-
7/28/2019 00021964.pdf
1/6
Summary. The risk of overloadingan atmospheric mud/gas
separator(MGS) during high-volume gas killoperations can be
minimized. Thispaper presents the theory and procedure for
minimizing this risk for hightemperature/high-pressure
(HT/HP)wells. The method can be used to setcriteria for selecting
the kill methodand for separator sizing.
570
A Method for HandlingGas Kicks Safely inHigh.Pressure WellsEric
Low, SPE, and Case Jansen, Deminex U.K. Oil & Gas Ltd.
IntroductionThe number of HT /HP wells being drilledin the North
Sea has increased rapidly. Pressures > 15,000 psi are common
with associated temperatures > 350of . The drillingand
exploitation of these reservoirs havebeen described as the new
challenge to thedrilling industry. 1 However, serious wellcontrol
incidents have compelled the industry to re-examine the equipment
and procedures used to drill these wells. 2This paper examines a
major shortcoming identified recently: the ability of rigequipment
to separate and vent large gasvolumes from mud safely. Venting
ratesfrom kicks in high-pressure wells can approach the equivalent
production of a commercial gas well.
I f he separator is overloaded, gas will beblown back into the
shale shaker room andother mud-processing facilities, creating
anextremely hazardous environment with ahigh explosion risk. Also;
live crude, condensate, and drilling mud will be expelledby the gas
through the gas vent line. On offshore rigs, where the vent line
often discharges at the top ofthe derrick, the liquidswill fall
back to the drilling rig o r platform.This creates a fire or
explosion hazard. Thevolatile condensate/oil mixture will
accumulate close to the deck in any void space andcan be ignited by
a spark. The hazards ofMGS blowdown are apparent.High reservoir
pressures and temperaturesincrease the surface gas volume per
unitvolume of gas influx. The ability of rig gasprocessing
equipment to handle such increased volumes concerns the industry.
Normal practice does not take into account thelimitations of the
separator but instead concentrates on well control, assuming that
theMGS can handle whatever gas volume ispresent.The problem is
clear. As we continue toexplore for oil and gas in deeper and
higherpressure reservoirs, we often exceed the safeoperating limits
of the MGS. Separatormodification and redesign has improved
itscapacity considerably, but space restrictions,especially on
mobile rigs, impose an inher-"Now at Deminex Norge.Copyright t 993
Society of Petroleum Engineers
ent limitation. Our lack of understanding ofthe complex
separation process has done little to improve operating procedures
andpractices.In this paper, the separation process isconsidered
from a functional standpoint, anda procedural method is developed
to reducethe risk of blowdown in an MGS. Thisprocedural method may
impose limitationson a poorly designed separator that renderthe
separator unsuitable for high-pressurework, but this method
illustrates how blowdown can be inhibited in any separator. Onthe
basis of the initial kick parameters,criteria are produced for
selection of the killmethod and parameters.GaS-Handling ProcessThe
atmospheric MGS, often called a"poor-boy" degasser or gas buster,
hadhumble beginnings. It originally consistedof a large-diameter
pipe that stood in a mudpit; gas was vented through the open
top.Modem versions are similar, but most nowinclude a
smaller-diameter vent line to discharge the gas farther from the
rig. Evolution essentially stopped here. The onlynoteworthy
introduction has been internalbaffles. For many years, the only
changesmade to the MGS were to make it smallerand lighter to save
space and weight, thusreducing the gas-handling capacity.
Morerecently, as a result of increased deep, highpressure drilling,
this trend has beenreversed. Larger MGS's, larger-diametervent
lines, and longer mud seals now are theorder of the day. Upgraded
separators stillare affected by the severe space limitationsof
drilling units.Fig. 1 illustrates a typical modem MGSwith the
following features.1. Internal baffles to encourage gas breakout
from the mud.2. Large-diameter vent lines to reducebackpressure
caused by the gas ventingfriction.3. Extended dip tubes, often into
the triptank, to improve the mud seal integrity.4. The recent
addition of vessel pressuregauges to monitor the approach
ofblowdown.5. Hydrostatic head sensors to monitor themud seal for
excessive gas cutting or oil or
June 1993 JPT
-
7/28/2019 00021964.pdf
2/6
1. Gas Vent Line2. Pressure Sensor3. Spray Tube4. Baffle Pla
tes5. Dip Tube6. Hydrostatic Sensor7. Choke Manifold8. Automatic
Choke9. Choke Line10 . Mud Processing Facilities
Fig. 1-Typical MGS.condensate contamination, which couldreduce
the mud seal integrity.Fig. 2 shows the mud/gas separation process.
