Well control is the technology focused on maintaining pressure on open formation (that is, exposed to the wellbore) to prevent or direct the flow of formation fluids into the wellbore. This technology encompasses the estimation of formation fluid pressures, the strength of the subsurface formations and the use of casing and mud density to safely stop a well from flowing. To conduct well-control procedures, large valves are installed at the top of the well to enable wellsite personnel to close the well if necessary.
1.Well Control Levels
There are three distinct well control levels that may occur during drilling operations:
1.1.Primary well control
The first line of defense is primary well control. Primary control over the well is maintained by ensuring that the pressure due to the column of mud in the borehole is greater than the pressure in the formations being drilled maintaining a positive differential pressure or overbalance on the formation pressures: Mud hydrostatic pressure > Formation pore pressure Any influx of formation fluids (oil, gas or water) in the borehole is known as a kick. When a kick is taken, primary control has been lost for some reason.
- Reasons for losing primary well control during drilling:
1. The well penetrates an overpressure zone with a higher formation pressure than mud hydrostatic pressure.
2. A weak downhole formation allows sufficient mud to leave the wellbore that the level of mud in the annulus drops.
3. The hole is not properly filled when pulling out of the hole.
4. Swabbing operations occur when the drill string is lifted upwards, fluid has to flow downwards as a pressure drop or suction is created by the withdrawal of the steel volume. This causes a temporary pressure reduction on the hole and is called swab pressure.
1.2.Secondary Well Control
If primary control is lost and formation fluids start to flow into the well, secondary well control is initiated by closing the blowout preventers to seal off the annulus. This stops mud leaving the well at the surface. As fluid enters the well from the kicking formation, pressure in the well will increase until the total pressure exerted by the mud on the kicking formation equals the formation pore pressure.
The aim of secondary control is to stop the flow of fluids into the wellbore and eventually allow the influx to be circulated to surface and safely discharged, while preventing further influx downhole. Now we can restore the primary well control.
It sometimes happens that the blowout preventer equipment fails or the hole starts to allow fluid to leak away into an underground formation. Secondary control cannot be maintained, and formation fluid again starts to enter the wellbore. This is now a dangerous situation. If control is not restored, the end result is a blowout. Tertiary control has to be applied to try to stop the flow.
Tertiary control involves pumping substances into the wellbore to try to physically stop the flow downhole. This may involve pumping cement (with a high risk of having to abandon the well afterwards). However, there is another method that may be employed, called a barite plug.
A barite plug is set by mixing a heavy slurry of barite in water or diesel oil. It has to be kept moving while mixing and pumping. Once the slurry is in position downhole and pumping stops, the barite rapidly settles out to form an impermeable mass that will hopefully stop the flow of formation fluid. The main risk is that if pumping stops with the slurry inside the pipe, barite will settle out in the pipe and plug the drill string.
2.Blowout Preventer Stack
The primary function of the BOP is to form a rapid and reliable seal around the drill string or across the empty hole (if no pipe is in the hole) so as to contain downhole pressures. There are currently two types of preventer available that allow this seal to be formed.
2.1.Bag-type Preventer (Or Annular Preventer)
A bag preventer contains a large rubber seal, which is circular if viewed from above and conical if viewed from the side. This is held inside a steel chamber. Below the rubber element is a hydraulically operated piston with a matching conical shape on top to fit the rubber underside. As the piston moves up, the rubber element is compressed by the cover above it and pushed inwards by the cone profile. The element can distort to allow it to seal around any smooth object in the wellbore, whether it is a round pipe or tool joint or a square kelly. It can also seal on the open hole, but the level of rubber element distortion necessary will seriously shorten the useful life of the element. The rubber seal, called a packing, is expensive and awkward to replace.
Moving pipe in a closed well when the well is under pressure is called stripping. The is possible because the rubber element can move to accommodate the thicker tool joints moving down through the element.
The other type of preventer uses a pair of large steel rams that shut under high hydraulic pressure, with great force. These rams are interchangeable and are of different types:
• Fixed pipe ram: the seal is sized to fit one outside diameter only.
• Variable bore pipe ram: the seal element can accommodate a narrow range of diameters. It can only seal on round pipe only.
• Blind rams: blind rams are designed to seal on the open hole.
• Blind-share rams: blind-share rams have blades incorporated that can cut through pipe.
• Casing share rams: these are heavy-duty share rams that do not seal but can cut through heavy pipe, such as casing.
• Below the rams are pipes that come out to the side. These are called side outlets and are used to allow flow out of or into the annulus during well killing operations.
