This article is a follow up to a previous article I published on the Vine. I recommend reading the other article before reading this one.
This article makes reference to many elements of oil and gas drilling operations that represent complex and highly engineered systems. I encourage anyone with an interest to research these references to discover how these various systems work. Most manufacturers of oilfield equipment have good web sites that describe the technical features of their products and include good images of them.
The latest information I have is that the Deepwater Horizon had finished cementing production casing when the explosion occurred that subsequently sunk the rig and left a huge environmental mess as a consequence.
I have great respect for the people working in this industry. Integrated into the DNA of the offshore oil and gas business is an expectation of hard physical work, attentiveness to duty and team work. These workers hold themselves to an extremely high level of performance. When you are a novice in the oilfield, you are a "worm." When you've proven your worth, you become a “hand.” If “you can’t get it done, you can't stay.” You will inevitably quit or be “run off.”
As the recent events bear out, people's lives depend on the worker’s adherence to this high standard.
The Deepwater Horizon is a floating work platform. As such it is subject to the effect of wind, waves, currents and tides. To drill a well, the Deepwater Horizon uses dynamic positioning to maintain its location over the well at the sea floor. The rig has a computer controlled system of thrusters (large pivoting propellers) mounted on the enormous pontoons upon which the rig structure floats. The system uses satellite global positioning and transponders on the subsea wellhead to sense the movement of the rig. The control system points and activates the thrusters to maintain the rig over the well site when it begins to drift off site. There are no anchors. The DP system functions around the clock the entire time the rig is on a location.
Most rigs of this type are towed from one well location to another by tug boats. For long haul moves overseas, a lift vessel loads the entire rig onto its deck to take it to distant drill sites.
For moving, the rig floats on the surface of the water with minimum draft. When at the well site, the rig ballasts down by flooding tanks in its pontoons with water. As the pontoons sink below the surface the rig becomes more stable and less prone to rocking and rolling on rough seas.
The Deepwater Horizon is owned by the drilling contractor Transocean. The operating company, BP, contracted the rig to drill on its lease. The crew is employed by Transocean. The manager of the rig is referred to as the toolpusher. Two drill crews report to the toolpusher. Leading each crew is a driller. Each crew works twelve hour shifts operating the rig around the clock. The work never stops unless there is a tropical storm threatening.
The operating company typically has two to four representatives on the rig. The top ranking representative of the operating company is referred to as “the company man.” He has ultimate responsibility for all operational activities. The company representatives coordinate logistics and the movement of workers and materials to and from the rig. They see to it that the drilling prognosis, a written plan for how to proceed during drilling, is executed by the rig crew.
The driller supervises the drill crew, operates the controls that move pipe and tools into and out of the hole and operates the controls for the mud pumps and well control system.
Second in command in the drill crew is the derrick man. His primary responsibility is to climb into the mast (ninety feet above the drill floor) and handle the top end of the stands of drill pipe when the operation must run pipe into or out of the hole. When not in the mast, the derrick man monitors the mud and assists the driller as needed.
Most drill crews have three or four “floor hands.” The floor hands handle the bottom end of the drill pipe stands and make the connections between stands of drill pipe.
Drill pipe is a special type of pipe used by the rig to carry the drill bit and other tools into and out of the hole. Drill pipe permits circulation of fluids through it, and enables the rotation of the drill bit and other tools to drill ahead (make hole).
Most of the activity of drilling is performed on a platform located at the base of the rig mast called the drill floor. In the center of the drill floor is the rotary table. This is a powered bushing that rotates the drill pipe during drilling. To the side of the rotary table is the drawworks. This is a huge hoist upon which the drill line is spooled. The drill line is stranded steel cable about two inches in diameter that extends from the drawworks over a set of sheaves at the top of the mast (the crown block) and down through sheaves in the travelling block. It is usually wrapped between eight and twelve turns through the two sets of sheaves creating a huge block and tackle assembly. A rig like the Deepwater Horizon is capable of lifting and supporting a couple of million pounds of pipe.
A new well is spudded by first installing conductor casing. This casing is usually thirty to thirty six inches in diameter. The conductor casing is run in open ocean. It is lowered on drill pipe to the sea floor with a wellhead and guide frame attached to the top of it. The guide frame is a steel structure resembling an upside down funnel. The structure guides the Blow Out Preventer (BOP) onto the subsea wellhead when it is lowered into place.
