charged to ordinary claimants such as shrimp farmers and hoteliers, who typically forfeit up to 25 per cent of their payouts to lawyers acting on their behalf.
A dam erected at Grand Isle, Louisiana, to protect the island’s beaches from oil that washes ashore from the Deepwater Horizon oil rig explosion and spill in the Gulf of Mexico
The rough ride given to BP contrasts with the treatment of US construction giant Halliburton, which made the cement on the British firm’s doomed well.
Halliburton has agreed to pay a fine of just $200,000 after it was found to have destroyed evidence from tests it performed on the quality of the cement used in the well.
But the financial hit is dwarfed by BP’s own costs, which it has warned could rise beyond the £27.7billion it has set aside.
BP has previously warned it faces a ‘feeding frenzy’ of lawyers, while the firm’s US head of communications last week said the firm’s efforts to meet its obligations were being exploited.
‘The Deepwater Horizon settlement could have been a model for resolving lawsuits after industrial accidents,’ said Geoff Morrell.
‘Instead it’s running into a monument to plaintiffs’ lawyers’ greed.’
BP intends to appeal against some £650million of payouts in total, with claims by law firms believed to make up nearly half of the total.
Source:DailyMail
I would like to share this NEWS.
A drilling rig owned by Nabors Drilling USA blew out and caught fire Wednesday evening just before 7 pm while drilling an Eagle Ford Shale horizontal well for EOG Resources in Lavaca County, Texas.
The well control incident occurred at Farm to Market 966 and State Highway 111 near Petersville, Texas. No injuries were reported.
Well control specialists from Houston have been called to put out the rig fire and conduct an investigation according to Shiner Volunteer Fire department Chief Mark Panus.
A nearby resident, who asked not to be identified, said her husband was in the front yard with their 4 year-old son at the time of the explosion and saw workers running. When he asked workers what happened the workers kept running so he too grabbed their son and ran, she said.
Ref: http://www.drillingahead.com/page/nabors-rig-blows-out-while-drilling-for-eog-resources-in-eagle-fo
International Association of Drilling Contractors (IADC ) is one of important organizations in drilling industries.
One of their main contributions is well control. IADC has the well control courses and material that are very useful to all people in the drilling industry. Besides IWCF, IADC also distributes their kill sheets to everyone and you can find the download links down below.
Wait and Weight well control
Wait and Weight Surface Stack
Wait and Weight Method – Field units (US Customary)
Wait and Weight Method – Metric units
Wait and Weight Method – SI units
Wait and Weight Subsea Stack Version
Subsea Stack Wait and Weight Method – Field units (US Customary)
Subsea Stack Wait and Weight Method – Metric units
Subsea Stack Wait and Weight Method – SI units
IADC – Kill sheet for bullheading
Bullheading draft killsheet, Field units (US Customary)
Bullheading draft killsheet, Metric system
Bullheading draft killsheet, SI units
Driller’s Method well control - Draft version
Driller’s Method – Field units (US Customary)
Driller’s Method – Metric units
Driller’s Method – SI units
In some special well control cases, you will not be able to circulate kick out of the well then the kick is brought up to the surface using special well control procedure like “Volume Metric Method”. At this point, surface pressure is the height because of decreased hydrostatic pressure in the well bore.
How can we remove the gas out of the well bore without allowing more influx coming into the well bore for this scenario?
This is the time that we must perform a special well control procedure called “Lubricate and Bleed”. Lubricate and bleed procedure is the way to remove the gas when the circulation is impossible to conduct. The basic theory is the same as Volumetric Well Control Method but it is just a reverse process. Surface pressure will be replaced with hydrostatic pressure by pumping drilling fluid into the wellbore. The gas and drilling mud are allowed to swap the places and amount of surface pressure will be bled off later.
If you use the current mud weight to perform the lubricate and bleed procedure, the well will not be killed and there is remaining surface casing pressure. Only surface casing pressure will be decreased to where it balances to formation pressure. In many cases, it is sometimes desirable to pump heavier mud in to the wellbore and hopefully it will kill the well too.
You will wonder why I use the phase “hopefully kill the well”. The reason is you may not have enough hydrostatic height to create extra hydrostatic head to just balance the formation pressure. This is based on case by case.
