Provides new techniques for blowout containment, never before published, first used in the Gulf War.
Provides the most up-to-date techniques and tools for blowout and well control.
New case histories include the Kuwait fires that were set by Saddam Hussein during the Gulf War.
As with his 1994 book, Advanced Blowout and Well Control, Grace offers a book that presents tested practices and procedures for well control, all based on solid engineering principles and his own more than 25 years of hands-on field experience. Specific situations are reviewed along with detailed procedures to analyze alternatives and tackle problems. The use of fluid dynamics in well control, which the author pioneered, is given careful treatment, along with many other topics such as relief well operations, underground blowouts, slim hole drilling problems, and special services such as fire fighting, capping, and snubbing. In addition, case histories are presented, analyzed, and discussed. Provides new techniques for blowout containment, never before published, first used in the Gulf War Provides the most up-to-date techniques and tools for blowout and well control New case histories include the Kuwait fires that were set by Saddam Hussein during the Gulf War
front cover 1
copyright 5
table of contents 6
front matter 10
Preface 10
body 14
1. EQUIPMENT IN WELL CONTROL OPERATIONS 14
PRESSURE, EROSION, CORROSION, AND VIBRATION 16
PRESSURE 16
VIBRATION 16
EROSION 17
CORROSION 24
THREADED CONNECTIONS 25
THE STACK 26
THE CHOKE LINE 28
THE CHOKE MANIFOLD 32
THE VALVES 32
THE DRILLING CHOKE 36
THE PANIC LINE 39
THE HEADER 39
THE SEPARATOR 41
THE KILL LINE 45
THE STABBING VALVE 46
2. CLASSIC PRESSURE CONTROL PROCEDURES WHILE DRILLING 50
CAUSES OF WELL KICKS AND BLOWOUTS 51
MUD WEIGHT LESS THAN FORMATION PORE PRESSURE 51
FAILURE TO KEEP THE HOLE FULL AND SWABBING WHILE TRIPPING 52
LOST CIRCULATION 52
MUD CUT 52
INDICATIONS OF A WELL KICK 53
SUDDEN INCREASE IN DRILLING RATE 53
INCREASE IN PIT LEVEL OR FLOW RATE 53
CHANGE IN PUMP PRESSURE 53
REDUCTION IN DRILLPIPE WEIGHT 54
GAS, OIL, ORWATER-CUT MUD 54
SHUT-IN PROCEDURE 54
CIRCULATING OUT THE INFLUX 59
THEORETICAL CONSIDERATIONS 59
THE DRILLER’S METHOD 65
THEWAIT AND WEIGHT METHOD 81
SUMMARY 2 100
3. PRESSURE CONTROL PROCEDURES WHILE TRIPPING 101
CAUSES OF KICKS WHILE TRIPPING 102
TRIP SHEETS AND FILLING PROCEDURES 103
PERIODIC FILLING PROCEDURE 106
CONTINUOUS FILLING PROCEDURE 109
TRIPPING INTO THE HOLE 112
SHUT-IN PROCEDURE 113
WELL KICKS WHILE TRIPPING 113
STRIPPING IN THE HOLE 116
4. SPECIAL CONDITIONS, PROBLEMS, AND PROCEDURES IN WELL CONTROL 128
SIGNIFICANCE OF SURFACE PRESSURES 129
A KICK IS TAKEN WHILE DRILLING 129
INFLUX MIGRATION 133
SAFETY FACTORS IN CLASSICAL PRESSURE CONTROL PROCEDURES 154
CIRCULATING A KICK OFF BOTTOM 158
CLASSICAL PROCEDURESÛPLUGGED NOZZLE EFFECT 160
CLASSICAL PROCEDURESÛ DRILL STRINGWASHOUT EFFECT 160