The gas/mud/oil/condensate mixture iscirculated from the well
through the drilling choke. The gas now expands rapidly andcools in
these near-atmospheric conditions,accelerating the mixture through
the chokemanifold directly to the MGS spray tube.The free gas is
released, and the spray action releases a high proportion of the
gas entrained in the mud. The mud and liquidcomponents then cascade
over a series ofbaffle plates, which increases retention timein the
separator and provides further agitation to encourage the release
of additionalentrained gas. The liquid discharge is gravityfed to
the dip tube, where the liquid replacesthe old mud in the tube,
which returns tothe mud-processing facilities. The separated gas
takes the path ofleast resistance, thegas vent. This vent safely
discharges the gassome distance from the rig. The process issimple,
if somewhat crude, but has the majoradvantage of preventing
blockages, whichcould easily happen considering the highsolids
content of drilling mud.By far the largest proportion of gas
isreleased during primary separation, whichoccurs during initial
impact on entry to theseparator. The gas must then travel
throughthe mud spray to the gas vent.Separation Capacity. Prieur3
outlines acriterion for calculating the separation capacity of an
MGS based on API Spec.121.4 Prieur states that effective
separationcan be achieved only when the settling velocity of the
liquid droplets exceeds the upward velocity of the gas stream.
Theseparation capacity can be calculated fromJPT June 1993
_Mu d_ Mud/Gas at Pressure!ISlJ Mud/Gas at Atmospheric
Fig. 2-Separation process.the liquid density, gas density, gas
flow rate,and cross-sectional flow area. He quotes thefollowing
equation for the maximum allowable superficial velocity for good
separation4 :
(va)max=K[(PL -Pg)/Pg]o.S, ...... 1)where K = constant depending
on design andoperating conditions quoted in AP1 Spec.121. The range
for 5-ft vertical separatorsis 0.12 to 0.24 ft/sec and for lO-ft
verticalseparators is 0.18 to 0.35 ft/sec. The lowestin the range
should be selected to give themaximum safety margin.The following
equation for separation capacity can be derived from Prieur's
conclusions:
q s p = 7 r r ~ A ( v a ) m a x ' .............. (2)Fig. 3
illustrates the typical range ofvalues this equation will give for
variousmud weights and separator sizes.Note that Eq. 1 is valid for
the separation
of liquid droplets larger than 100 J..tm onlyif (1) the
operating temperature exceeds theoil cloud point, (2) the operating
temperature exceeds the gas hydrate point, (3) theliquid has a
minimal or no foaming tendency, and (4) uniform flow exists.It is
not possible yet to assess with anydegree of confidence whether any
of theseconditions apply to the mud/gas separationprocess. In
particular, the requirement foruniform flow is probably the most
difficultto achieve because the flow can vary from100% gas to 100%
mud. This rudimentaryexpression of mud/gas separation unfortunately
is the best available in the industry. It has been applied widely
and appearsto give reasonable results.
The construction of Eq. 1 is not the purpose of this paper, so
the equation has beenaccepted and used as stated. The development
of a more realistic expression shouldbe a priority because it is a
fundamentalbuilding block for advancing our knowledgeon this
subject.Blowdown Capacity. The second importantlimiting criterion
for MGS's is blowdowncapacity: the gas rate that will create
sufficient backpressure in the vessel, from friction in the gas
vent line, to overcome thehydrostatic fluid head in the dip
tube.The U.K. Dept. of Energy 5 favors a calculation based on a
light crude oil (0.3 psi/ft)in the mud seal. This calculation
accountsfor the possibility of condensate or lightcrude being a
constituent of the influx andcontaminating the mud. The maximum
safeworking pressure of the separator,(Psp)max, can be expressed
as
(Psp)max=Lm . ................. (3)Eq. 3 may be invalid if the
mud seal ar
rangement does not contain a substantialmud volume (e.g., "u"
tube) in which casean overall 0.3-psi/ft gradient should
beapplied.Pressure gauges fitted to the separator vessel to monitor
for blowdown must be highaccuracy/low-pressure gauges because
themaximum safe working pressure will normally be < 9 psi.The
blowdown capacity can be calculated with the Weymouth equation. 6
TheWeymouth equation is a gas pipeline expression commonly used to
calculate frictionlosses in small-diameter pipelines. The
fol-571
-
7/28/2019 00021964.pdf
3/6
"Normal practice doesnot take into accountthe limitations of
theseparator but insteadconcentrates on wellcontrol, assuming
thatthe MGS can handlewhatever gas volume ispresent."
lowing form of the equation should be usedto calculate the gas
flow rate:qg =433.45(Tabs /Pa)df-667 [(prp -P'lJ/Leq'YgTz]O.S. . .
