Well control for non-drillers ...

Well control is one of the most important aspects of offshore shallow or deepwater drilling

operations. Improper handling of kicks in well control can result in blowouts with very grave consequences, including the loss of valuable resources such as in recent Deep Horizon Macondo incident losing millions in revenue. Even though the cost of a blowout (as a result of improper/no oil well control) can easily reach millions or billions of dollars, the monetary loss is not as serious as the other damages that can occur: irreparable damage to the environment, waste of valuable resources, ruined equipment, and most importantly, the safety and lives of personnel on the drilling rig.

In order to avert the consequences of blowout, the utmost attention must be given to oil well control. That is why well control procedures should be in place prior to the start of an abnormal situation noticed within the wellbore, and ideally when a new rig position is sited. In other words, this includes the time the new location is picked, all drilling, completion, workover, snubbing and any other drilling-related operations that should be executed with proper oil well control in mind. This type of preparation involves widespread training of personnel, the development of strict operational guidelines and the design of drilling programs — maximizing the probability of successfully regaining hydrostatic control of a well after a significant influx of formation fluid has taken place.

One concern is the increasing number of governmental regulations and restrictions placed on the hydrocarbon industry, partially as a result of recent, much-publicized well-control incidents. For these and other reasons, it is important that drilling personnel understand well-control principles and the procedures to follow to properly control potential blowouts.

The key elements that can be used to control kicks and prevent blowouts are based on the work of a blowout specialist and are briefly presented below:

Quickly shut in the well.

When in doubt, shut down and get help. Kicks occur as frequently while drilling as they do while tripping out of the hole. Many small kicks turn into big blowouts because of improper handling.

Act cautiously to avoid mistakes—take your time to get it right the first time. You may not have another opportunity to do it correctly.

Many well-control procedures have been developed over the years. Some have used systematic approaches, while others are based on logical, but perhaps unsound, principles. The systematic approaches will be presented here.

The drilling mud forms the first line of defence against kicks and blowouts. The second, and last, line of defence is the blow-out preventer stack. This is a collection of large, high-pressure valves which is fitted on the top of the wellhead in a vertical tier and which can be controlled remotely from any of several positions on the drilling unit. Although outwardly the BOP stack on a deep-water floater appears fairly unremarkable, it is an enormously expensive precision tool that can withstand pressures of up to 15,000 psi.

Because of the intricacy of its numerous working parts a dedicated ‘sub-sea engineer’ is employed by the drilling contractor to maintain it and its control system in top condition. Through the middle of the BOP stack is a hole wide enough for large drilling tools to pass up and down during the course of normal operations. The width of the opening is determined to some extent by the stage at which the stack is intended to be first used in the well programme. An 18-3/4” stack is quite a popular size, but this can obviously not be used until wide-diameter bits have drilled 36” and 26” hole.
When a kick or blow-out threatens the rig and the BOP controls are operated, large and powerful devices are closed together to seal off the hole and prevent the passage of well fluids up to the rig. Arrangements have to be made for sealing the hole either when drill pipe is in it, or when it is empty,
and different types of preventer are incorporated in the stack for use in everydifferent situation.The topmost preventer in the stack looks like a large steel pot from the outside and is called the ‘annular preventer’ or, sometimes, the ‘bag preventer’or ‘spherical preventer’. This can seal off the annulus between the preventer housing and any type of tubular that happens to be inside it. It can also seal off the hole completely if there is nothing inside running through the preventer at the time.

With the constant-bottomhole-pressure concept, the total pressures (e.g., mud hydrostatic pressure and casing pressure) at the hole bottom are maintained at a value slightly greater than the formation pressures to prevent further influxes of formation fluids into the wellbore. And, because the pressure is only slightly greater than the formation pressure, the possibility of inducing a fracture and an underground blowout is minimized. This concept can be implemented in three ways:

One-Circulation, or Wait-and-Weight, Method. After the kick is shut in, weight the mud to kill density and then pump out the kick fluid in one circulation using the kill mud. (Another name often applied to this method is “the engineer’s method.”)