The lubricate and bleed procedure is listed in the following steps:
Step 1 – Determine hydrostatic pressure
Determine hydrostatic pressure of 1 bbl (I use the oil field unit) of mud that will be pumped into the well.
Step 2 – Lubricate
Slowly pump a desired volume into the well. The amount of volume depends on well conditions and it may change during the process. Increasing in surface pressure can be estimated by utilizing Boyle’s Laws (P1V1 = P1V2) and every one bbl of mud pumped into the well, the gas size is reduced by one bbl.
During lubricating, surface casing pressure will be definitely increase. The amount of pressure increase will depend on the volume of gas being compressed. Small pressure increase indicates large volume of gas. Additionally, Maximum Allowable Surface Casing Pressure (MAASCP) will reduce because the increase in hydrostatic pressure during lubrication. Since gas volume also decreases every time that gas is bled off, you may reach the point to stop lubricating operation in order to prevent breaking out the wellbore. At this point you will have gas in the wellbore but the lubricate and bleed procedure cannot be performed any more. In order to know this figure, you may need to play with the kill sheet to find this stopping point. By adjusting parameters in the kill sheet, you can minimize this issue.
Step 3 – Wait
Wait for awhile to allow gas and mud swapping out. Drilling mud properties as mud weight and rheology affects on this step. You need to be patient.
Step 4 – Bleed off pressure
Bleeding gas from the surface until the amount of pressure is equal to hydrostatic pressure of mud pumped in hole. If you know that you lubricate in 50 psi, only 50 psi of gas must be bled off. It is very important to bleed only gas. During this process if you see mud on surface, you must stop and allow gas to swap out. For instant, you plan to bleed a total of 50 psi but you observe mud coming out when you bleed only 30 psi, you stop the bleeding process and shut the well in. Then, you continue bleeding the remaining 20 psi later.
If the mud is accidentally allowed to come out during this bleeding process, the bottom hole pressure will reduce resulting in more influx coming into the wellbore.
Step 5 – Repeat step 2 to 4
Repeat step 2 – 4 until you get the gas out of the well or the desired surface casing pressure is reached. As you know, you may not be able to kill the well with this method because total hydrostatic head is not sufficient to balance the wellbore.
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Two types of stabbing valves that must be prepared for well control are Full Opening Safety Valve (TIW valve) and Inside BOP valve (Gray Valve). We would like to describe what the differences between two valves are.
Full Opening Safety Valve or TIW valve
Full Opening Safety Valve or TIW valve is a ball valve designed for high pressure condition and it can hold pressure from both directions. It is called “Full Opening” because when the ball valve is opened; the flow path through the valve has a smooth inside diameter. One thing that you need to remember is that the term “Full Opening” does not mean that the ID of the valve is the same of drill pipe ID.
Figure 1 Full Opening Safety Valve
The valve should be always located on the rig floor and left in the open position. Additionally, you need to ensure that personnel on the rig have a right wrench to close the valve. The valve left in the open position is critical because the valve can be stab into drill string if the well flows through drill pipe.
For good drilling practices, you must have all size full opening safety valves which can be screwed into each size of drill pipe, drill collar, tubing, etc on the rig. When there is any string in the hole, the correct connection of the valve must be ready on the rig floor to stab in. Furthermore, it is a good practice to install the valve when there is a sting left on the rotary table during rig performs any tasks. The full opening safety valve should be used for shutting the well in while tripping.
Inside BOP valve (Gray Valve)
Insider blowout preventer (IBOP) valves have several industrial names as drill pipe float valves, Gray valves, Omsco valves and drop-in dart valves.
Figure 2 Inside BOP (Dart Type)
This valve is a non-return valve (check valve) allowing pumping through the valve into the drillstring but it prevents upward flow and the more widely used type is “dart-type”. The dart is used to hold the tool open therefore it is possible to stab the valve while the fluid is flowing through the drillpipe. With the IBOP valve installed in the drill string, it allows you to strip in hole without mud flowing through the drillsting. The IBOP valve should not be used for shut the well in while tripping.