. . . . . . . . . . . . . . . . . (4)Typical solutions to this
equation are 15to 20 MMscflD for an 8-in.-diameter ventline and 25
to 35 MMscflD for a lO-in.diameter vent line.The blowdown capacity,
as calculatedabove, assumes that there is no liquid carryover to
the vent. Comparing Fig. 3 withthe typical solutions quoted above
indicatesthat the separation capacity is exceeded, soliquid
carryover must occur. The blowdowncapacity, therefore, depends not
only on thegas rate but also on the proportion of mudvented with
the gas. The Weymouth equa
tion gives good results if only dry gas isprocessed. The
separation capacity rate alsoensures that only gas is vented.
Betweenthese two capacity figures, variable conditions allow for
variable mud/gas ratios inthe vent line. The blowdown pressure
(Eq.3) will be approached rapidly as mud content increases in the
vent line.Some older MGS designs with short (3 to4 ft) mud seals
and small (6-in.) vent linescan have separation capacities that
exceedtheir blowdown capacity. Such separatorswill have very low
gas-handling capacities,and safe separator working pressures can
be< I psi. Thankfully, most of these separators have been
replaced; they should beavoided, even for normally pressured
wells.So far we have determined the twoprimary capacity figures and
how to calculate them for an MGS under specific conditions. For
typical modern oilfield MGS's,a safety factor of 5 to 10 exists
betweenseparation and blowdown capacity. Thissafety factor is
important because it providesfor the various conditions that exist
duringa well kill.We can conclude that if a modern separator can be
controlled to operate at or below its separation capacity, the risk
ofblowdown is virtually eliminated.572
10 MMSCFD
8
6
0 8 9 10 11 12 13 14 15 16 17 18 19 20Mud Weight (ppg)
20" Separator -+ - 24" Separator -+ - 3 ~ ' ' Separator-a- 36"
Separator ~ 42" Separator -+ - 48" Separator
Fig. 3-Separation capacity.Controlling th e SeparatorDuring well
kill operations, well control isalways emphasized. The concept of
adjusting well kill parameters to control the MGSmay appear foolish
or even dangerous. " I fthe separator can't handle it, then change
theseparator" has been the main thrust of theindustry's approach to
the problem. Onemajor well kill parameter, however, isselected
arbitrarily: the kill pump rate. Thisparameter controls the rate
that the mud/gasmixture enters the MGS.Consider I bbl of mud/gas
mixture displaced through the choke. The gas will expand rapidly in
the near-atmosphericconditions, but the mud will not. The
worstpossible case occurs if the barrel contains100% gas. The whole
barrel then will expand, providing the maximum rate at whichgas can
enter the MGS. Ifwe can adjust thismaximum rate to the separation
capacity ofthe separator, we shall have gained controlunder the
worst possible scenario.The kill pump rate at which 1 bbl of
100%gas is expelled through the choke into theMGS at its separation
capacity can be calculated with the normal gas laws:Plq/Tlz l
=P2qsp/T2z2, . . . . . . . . . . (5)
orq=(P2qsp/PI)(Tl zI /T2Z2) . . . . . . . . (6)For Eq. 6, PI
must be calculated from initial kick parameters, P2 can be
verifiedwith the Weymouth equation, TI isunknown, but can be
estimated (the lowest
TI can be is ambient North Sea temperature-i.e., 40F), and T2 is
unknown, so itmust be estimated. Because we are concerned mainly
with high gas rates, adiabatic expansion may result in extremely
lowtemperatures. However, if we select OF weobtain a worst case for
q. Note that it is theratio TI/T2 that is important, not the
absolute values. z has a significant influence onthe result and
should not be ignored. It canbe obtained from gas tables or
calculatedwith an iterative routine by computer. Be-
cause the conditions inside the separator willbe close to
atmospheric, z2 = I should beused.Although we have had to estimate
the temperatures, the other variables are known orcan be
calculated. PI is the only variablethat has not yet been
addressed.Calculating the Casing Pressure. Themaximum possible
casing pressure that anygiven kick can generate will occur if the
entire kick volume is gas and that gas is immediately upstream of
the choke in anexpanded condition at the pressure requiredto
balance the bottornhole pressure (BHP).This is the classical view
of the well-controlmechanism and does not account for
kickdispersion or for gas solubility in oil-basedmud. Gas
solubility and miscibility in oilbased mud have attracted a great
deal of attention lately, especially in relation to highpressure
wells. 7-11 The effects of thesephenomena can be significant, and
all personnel involved in well control should bemade aware of this.