Two-Circulation, or Driller’s, Method. After the kick is shut in, the kick fluid is pumped out of the hole before the mud density is increased.

Concurrent Method. Pumping begins immediately after the kick is shut in and pressures are recorded. The mud density is increased as rapidly as possible while pumping the kick fluid out of the well.

If applied properly, each method achieves constant pressure at the hole bottom and will not allow additional influx into the well. Procedural and theoretical differences make one procedure more desirable than the others.

Process suitability partially depends on the ease with which the procedure can be executed. The same principle holds true for well control. If a kick-killing procedure is difficult to comprehend and implement, its reliability diminishes.

The concurrent method is less reliable because of its complexity. To perform this procedure properly, the drillpipe pressure must be reduced according to the mud weight being circulated and its position in the pipe. This implies that the crew will inform the operator when a new mud weight is being pumped, that the rig facilities can maintain this increased mud-weight increment, and that the mud-weight position in the pipe can be determined by counting pump strokes. Many operators have stopped using this complex method entirely.

Basic of Well Control.ppt 

Well control Rev1.ppt  

Subsea well control

 

Understanding Well Control

INTRODUCTION

The function of Well Control can be conveniently sub-divided into two main categories, namely Primary Well Control and Secondary Well Control. These categories are briefly described in the following paragraphs.

1.1.1 Primary Well Control (Hmud > Pf )

This is the maintenance of sufficient hydrostatic head of fluid in the wellbore (HMUD) to balance the pressure exerted by the fluids in the formation being drilled (PF).

However, it should be noted that balancing formation pressure is a theoretical minimum requirement; good drilling practice dictates that a sufficient excess of hydrostatic head over formation pressure, be maintained at all times to allow for contingencies. This excess head is generally referred to as ‘Trip Margin’ or ‘Overbalanced’.

1.1.2 Secondary Well Control (Hmud < Pf )

If for any reason the effective head in the wellbore should fall below formation pressure, an influx of formation fluid (kick) into the wellbore would occur. If this situation occurs the Blowout Preventers (BOPs) must be closed as quickly as possible to prevent or reduce the loss of mud from the well.

The purpose of Secondary Well Control is to rectify the situation by either:

a) allowing the invading fluid to vent harmlessly at the surface, or

b) closing the well in. i.e. providing a surface pressure to restore the balance between pressures inside and outside the wellbore.

This latter procedure prevents any further influx of formation fluid and allows any one of a variety of ‘Kick Removal’ methods to be applied thus restoring a sufficient hydrostatic head of fluid in the wellbore. This re-establishes the preferred situation of Primary Well Control.

BOTTOM HOLE PRESSURE

The term ‘bottom hole pressure’, as used here, means the sum total of all pressures being exerted on a well by our operations. Bottom hole pressure is the sum of the hydrostatic pressures exerted by the fluids in the well, plus any circulating friction loss (e.g. Annular Pressure Loss), plus any surface applied back pressures, where appropriate.

This is the total pressure exerted by us. It is usually intended to at least balance the formation fluid pressures in the exposed portion of the well.

FORMATION FLUID PRESSURE (PF)

The formation fluid pressure, or pore pressure, is the pressure exerted by the fluids within the formations being drilled. The sedimentary rocks, which are of primary importance in the search for, and development of oilfields, contain fluid due to their mode of formation.

ABNORMAL PRESSURES

Abnormal formation fluid pressures, or ‘sur-pressures’ as they are sometimes known, can arise for a number of reasons.

They can be categorised as:

a) Differential Fluid Pressure
b) Surcharged Shallow Formations
c) Sediment Compression
d) Salt Beds
e) Mineralisation.