One side connects to the standpipe manifold to allow flow to be directed into the annulus. This is called the kill line.
• The opposite side connects to a manifold of valves and chokes. This is called the choke line, and its purpose is to allow flow out of the annulus to be controlled.
BOP Stack Components:
• Normally, a BOP stack would have at least one bag preventer and two ram preventers.
• Stacks for deeper wells might have up to four ram preventers and two annular preventers.
• The ram preventers generally have a higher pressure rating and are always installed below the bag preventers.
• If only two ram preventers are used, the bottom set will normally be blind-shear rams, and the upper set will be pipe rams. One reason for placing the blind rams on the bottom is that if the pipe rams or annular leaks, it is possible to close the blind rams below and fix the leak above.
A choke valve allows fluid to flow through it, but it has a variable sized opening. This allows mud to flow out of the annulus but at the same time keeps pressure on the annulus.
4.BOP Control Systems
1- BOP units (bag and ram preventers and some valves) are moved using hydraulic fluid under pressure to provide this pressure, a hydraulic control system is used that contains several elements:
2- A reserve hydraulic fluid tank holding fluid at atmospheric pressure.
3- A set of bottles holding fluid under high pressure (usually 3,000 psi) with pressurized nitrogen.
4- A high-pressure manifold connected to the bottle system.
5- A low-pressure manifold that contains fluid at the working pressure of the ram preventers
6- (usually 1,500 psi).
7- A pressure regulator that feeds fluid from the high pressure manifold to the low-pressure manifold and that reduces the pressure to the working pressure.
8- A set of valves attached to the low-pressure manifold that can direct working pressure fluid to the rams (to open or to close them) and that directs exhaust fluid back to the reserve hydraulic fluid tank.
9- A valve that controls the opening and closing of the bag preventer.
10- A pressure regulator that feeds fluid from the low pressure manifold to the bag preventer control valve.
11- Two sets of pumps to maintain system pressure. One set is driven by compressed air from the rig air system, the other is powered by electricity.
- Subsea BOP Systems
On floating rigs, the BOP is attached to the top of the surface casing at the seabed. A subsea BOP contains extra control systems when compared to a surface BOP.
The hydraulic control system is also open ended in that hydraulic fluid is exhausted to the sea rather than being returned to the control system. The hydraulic fluid in this case is water mixed with a nontoxic soluble oil so that pollution is avoided.
5.Kick Detection Equipment
There are two main kick detection systems that give a direct indication of a kick:
• The pit volume totalizer.
• The flow indicator.
5.1.The Pit Volume Totalizer
That can display the volume in any particular tank and can also add up all of the surface active volumes so that any change in the total surface volume may be detected. The PVT also includes alarms that can be set so that changes beyond a set amount lost or gained will cause an alarm to sound.
It provides a readout showing the total volume of drilling fluid held on the surface. If this total increases, and the increase is not due to the mud engineer adding chemicals or fresh mud to the system, a kick is occurring.
5.2.The Flow Indicator
This system consists of an instrument attached to a paddle that sits in the flowline from the annulus. This paddle is pushed up by the returning mud stream; the amount it is pushed depends on the flow rate, among other things. If the flow rate should increase, an alarm will sound. If the flow rate out increases but the mud pump speed has not been increased, it is possible that the extra flow out is due to an influx entering the wellbore.
Generally the flow indicator will give the first positive indication of a kick, followed by an increase in the active volume. However, the paddle-type flow indicator is prone to false alarms because of cuttings and other debris that may stick to the paddle or build up underneath it.
If the surface instruments indicate that a kick is in progress while drilling, normally the driller will stop drilling, pick up the drill string so that the bit is above the bottom of the hole, and stop the pumps. A visual check is then made by looking down through the rotary table, into the bell nipple, at the level of mud in the annulus. If the well is in fact kicking, the mud in the annulus will still be moving upwards even though the pumps are shut down. Having confirmed a kick, the driller will then close the BOP as quickly as possible and will then notify the tool pusher and drilling supervisor in charge of the rig.
If the permeability of the flowing formation is high, the kick can develop very quickly. A larger drilled hole will also allow influx to flow in faster, but this is compensated for to an extent because the capacity of the hole is greater in a larger hole. It is also possible that if permeability is very low, little or no influx enters the wellbore even though mud hydrostatic is less than formation pore pressure.
This article described the three levels of well control (primary, secondary, and tertiary). Well control equipment was covered in some detail, including blowout preventers and control systems, chokes, and kick detection equipment.
– Drilling Technology in nontechnical language, steve devereux, Editor.