DETERMINATION OF SHUT-IN DRILLPIPE PRESSURES 162
DETERMINATION OF THE TYPE OF FLUID THAT ENTERED THE WELLBORE 163
FRICTIONAL PRESSURE LOSSES 165
ANNULUS PRESSURE PROFILES WITH CLASSICAL PROCEDURES 169
CONSTANT CASING PRESSURE, CONSTANT DRILLPIPE PRESSURE, AND MODIFICATION OF THEWAIT AND WEIGHT METHOD 188
THE LOW CHOKE PRESSURE METHOD 190
REVERSE THE BUBBLE OUT THROUGH THE DRILLPIPE 191
THE OVERKILLWAIT AND WEIGHT METHOD 196
SLIM HOLE DRILLINGÛ CONTINUOUS CORING CONSIDERATIONS 199
STRIPPING WITH INFLUX MIGRATION 204
OIL-BASE MUD IN PRESSURE AND WELL CONTROL OPERATIONS 209
FIRE 210
SOLUBILITY OF NATURAL GAS IN OIL-BASE MUD 211
FLOATING DRILLING AND SUBSEA OPERATION CONSIDERATIONS 215
SUBSEA STACK 215
SPACING OUT 218
SHUT-IN PROCEDURES 218
FLOATING DRILLING WELL CONTROL PROBLEMS 219
DEEP-WATER FLOATING DRILLING 223
SHALLOW GAS KICKS 228
5. FLUID DYNAMICS IN WELL CONTROL 230
KILL-FLUID BULLHEADING 231
KILL-FLUID LUBRICATION— VOLUMETRIC KILL PROCEDURE 241
DYNAMIC KILL OPERATIONS 262
THE MOMENTUM KILL 273
6. SPECIAL SERVICES IN WELL CONTROL 282
SNUBBING 282
EQUIPMENT AND PROCEDURES 283
EQUIPMENT SPECIFICATIONS 297
BUCKLING CONSIDERATIONS 300
SPECIAL BUCKLING CONSIDERATIONS: VARIABLE DIAMETERS 309
FIRE FIGHTING AND CAPPING 315
FIRE FIGHTING 315
EXTINGUISHING THE FIRE 320
CAPPING THE WELL 321
FREEZING 324
HOT TAPPING 325
JET CUTTING 326
7. RELIEF WELL DESIGN AND OPERATIONS 328
HISTORY 328
ULSEL AND MAGNETIC INTERPRETATION INTRODUCED 328
SCHAD’S CONTRIBUTION 331
MAGRANGE DEVELOPED 331
WELLSPOT DEVELOPED 332
MAGRANGE AND WELLSPOT COMPARED 335
RELIABILITY OF PROXIMITY LOGGING 337
RELIABILITY OF COMMERCIAL WELLBORE SURVEY INSTRUMENTS 339
SUBSURFACE DISTANCE BETWEEN RELIEF WELL AND BLOWOUT 343
SURFACE DISTANCE BETWEEN RELIEF WELL AND BLOWOUT 346
SUMMARY 7 347
RELIEF WELL PLAN OVERVIEW 348
8. THE UNDERGROUND BLOWOUT 353
CASING LESS THAN 4000 FEET 361
PIPE BELOW 4000 FEET 372
CHARGED INTERVALS—CLOSE ORDER SEISMIC— VENT WELLS 382
SHEAR RAMS 384
CEMENT AND BARITE PLUGS 385
9. CASE STUDY: THE E. N. ROSS NO. 2 388
ANALYSIS OF THE BLOWOUT 399
THE DRILLING AND FISHING OPERATION 399
THE KICK 399
THE SNUBBING PROCEDURE 401
THE SIGNIFICANCE OF THE SURFACE PRESSURES 412
THE SNUBBING OPERATION TO JULY 14 412
THE SNUBBING OPERATION, JULY 15 414
THE CIRCULATING PROCEDURE, JULY 15 414
ALTERNATIVES 419
OBSERVATIONS AND CONCLUSIONS 424
10. CONTINGENCY PLANNING 425
11. THE AL-AWDA PROJECT: THE OIL FIRES OF KUWAIT 429
OVERVIEW OF THE PROJECT 429
THE PROBLEMS 437
THE WIND 437
LOGISTICS 438
WATER 438
GROUND FIRES 440
OIL LAKES 441
THE COKE PILES 442
CONTROL PROCEDURES 442
THE STINGER 443
THE CAPPING SPOOL 444
THE CAPPING STACK 444
EXTINGUISHING THE FIRES 447
WATER 447
NITROGEN 450
EXPLOSIVES 450
NOVEL TECHNIQUES 450
CUTTING 451
STATISTICS 453
SAFETY 456
CONCLUSION 11 457
EPILOGUE 458
Index 478
CHAPTER ONE EQUIPMENT IN WELL CONTROL OPERATIONS
“… I could see that we were having a blowout!” Gas to the surface at 0940 hours.