Sometimes a rig drills a hole for the conductor casing and sometimes it jets the conductor into the seabed with water pressure. When in place, the conductor casing extends into the sea floor a few hundred feet and the subsea wellhead is positioned ten or 20 feet above the sea floor. This is the foundation for the well.
Next the rig picks up a drilling assembly to drill the surface hole. The surface hole penetrates into the seabed usually about a thousand feet. This hole is drilled without circulation of fluids back to the rig using salt water as a drilling fluid. The cuttings from the drill bit simply flow out onto the seabed.
When the hole reaches planned depth, the drill string is pulled out of the hole and the surface casing is run and cemented. Surface casing is usually around twenty inches in diameter and extends into the well bore through the subsea wellhead and the conductor casing. Surface casing is usually cemented back to near the surface.
At the top of the surface casing is the subsea high pressure wellhead. It lands inside of the low pressure subsea wellhead that was installed with the conductor casing.
The top of the high pressure wellhead has a machined profile that enables the subsea BOP to be landed, hydraulically locked and sealed over the wellhead.
Once the surface casing is landed and cemented, the BOP is picked up and lowered onto the subsea high pressure wellhead. The BOP is run on the bottom of the drilling riser. A hydraulic latch is operated from the surface control system that latches and seals the BOP to the wellhead.
When the BOP is "latched up" the entire system is fully tested for pressure and function. No leakage is acceptable. Every component must function and hold rated pressure one hundred percent for the operation to proceed.
The drilling riser extending from the top of the BOP to the rig is suspended under the drill floor by a series of hydraulic tensioners that maintain a constant tension on the riser holding it in a fixed position relative to the wellhead while the rig heaves up and down on the sea surface.
The riser terminates at the rig with the diverter system.
The diverter is just below the rig's rotary table. It has a set of large elastomeric seals that can be hydraulically compressed and expanded to seal around any pipe suspended through it. It has large outlets that are connected to vent pipes that extend laterally out past the edge of the rig on both sides. If gas gets into the drilling riser, the diverter is closed and one or both outlets opened to vent it away from the rig and prevent ignition.
With the drilling riser installed, the rig can circulate drilling fluids into and out of the hole. During drilling, the rig continuously circulates drilling mud down the drill pipe. It exits at the bit and rises back up the drilled hole to the rig. At the top of the drilling riser it drains out an outlet and flows to the mud conditioning system referred to as the shale shakers.
The shale shakers filter out cuttings and sand from the drilling process and return the mud to its specified physical and chemical properties. Conditioned mud is drained back into the mud tanks for re-circulation.
Drilling mud lubricates and cools the drill bit. It cakes up on the walls of the hole to prevent leakage into the geologic strata through which the hole is made. Its most important function is to offset the pressures inherent in the geologic strata. The weight and viscosity of the drilling mud is critical to prevent fluids and gases from the earth from entering the well bore.
Generally pressures in geologic formations increase with the depth of the well. The weight of the column of drilling mud in the hole creates positive pressure in the hole that offsets formation pressures. With this balance, the top of the hole can be kept open so drilling tools can be lowered into and out of the well.
Once the drilling riser is installed, the drill crew makes up a bit to the drill string and lowers the assembly into the well to begin drilling.
Next the rig continues drilling with a smaller bit that passes through the subsea BOP, wellhead and into the surface casing. The rig drills past the bottom of the surface casing and extends the hole down to the next planned depth for installing casing.
Typically, at least one intermediate string of casing is run and cemented before the well reaches target depth. The intermediate casing strings are progressively smaller in diameter so they can be run inside of the previously set casing. They are run through the BOP to land and seal in the subsea wellhead.
After each casing string is set, the rig continues to drill using a smaller bit to fit through the casing and extend the hole deeper.
During the drilling process, much data is collected related to all aspects of down hole conditions. These include the geological and geographical position of the bottom of the well, its angle of deviation from vertical at various depths plus geological formation temperatures, pressures and physical composition.
When a well reaches its target depth, some rig time is spent conditioning the mud in the well by circulating it into and out of the well. The weight and viscosity of the mud is measured on a regular basis. Some simple chemical tests are run as well to detect hydrocarbons in the mud.
To circulate the well, the crew runs the drill pipe down to just above the bottom of the hole (they trip the pipe into the hole). In the case of the Deepwater Horizon, that's roughly fifteen thousand feet of pipe.
This operation takes a bit of time.
