Blowout and Well Control Handbook, Second Edition, brings the engineer and rig personnel up to date on all the useful methods, equipment, and project details needed to solve daily well control challenges. Blowouts are the most expensive and one of the most preventable accidents in the oil and gas industry. While some rig crews experience frequent well control incidents, some go years before seeing the real thing. Either way, the crew must always be prepared with quick understanding of the operations and calculations necessary to maintain well control.
Updated to cover the lessons learned and new technology following the Macondo incident, this fully detailed reference will cover detection of influxes and losses in equipment and methods, a greater emphasis on kick tolerance considerations, an expanded section on floating drilling and deepwater floating drilling procedures, and a new blowout case history from Bangladesh. With updated photos, case studies, and practice examples, Blowout and Well Control Handbook, Second Edition will continue to deliver critical and modern well control information to ensure engineers and personnel stay safe, environmentally-responsible, and effective on the rig.
Features updated and new case studies including a chapter devoted to the lessons learned and new procedures following Macondo
Teaches new technology such as liquid packer techniques and a new chapter devoted to relief well design and operations
Improves on both offshore and onshore operations with expanded material and photos on special conditions, challenges, and control procedures throughout the entire cycle of the well
Having well control equipment on a well is a standard practice in the oil industry. Blowout preventers and other well control equipment are routinely rigged up and successfully tested. However, pressure testing does not always confirm that the equipment will function properly in a significant well control event. The intent in this chapter is not to discuss the workings of a BOP, but to discuss what can and does happen to the equipment when circulating out a kick. When the equipment is exposed to significant flow for an extended period of time, it will start to fail. Equipment downstream of the BOPs is often rigged up improperly. Targeted turns downstream of the chokes can be installed backwards or left out entirely. The 90 and 45 degree turns will wash out much more quickly. Separators will be rigged up without a liquid leg or too little liquid leg, and gas will be vented to the shakers or mud house. Simple pressure testing does not find these types of problems.
Under most circumstances, it is desirable to have two barriers to flow. The fluid column is usually the primary barrier, and the well control equipment (along with other equipment in the well) is the secondary barrier. Oil industry personnel must be able to recognize what is a barrier and when the barrier is lost. It may not be possible to maintain two barriers in all situations, and risks must be mitigated in those situations.
A by-product of managed pressure drilling has resulted in improved equipment for detecting and circulating out a kick. Improved flow meters, computer-controlled chokes, and computer algorithms can be used to detect kicks sooner and to circulate out the kicks with less chance of human error.
Keywords
Choke; Kill; Manifold; Blowout preventer; Erosion; Corrosion; Separator; Header; Barrier; Well barrier element; Managed pressure drilling; Coriolis meter
â⊠I could see that we were having a blowout! Gas to the surface at 0940 hours.â
0940 TO 1230 HOURS
Natural gas was at the surface on the casing side very shortly after routing the returning wellbore fluid through the degasser. The crew reported that most of the unions and the flex line were leaking. A
-in. hammer union in the line between the manifold and the atmospheric-type âpoor-boyâ separator was leaking drilling mud and gas badly. The separator was mounted in the end of the first tank. Gas was being blown from around the bottom of the poor-boy separator. At about 1000 hours, the motors on the rig floor began to rev as a result of gas in the air intake. The crew shut down the motors.
At 1030 hours the annular preventer began leaking very badly. The upper pipe rams were closed.
1230 TO 1400 HOURS
Continuing to attempt to circulate the hole with mud and water.
1400 TO 1500 HOURS
The casing pressure continues to increase. The flow from the well is dry gas. The line between the manifold and the degasser is washing out and the leak is becoming more severe. The flow from the well is switched to the panic line. The panic line is leaking from numerous connections. Flow is to both the panic line and the separator.
The gas around the rig ignited at 1510 hours. The fire was higher than the rig. The derrick fell at 1520 hours.
This excerpt is from an actual drilling report. Well control problems are difficult without mechanical problems. With mechanical problems such as those described in this report, an otherwise routine well control problem escalates into a disastrous blowout. In areas where kicks are infrequent, it is common for contractors and operators to become complacent with poorly designed auxiliary systems. Consequently, when well control problems do occur, the support systems are inadequate, mechanical problems compound the situation, and a disaster follows.
Because this book is presented as a blowout and well control handbook, its purpose is not to present the routine discussion of blowout preventers (BOPs) and testing procedures. Rather, it is intended to discuss the role of equipment, which frequently contributes to the compounding of the problems. The components of the well control system and the more often encountered problems are discussed.
The saying âit will work great if we don't need it!â applies to many well control systems. The fact is that, if we don't ever need it, anything will suffice. And therein lies the root of many of the problems encountered. On a large number of rigs, the well control system has never been used and will never be needed.
Some rigs routinely encounter kicks, and the crew is required to circulate out the kick using classical well control procedures. In these instances, the bare essentials will generally suffice. For most of these conditions, well site personnel need not be too concerned about how the equipment is rigged up or how tough it is.
In some parts of the industry, wells are routinely drilled underbalanced with the well flowing. In these cases, the well control system is much more critical, and more attention must be paid to detail.
In a few instances, the kick gets out of control, or the controlled blowout in the underbalanced operation becomes uncontrolled. Under these conditions, it is sometimes impossible to keep the best well control systems together. When it happens, every âiâ must be dotted and every âtâ crossed.
Unfortunately, it is not always possible to foretell when and where one of those rare instances will occur. It is easier and simpler to merely do it right the first time. Sometimes, the worst thing that can happen to us is that we get away with something we shouldn't. When we do, we are tempted to do things the same way over and over and even to see if we can get away with more. Sooner or later, it will catch up with the best of us. It is best to do it right the first time.
Pressure, Erosion, Corrosion, and Vibration
When everything goes to hell in the proverbial hand basket, our first question should be, âhow long is all this sâgoing to stay together?â The answer to that question is usually a function of the items listed aboveâpressure, erosion, corrosion, and vibration.
Pressure
If the well control system is rated to 10,000 psi and has been tested to 10,000 psi, I'm comfortable working up to that pressure provided none of the other three factors is contributing, though that is seldom the case. There is usually a large difference between the working pressure and test pressure for a given piece of equipment. For example, a 10,000 psi working pressure BOP has a test pressure of 15,000 psi. That means the rams should operate with 10,000 psi, and under static conditions, everything should withstand 15,000 psi.
Wellheads, valves, and all other components are the same. It is easy to understand how a valve can have a âworkingâ and a âtestâ pressure, but it is natural to wonder how a spool can have a âworkingâ and a âtestâ pressure. Since a spool has no moving parts, it seems that the two should be the same.
Vibration
When things begin to vibrate, the working pressure goes down. There are no models available to predict the effect of vibrati...