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 3-inch hammer union in the line between the manifold and the atmospheric-type “poor-boy” 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 an advanced blowout and well control operations manual, its purpose is not to present the routine discussion of blowout preventers 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 “It will work great, if we don’t need it!” applies to many well control systems. The fact is, 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 “i” must be dotted and every “t” 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, “How long is all this s—going to stay together?” The answer to that question is usually a function of the items listed above—pressure, 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 blowout preventer 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 “working” and a “test” pressure, but it is natural to wonder how a spool can have a “working” and a “test” 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 vibration. All connections have a tendency to loosen when vibrated violently. As will be outlined in Chapter 9, at the E.N. Ross, a chicksan on a pump in line on the rig floor vibrated loose during the final kill attempt. Due to the presence of hydrogen sulfide, the gas was ignited and the rig was lost.
EROSION
Erosion of the well control system is the most serious problem normally encountered. When circulating out kicks and bubbles in routine drilling operations, erosion is not generally a factor. The exposure time is short and the velocities of the fluids are minimal. Therefore, almost any arrangement will suffice. It is usually under adverse conditions that things begin to fail. That is the reason most well control systems are inadequate for difficult conditions. Difficult conditions just do not happen that often.
In the time frame of most well control incidents, dry gas simply does not significantly erode; at least nothing harder than N-80 grade steel. At a production well blowout in North Africa, the flow rate was determined to be approximately 200 mmscf along with about 100,000 barrels of oil per day. The well flowed for almost six weeks with no significant erosion on the wellhead or flow lines. Thickness testers were used to monitor critical areas and showed no significant thickness reduction.
At a deep blowout in the southern United States, the flow rate was determined to be well over 100 mmscfpd through the 3-inch drillpipe by 7-inch casing annulus. The flowing surface pressure was less than 1000 psi. There was great concern about the condition of the drillpipe—would it be eroded or perhaps even severed by the flow? After about 10 days exposure, the drillpipe was recovered. At the flow cross, the drillpipe was shiny. Other than that, it was unaffected by the exposure to the flow.
Unfortunately, the industry has no guidelines for abrasion. Erosion in production equipment is well defined by API RP 14E. Although production equipment is designed for extended life and blowout systems are designed for extreme conditions over short periods of time, the API RP 14E offers insight into the problems and variables associated with the erosion of equipment under blowout conditions. This Recommended Practice relates a critical velocity to the density of the fluid being produced. The equations given by the API are as follows:
(1.1)
(1.2)
(1.3)
Where:
Ve = Fluid erosional velocity, ft/sec
c = Empirical constant
= 125 for non-continuous service
= 100 for continuous service
ρ = Gas/liquid mixture density at operating temperature, lbs/ft3
P = Operating pressure, psia
Sl = Average liquid specific gravity
R = Gas/liquid ratio, ft3/bbl at standard conditions
T = Operating temperature, °Rankine
Sg = Gas specific gravity
z = Gas compressibility factor
A = Minimum cross-sectional flow area required, in2/1000 bbls/day
Equations 1.1, 1.2, and 1.3 have been used to construct Figure 1.1, which has been reproduced from API RP 14E and offers insight into the factors affecting erosion. Because the velocity of a compressible fluid increases with decreasing pressure, it is assumed that the area required to avoid erosional velocities increases exponentially with decreasing pressure.
Figure 1.1 Erosional Velocity Chart.
It is, however, interesting that pursuant to Figure 1.1 and Equations 1.1 through 1.3, a high...
| Erscheint lt. Verlag | 3.10.2003 |
|---|---|
| Sprache | englisch |
| Themenwelt | Naturwissenschaften ► Geowissenschaften ► Geologie |
| Technik ► Bergbau | |
| Technik ► Elektrotechnik / Energietechnik | |
| ISBN-10 | 0-08-047616-3 / 0080476163 |
| ISBN-13 | 978-0-08-047616-2 / 9780080476162 |
| Haben Sie eine Frage zum Produkt? |
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