For the drill crew, the process consists of picking up stands of drill pipe from the rack in the mast and making them up to the top of the main drill string hanging in the hole, then lowering that section down until the top of it is just above the drill floor. The drill crew hangs the drill string off in the rotary slips and picks up the next stand of drill pipe.
This goes on continuously until the pipe is run. Each stand of drill pipe, on average, weighs about a ton. Handling that amount of weight and moving it around requires absolute attention to what you are doing or you can easily lose fingers, hands or heads.
Each member of the drill crew has a specific responsibility. Timing is very important as their goal is a fluid motion that moves the pipe quickly and efficiently. It is literally a dance where each person responds to the action of another team member and no one can be out of step.
Everyone is very aware of the need for safe operations. It's their bodies at risk, and most of them have witnessed a few accidents and injuries.
Rig time is money. They want to work as fast as possible.
After running the drill pipe, the drill crew begins pumping mud down the drill pipe. It exits out the drill bit at the bottom and circulates back up the outside of the drill pipe through the open hole, the previously set casing, the wellhead, the BOP, and the drilling riser.
When it circulates back to the top of the drilling riser it drains off into an outlet that leads to the shale shakers.
From the shale shakers the mud drains back into the mud tank. The level in this tank is continuously monitored and should remain relatively fixed (the same amount that goes in the hole, comes out).
When rig management feels comfortable with the well conditions they go forward with the process of running the casing.
Running casing on an offshore oil rig is a monumental task of logistics, operations planning and physical execution. Dozens of vendor equipment specialists (service hands) support the drill crew during the process.
While the well is prepared, casing is offloaded from supply vessels onto the pipe rack by a pedestal crane at the perimeter of the rig. The crane operator is in charge of this operation and he is usually supported by three or four roustabouts.
The supply vessel can rarely tie off due to sea conditions. The skipper of the supply vessel must keep the boat in position under the crane by controlling the vessel's screws with throttles mounted on the back deck of the boat.
As it is offloaded, every joint of pipe is numbered, measured and marked both in a tally book and on the pipe itself.
Eventually the stack of pipe will be about ten feet high.
Production casing is usually about seven to ten and three quarter inches in diameter and weighs about fifty pounds per foot. Each joint of pipe is about forty five feet long. Each joint weighs about a ton. Based on the published hole depth for the Deepwater Horizon well, when made up together, the casing string weighed seven hundred fifty thousand pounds or more.
Because casing is so heavy to handle, and it requires special handling tools to get it run into the well, a specialist crew is called out to the rig to work with the drill crew to run the casing into the well. The casing crew consists of five or six service hands trained to use the special hydraulic tongs to torque the pipe connections together, special elevators to pick up the casing with the rig hoisting equipment and special drill floor slips to support the weight of the casing so the elevators can be released to pick up more pipe.
The cement pumps are supplied by a well cementing specialty company and stay on the rig all the time. For that reason, one or two cementing service hands are on the rig at all times. The well cementing hand operates a high pressure, high volume pumping system that mixes dry cement to a specific chemical formula and pumps it out as a slurry that meets specified physical and chemical requirements.
When run, the casing is suspended in the subsea wellhead. The casing hanger threads onto the last joint of casing and can be picked up using a specially designed running tool. The casing hanger lands in a machined profile inside the subsea wellhead. It has a separate annular seal that is also made up to the running tool. Because these tools are proprietary designs of the wellhead manufacturer, there is one or more service hands from the wellhead vendor on the rig to supervise running the casing hanger, sealing the casing annulus, releasing the running tool and retrieving it back to the rig drill floor.
When the drill pipe is out of the hole and the rig is ready to start running casing, the casing slips, elevators and tongs are installed at the rig drill floor. The crane operator picks up the first joint of casing from the pipe rack and places it in the “V-door.” (The V-door is an opening in the drilling mast at the rig drill floor through which pipe can be picked up by the rig hoisting equipment.
The first joint of casing has a fitting called the casing shoe on bottom. The casing shoe is a metal sleeve that threads onto the casing end connection. Its core is made of cement and it has an open bore through the middle with an elastomeric floating ball check valve. The check valve allows fluid to be pumped through the shoe, but seats and stops fluid from returning back into the shoe from the bottom.
The shoe joint is suspended in the casing slips over the hole and the next joint is placed in the V-door and picked up by the drawworks.