However, if gas is stillin solution in the oil component of the
mud,the gas rate entering the MGS will necessarily be reduced owing
to the presence ofthe mud. Gas solubility and dispersion havesome
benefits. They reduce gas rates at surface and at maximum casing
pressures. Theclassical view, therefore, provides an optimal basis
for the worst-case approach weopted for. It is fully consonant with
thepreviously mentioned premise that thehighest gas rates are
produced when 100%gas expands through the choke.To calculate the
maximum possible casingpressure, we can turn to any good
wellcontrol textbook to obtain the equations orwe can derive them
from first principles.The driller's method should be used in
thiscalculation because, if the effect of killweight mud is
ignored, the calculation issimplified and will result in a
worst-casecasing pressure. This is recommendedregardless of the
kill method used to increasethe safety margin.
June 1993 JPT
-
7/28/2019 00021964.pdf
4/6
The formula for calculating the maximumpossible casing pressure
is(Pcs)max=0.5{X+[X2 +4(pwsVbhTjZjgm)l(VannTbhZbh)] 0.5 },
............... (7)where X=Pws-[(LclVclIVann)+Drv
-Lcl]gm'Kick Decision ModelA kick decision model (KDM) was
developed to establish a logical basis for determining whether a
given gas influx could behandled safely by the MGS of the rig.
Ifnot,it would be safer to bullhead this influx backto the
formation. However, there are severalserious concerns with
bullheading.1. What bullhead pressure will be required?2. Will the
well-control equipment withstand this pressure?3. Will the wellbore
withstand thispressure?4. Will an underground blowout occur ifthe
formation is fractured?5. Can the influx be pumped back into
theformation if this influx has dispersed in themud?These are all
unknown risks. Even if aninjection rate can be established, is the
influx being pumped back or is mud beingpumped into a weaker zone?
At best, bullheading can be considered only an influxdisposal
method. It is not a kill method because kill circulations will
still be required.Bullheading sometimes can be the safest op-tion,
but if the influx can be disposed of safely at surface, circulating
normally will carryfar less risk.To fulfill the objective of the
KDM as adecision-making tool, the KDM must bebased on initial kick
parameters and mustbe able to be run immediately after a kickis
taken. The chances of a successful bullheading operation are
enhanced greatly ifthis procedure is attempted when the influxis
still close to the zone of origin.The theoretical basis of the KDM
has beendetailed in preceding sections. First, themodel calculates
the safety factor betweenseparation and blowdown capacity for
themud weight in use. Second, it dynamicallylinks the initial kick
parameters with theseparation capacity of the MGS to give
theresulting kill pump rate (Eq. 6). These twoparameters are
themselves an assessment ofthe MGS's ability to handle the influx.
Thelower the values, the poorer the MGS design. The time it takes
to circulate the influx out at surface will be the criterion,
andthis length of time may be impractical. TheKDM only shows what
will be involved inkilling the well safely. The judgment of
whatroute should be taken is influenced by otherconsiderations,
including weather, equipment, and crew experience.The form of these
calculations lends itself to computerization for speed and
accuracy. The fixed geometric data and most ofthe basic data can be
preprogrammed easily in data files. This limits the input
requirement to the initial kick parameters, whichJPT June 1993
Fig. 4-0verload MGS.makes the computer model quick and simple to
use. The model results are illustratedin the examples.Well-Control
Procedure. Assuming thatthe KDM results have been used to assistin
selection of the kill method and it has beendecided to circulate
out the influx, preparation and calculations for the kill
programthen proceed normally. The reduced killpump rate may be
selected to begin the kill,but this is unnecessary and in some
circumstances may prolong the strain on equipmentand personnel. The
reduced kill pump rateis required only when the influx
reachessurface.The reduction of heat dissipation from theinflux is
a very sound argument for circulating out gas kicks as fast as
practical. Twomain advantages can be achieved from keeping the
influx' as warm as possible.1. Gas expansion through the choke
willbe reduced if the gas is warmer. The KDMcan be used to confirm
this effect.2. A warm gas at surface reduces the riskof hydrate
formation. The initial temperature used when examining adiabatic
expansion has a dramatic effect on the finaltemperature.Therefore,
the recommended initial killcirculation rate should be as high as
the(1) choke manipulation for startup,(2) weighting up of mud
(wait-and-weightmethod), and (3) sufficient time to react
topressure anomalies will allow.The kill proceeds normally until
the influx approaches surface, when the reducedkill pump rate from
the KDM must be applied. Changing the kill circulation rate during
a kill is a procedure commonly taughtand practiced in well-control
courses. It isrecommended that circulation be stoppedand that the
well be shut in before establishing the new rate. The rate change
should bemade well before the influx reaches surfaceto establish
the new rate before the pressurefluctuations of gas being expelled
at surfacebegin. Shut-in should take place when the
" . . as a result ofdeep, high.pressuredrilling, ... argerMGS's,
larger.diametervent lines, and longermud seals now are theorder of
the day."