The main causes of kicks are:

a) Failing to fill the hole properly when tripping
b) Swabbing in a kick while tripping out
c) Insufficient mud weight
d) Abnormal formation pressure
e) Lost circulation
f) Shallow gas sands
g) Excessive drilling rate in gas bearing sands


INDICATIONS THAT A KICK IS IN PROGRESS

1) During Drilling

There are several indications which show that a kick is in progress:
a) FLOW RATE INCREASE.
b) PIT VOLUME INCREASE.
c) PUMP PRESSURE DECREASE/PUMP STROKE INCREASE.

2) During Tripping

The indication of the presence of a kick is:

a) INCORRECT HOLE FILL VOLUME.

If this indication is not noticed at an early stage, it should become progressively more obvious.
In the extreme case the hole would eventually stay full, or flow, while pulling out. This may sound ridiculous, but it has occurred.

b) HOLE KEEPS FLOWING BETWEEN STANDS, WHILE RUNNING IN.

The presence of some or all of these indications require that a flow check be carried out to determine whether or not a kick is in progress.

When a kick occurs, the surface pressure required to contain it will depend mainly upon the size of the influx taken into the wellbore. A small kick closed in early means lower pressures being involved through the kill. Furthermore it is easier to deal with a kick which is noticed early and closed in quickly.

ANNULAR PREVENTERS

Annular Closing Times

• API RP53 state that surface annular preventers closing times should not exceed 30seconds for smaller than 18 3/4” and 45 seconds for 18 3/4” and larger.

• Subsea annular preveters should not exceed 60 seconds.

Shaffer Spherical BOP

Shaffer annular BOPs are rugged, compact and will seal on almost any shape or size- Kelly’s, drill pipes, tool joints, drill collars, casing or wireline. They also provide positive pressure control for stripping drill pipe into and out of the hole. The annular BOP is one of the first lines of defence in controlling a kicking well. When the BOP is actuated, hydraulic pressure operates, and in turns closes the spherical shaped preventer. The closure occurs in a smooth upward and inward motion, as opposed to horizontal motion.

Special features include:
• Rugged and reliable sealing element provides positive seal after hundreds of tests to full working pressure.
• Strong and simple construction-only five major parts.
• Simple hydraulic system-only two hydraulic connections are needed.
• Wear rings on movable parts prevent metal-to-metal contact. This feature prolongs preventer life.
• Suitable for H2S service.
• Servicing is easy- Element can be changed without getting mud and grit into the hydraulic system.


Diverters

A diverter is a safety system, which reroutes a well fluid flow away from the rig. Shallow gas is permitted to flow until depleted, or until the well is bridged over or killed by pumping in heavy mud. Ready during upper hole operations, a diverter is intended for use when there is a danger of penetrating a pressurised gas zone, while the casing shoe strength may not be sufficient to contain shut in pressures. Massive flows of gas and sand can quickly destroy a rig’s diverter system. Hydril incorporate integral valve functions and switchable target to minimise equipment and thereby decrease the risk of malfunction.


MUD GAS SEPARATOR (POOR BOY DEGASSER)

The height and diameter of an atmospheric separator are critical dimensions which affect the volume of gas and fluid the separator can efficiently handle. As the mud and gas mixture enters the separator, the operating pressure is atmospheric plus pressure due to friction in the gas vent line. The vertical distance for the inlet to the static fluid level allows time for additional gas break-out and provides an allowance for the fluid to rise somewhat during the operation to overcome friction loss in the mud outlet lines. As shown in Figure 39, the gasfluid inlet should be located approximately at the midpoint of the vertical height. This provides the top half for a gas chamber and the bottom half for gas separation and fluid retention. The 30 in. diameter and 16 ft minimum vessel height requirements have proven adequate to handle the majority of gas kicks. The separator inlet should have at least the same ID as the largest line from the choke manifold which is usually 4 in. Some separators use tangential inlet, which creates a small centrifugal effect on the gas-fluid mixture which causes faster gas break-out. The baffle system causes the mud to flow in thin sheets which assists the separation process. There are numerous arrangements and shapes of baffles used. It is important that each plate be securely welded to the body of the separator with angle braces.

Well Control Basics

Guide to Drilling Eqpt Opns.pdf