Reference book: Well Control Books
Many people tend to confuse between possible and positive well control indicators therefore we would like to differentiate between these two well control indicators.
Possible well control (kick) indicators mean that there is possibility to get influx into wellbore. It MAY or MAY NOT be a kick.The indications 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 well control (kick) indications are as follows;
Change in drilling breaks (ROP change) – If the 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 formation 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 bigger than normal cutting. Larger of cutting size will be result in difficulty 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.
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 be useful for people on the rig to notify the high pressure transition zones.
Read and understand about d-Exponent and learn how to calculate d-Exponent and normalized d-Exponent (corrected d-Exponent)
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 drilling 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 transition zones.
There are some factors that you need to account for when you try to evaluate mud temperature changes as listed below;
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:
Positive well control (wellbore influx) indications mean indications showing almost 100% kick (wellbore influx) into wellbore. We can classify the positive indicators the following categories.
Positive Well Control Indicators While drilling
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.
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 level may be detected after the increase in flow show because it takes more time to accumulate volume enough to be able to detect by pit sensors.
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 flow coming after pumps off, it indicates formation influx into wellbore.
Positive Kick Indicators While Tripping
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 tank 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.
• If flow check indicates wellbore influx, crew must quickly shut the well in.
• 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.
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.
We wish this article will clear your mind about the possible and positive well control indicators.
Reference book: Well Control Books
Recap from the following articles: http://www.drillingformulas.com/positive-kick-wellbore-influx-indications/
http://www.drillingformulas.com/possible-kick-wellbore-influx-indications-part1/
http://www.drillingformulas.com/possible-kick-wellbore-influx-indications-part2/
There are a lot of people who are interested in well control and we would like to help them learn and make their life easier by sharing the well control spread sheet. The image (Figure 1) below is the screen shot of the spread sheet.
Figure 1 - Well Control Formula Screen Shot
In this file, there are several formulas covering from basic formulas to well control related ones. There are a total of 47 formulas listed below;
• Annular Capacity
• Annular Velocity (AV)
• Converting Pressure into Mud Weight
• Displacement of plain pipe such as casing, tubing, etc.
• How many feet of drill pipe pulled to lose certain amount of hydrostatic pressure (psi)
• Hydrostatic Pressure (HP) Calculation
• Hydrostatic Pressure (HP) Decrease When POOH
• Inner Capacity of open hole, inside cylindrical objects
• Pressure Gradient
• Slug Calculation
• Specific Gravity (SG)
• Pump out (both duplex and triplex pump)
• Pump Pressure and Pump Stroke Relationship
• Formation Integrity Test (FIT)
• Leak Off Test (LOT)
• Increase mud weight by adding Barite
• Increase mud weight by adding Calcium Carbonate
• Increase mud weight by adding Hematite
• Equivalent Circulating Density (ECD)
• Equivalent Circulating Density (ECD) Using Yield Point for MW less than or equal to 13 ppg
• Equivalent Circulating Density (ECD) Using Yield Point for MW more than 13 ppg
• Calculate Equivalent Circulating Density with Engineering Formula
• Surge and Swab Pressure Method#1
• Surge and Swab Pressure Method#2
• Accumulator capacity
• Actual gas migration rate in a shut in well
• Adjusted maximum allowable shut-in casing pressure for new mud weight
• Calculate Influx Height
• Estimate gas migration rate with an empirical equation
• Estimate type of influx
• Final Circulating Pressure (FCP)
• Formation pressure from kick analysis
• Hydrostatic Pressure Loss Due to Gas Cut Mud
• Initial Circulating Pressure (ICP)
• Kick Tolerance (Surface Stack and Vertical Well)
• Kick tolerance factor (KTF)
• Kill Weight Mud (KWM)
• Maximum formation pressure (FP)
• Maximum influx height
• Maximum Initial Shut-In Casing Pressure (MISICP)
• Maximum pit gain from gas kick in water based mud
• Maximum Surface Pressure from Gas Influx in Water Based Mud
• Maximum surface pressure from kick tolerance information
• New Pressure Loss With New Mud (psi)
• New Pump Pressure With New Strokes (psi)
• Riser Margin
• Trip margin
Please check the download link below to get the file for FREE.
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