A maior rede de estudos do Brasil

Grátis
Applied Drilling Engineering

Pré-visualização | Página 11 de 50

pipe removed, a kick mav be in 
progress. 
Small trip tanks provide the best means of 
monitoring hole fill-up volume. Trip tanks usually 
hold 10 to 15 bbl and have 1-bbl gauge markers. Two 
alternative trip-tank arrangements are illustrated in 
Fig. 1.42. With either iuraniement, the hole is 
maintained full as pipe is withdrawn from the well. 
Periodically, the trip tank is refilled using the mud 
pump. The top of a gravity-feed type trip tank must 
be slightly lower than the bell nipple to prevent mud 
from being lost to the flowline. The required fill-up 
volume is determined by periodically checking the 
fluid level in the trip tank. When a trip tank is not 
installed on the rig, hole fill-up volume should be 
determined by counting pump strokes each time the 
hole is filled. The level in one of the active pits should 
not be used since the active pits are normally too 
large to provide sufficient accuracy. 
• 
ROTARY DRILLING PROCESS 
c: 
" E 
.e-
" 0" w 
0> 
0: 
__, 
z 
0 
>-
"' 2 
:; 
0 
u 
23 
Fig. 1.43- Example ram-type blowout preventer. 
The flow of fluid from the well caused by a kick is 
stopped by use of special pack-off devices called 
blowout preventers (BOP's). Multiple BOP's used in 
a series are referred to collectively as a BOP stack. 
The BOP must be capable of terminating flow from 
the well under all drilling conditions. When the 
drillstring is in the hole, movement of the pipe 
without releasing well pressure should be allowed to 
occur. In addition, the BOP stack should allow fluid 
circulation through the well annulus under pressure. 
These objectives usually are accomplished by using 
several ram preventers and one annular preventer. 
An example of a ram preventer is shown in Fig. 
1.43. Ram preventers have two packing elements on 
opposite sides that close by moving toward each 
other. Pipe rams have semicircular openings which 
match the diameter of pipe sizes for which they are 
designed. Thus the pipe ram must match the size of 
pipe currently in use. If more than one size of 
drillpipe is in the hole, additional ram preventers 
must be used in the BOP stack. Rams designed to 
close when no pipe is in the hole are called blind 
rams. Blind rams will flatten drillpipe if inadvertently 
closed with the drillstring in the hole but will not stop 
the flow from the well. Shear rams are blind rams 
designed to shear the drillstring when closed. This 
will cause the drillstring to drop in the hole and will 
stop flow from the well. Shear rams are closed on 
pipe only when all pipe rams and annular preventers 
have failed. Ram preventers are available for 
working pressures of 2,000, 5,000, 10,000, and 
· 15,000 psig. 
Annular preventers, sometimes called bag-type 
preventers, stop flow from the well using a ring of 
synthetic rubber that contracts in the fluid passage. 
The rubber packing conforms to the shape of the 
pipe in the hole. Most annular preventers also will 
close an open hole if necessary. A cross section of 
one tyoe of annular preventer is shown in Fig. 1.44. 
Annular preventers are available for working 
pressures of 2,000, 5,000, and 10,000 psig. 
Both the ram and annular BOP's are closed 
hydraulically. In addition, the ram preventers have a 
screw-type locking device that can be used to close 
the preventer if the hydraulic system fails. The an-
nular preventers are designed so that once the rubber 
element contacts the drillstring, the well pressure 
helps hold the preventer closed. 
Modern hydraulic systems used for closing BOP's 
are high-pressure fluid accumulators similar to those 
developed for aircraft fluid control systems. An 
example vertical accumulator is shown in Fig. 1.45. 
The accumulator is capable of supplying sufficient 
high-pressure fluid to close all of the units in the BOP 
stack at least once and still have a reserve. Ac-
cumulators with fluid capacities of 40, 80, or 120 gal 
and maximum operating pressures of 1,500 or 3,000 
psig are common. The accumulator is maintained by 
a small pump at all times, so the operator has the 
ability to close the well immediately, independent of 
normal rig power. For safety, stand-by accumulator 
pumps are maintained that use a secondary power 
source. The accumulator fluid usually is a non-
corrosive hydraulic oil with a low freezing point. The 
hydraulic oil also should have good lubricating 
characteristics and must be compatible with synthetic 
rubber parts of the well-control system. 
The accumulator is equipped with a pressure-
regulating system. The ability to vary the closing 
pressure on the preventers is important when it is 
necessary to strip pipe (lower pipe with the preventer 
closed) into the hole. If a kick is taken during a trip, 
it is best to strip back to bottom to allow efficient 
circulation of the formation fluids from the well. The 
• 
0 
u 
-c 
"' I 
0 
"' 
"' 
" ~ 
0 
u 
~ 
> 
" E 
0 
0 
"' 0 
24 
Fig. 1.44- Example annular-type blowout preventer. 
~ 
~ 
=> 
0 
u 
Fig. 1.45- Example accumulator system. 
application of too much closing pressure to the 
preventer during stripping operations causes rapid 
wear of the sealing element. The usual procedure is to 
reduce the hydraulic closing pressure during stripping 
operations until there is a slight leakage of well fluid. 
Stripping is accomplished most easily using the 
annular preventer. However, when the surface well 
pressure is too great, stripping must be done using 
two pipe ram preventers placed far enough apart for 
external upset tool joints to fit between them. The 
upper and lower rams must be closed and opened 
alternately as the tool joints are lowered through. 
Space between ram preventers used for stripping 
operations is provided by a drilling spool. Drilling 
spools also are used to permit attachment of high-
pressure flowlines to a given point in the stack. These 
high-pressure flowlines make it possible to pump into 
the annulus or release fluid from the annulus with the 
BOP closed. A conduit used to pump into the an-
nulus is called a kill line. Conduits used to release 
fluid from the annulus may include a choke line, a 
diverter line, or simply a flowline. All drilling spools 
must have a large enough bore to permit the next 
string of casing to be put in place without removing 
the BOP stack. 
The BOP stack is attached to the casing using a 
casing head. The casing head, sometimes called the 
braden head, is welded to the first string of casing 
APPLIED DRILLING ENGINEERING 
Fig. 1.46- Example remote control panel for operating 
blowout preventers. 
cemented in the well. It must provide a pressure seal 
for subsequent casing strings placed in the well. Also, 
outlets are provided on the casing head to release any 
pressure that might accumulate between casing 
strings. 
The control panel for operating the BOP stack 
usually is placed on the derrick floor for easy access 
by the driller. The controls should be marked clearly 
and identifiably with the BOP stack arrangement 
used. One kind of panel used for this purpose is 
shown in Fig. 1.46. 
The arrangement of the BOP stack varies con-
siderably. The arrangement used depends on the 
magnitude of formation pressures in the area and on 
the type of well control procedures used by the 
operator. API presents several recommended 
arrangements of BOP stacks. Fig. 1.47 shows typical 
arrangements for 10,000- and 15,000-psi working 
pressure service. Note that the arrangement 
nomenclature uses the letter "A" to denote an an-
nular preventer, the letter "R" to denote a ram 
preventer, and the letter "S" to denote a drilling 
spool. The arrangement is defined starting at the 
casing head and proceeding up to the bell nipple. 
Thus, Arrangement RSRRA denotes the use of a 
BOP stack with