A few joints above the shoe joint, a joint is installed with a special fitting referred to as a float collar made up to it. The float collar also includes a cement core and a ball check valve.
From this point running casing is a continuous operation of picking up casing joints, making them up to the main string hanging in the hole and lowering the string down until the top of the last joint is in position for the next joint to be made up. There is no stopping until the job is complete. This may take a day or more to finish.
When the last joint of casing is made up to the casing string in the hole, the bottom of the casing string is still five thousand feet from its final set position (depth of the water to the subsea wellhead).
On top of the last joint of casing, the crew installs the casing hanger, its running tool, and the first stand of drill pipe. Inserted into the top of the casing below the casing hanger running tool is the cementing stinger. The rig picks up the casing with the draw-works and all the casing handling equipment is removed and drill pipe handling tools installed.
From that point stands of drill pipe are made up to lower the casing string down to its final position where the casing hanger lands in the wellhead and the bottom of the casing is a few dozen feet above the bottom of the hole. The space between the casing shoe and the bottom of the hole is referred to as ”rat hole.”
When the casing hanger lands, the weight of the casing transfers from the rig to the wellhead.
Lines from the cement pumps are then made up to the top of the drill string extending above the rotary slips at the drill floor.
When the pumps lines are made up and pressure tested, the rig is ready to cement the casing. Once they start pumping cement they have to pump it continuously until it is in position, otherwise there will be a big mess from which to recover. Time to complete the job is critical. The cement will begin to set after a certain period of time.
The rig management calculates how much cement will be required to fill up the casing annulus. They want the cement to fill the annulus above the bottom of the previously run casing string but not all the way back to the wellhead.
Prior to pumping cement, a ball is dropped into the top of the drill pipe at the rig drill floor. They begin pumping cement behind the ball. The ball is pumped down into the cement stinger at the bottom of the drill pipe below the casing hanger running tool.
The cement stinger houses two elastomeric plugs. They have an open bore and the mud can circulate through them. When the ball reaches the plugs, it seats in the bottom one sealing the bore. Pump pressure pushes the plug out of the cement stinger and it expands to seal against and wipe the inside of the casing. The plug leads the cement down the casing.
When the plug reaches the float collar, it seats and seals against the bore of the float collar. At the cement pumps an expected increase in pressure indicates the ball has seated and the bottom of the cement is at the float collar. Extra pump pressure forces the ball to collapse and cement passes through the bore and out of the casing shoe to fill up the casing annulus.
When the last of the cement has been mixed and pumped into the well, a dart is dropped into the drill pipe from the drill floor. At this point the pumping operation switches over from the cement pumps to the rig pumps. This dart is pumped down the drill pipe with drilling mud on top of it. When it seats in the second plug housed in the cement stinger it seals the bore of the plug. Continued pump pressure forces the second plug out of the cement stinger.
The plug expands to seal against the inside of the casing and separates the mud from the cement.
When the second plug lands in the float collar the expected increase in pressure indicates the cement job is complete.
At that point, the casing hanger running tool is used to set the casing hanger annular seal which isolates the bore of the casing from the outer casing annulus preventing communication of fluids or gases to the outer strings of casing through the wellhead.
When the casing hanger annulus seal is confirmed set and pressure tested, the casing hanger running tool is released from the casing hanger and the entire assembly is pulled out of the hole.
The well is now full of mud down to the casing float collar. There is a plug of cement inside the casing between the float collar and the shoe. There is cement on the outside of the casing extending up into the previously run casing.
This is the point when the Deepwater Horizon may have experienced the kick.
If the cement channels in the hole or gas and oil permeate through the cement plug before it can fully set, or if the cement doesn't set properly, gas and oil may work its way into the casing. As the gas and oil rises through the mud the pressure created by the weight of the mud is reduced because there is less mud above the bubble. The bubble expands as it rises accelerating the kick.
Closing the BOP should seal off the well. For some reason the BOP wasn't closed, or it failed to hold the pressure allowing the gas and oil into the drilling riser.
Apparently the diverter at the top of the drilling riser was unable to divert the flow out away from the rig as it is designed to do.
The gas reached the rig and any one of numerous ignition sources caused it to explode.
At that point, with a fire raging in the area of the drill floor, all attention would turn to getting the rig evacuated. Nothing could be done to seal in the well from the rig. Anyone on the drill floor or below it when the explosion occurred was probably lost in the explosion.
The mystery and focus of the investigation of this accident must determine why the well control system failed.