influx is approximately 3,500 to 4,000 ftfrom surface to provide
an adequate safetymargin. For larger influxes, earlier shut-inwould
be prudent.There are other significant advantages tostopping the
kill at this point. Final checkscan be made to prepare for
receiving the gasat surface. This also is a good time to
beginmethanol injection into the chokeline. Thispractice is
becoming more common owingto increasing awareness of the risk of
hydrate formation. Stopping the kill also provides an opportunity
to check well pressuresand mud volumes before entering this crit
ical phase of the kill.The kill continues with the reduced killpump
rate or an even lower rate. The reduced rate allows more time for
the chokemanipulation required when the gas reachessurface. Use of
the lower rate also allowsmore time to read and react to MGS
pressure changes and to blowout preventer(BOP) and chokeline
temperature changes.Although this technique will drasticallyreduce
the risk of MGS blowdown, contingency plans should always be in
place incase blowdown occurs. Blowdown will firstbe detected by the
MGS vessel pressuregauge, but reaction to and implementationof
these plans will have to be speedy.Procedure Summary.
1. Begin kill with the highest practical killpump rate.2. Shut
down the kill and shut in the wellwhen the influx is still some
distance fromsurface.3. Prepare for handling the influx at surface,
check equipment, and confirm wellpressures and mud volumes. Begin
methanolinjection (if required).4. Resume kill circulation with the
reduced kill pump rate, maintaining that rateuntil all the gas is
expelled.5. Monitor MGS vessel pressure and beprepared to proceed
with the blowdown contingency plan if required.
573
-
7/28/2019 00021964.pdf
5/6
Application to North SeaWell KicksExample 1. This method was
appliedretroactively to North Sea well kicks withknown parameters
to validate the KDM. Inone example of a well kick, in a
12IA-in.hole, the MGS was overloaded (see Fig. 4).The initial kick
parameters were shut-indrillpipe pressure, 2,433 psi; shut-in
casingpressure, 2,553 psi; pit gain, 25 bbl; truevertical depth
(TVD), 7,800 ft; mud (oilbased) weight in use, 10.6 Ibm/gal; and
bottornhole static temperature (BHST), 180F(estimated). The
following data also are required for the calculations: Lel=40.0
ft,Vel =0.0087 bbllft, Vann =0.1245 bbl/ft,di=6.0 in., Leq =0.0652
miles, Ti = 1.208ft, and K =0.12. The typical North Sea gasspecific
gravity relative to air, 0.7, wasused.The kick was circulated out
at 30strokes/minute (3.47 bbllmin). The KDMwas run with the well
data listed above, andthe results indicated that the kill pump
rateshould have been reduced to 0.8 bbl/min toprevent liquid
carryover to the gas vent.Although the eruption was short lived-l
to2 minutes-gas rates could have reachedmore than 7 MMscf/D during
that period.This example shows that ifKDM conceptshad been applied,
this dangerous incidentmay have been avoided.Example 2. Turner2
published the data forthis example. Some peripheral geometricdata
were not included in Turner's publication, but these have been
assumed fromgeneral rig layouts. In Turner's publication,Well E
experienced a severe kick in a 9.5-in.hole at 14,818 ft. Severe
gassing and freezing were reported when the influx was atsurface.
The initial kick parameters wereshut-in drillpipe pressure, 4,400
psi; shutin casing pressure, 5,300 psi; pit gain, 90bbl; TVD,
14,818 ft; mud weight in use,12.2 Ibm/gal; and BHST, 260F
(estimated). The following data also are required forthe
calculations: Lel=400.0 ft, Vel=0.87bbl/ft, Vann =0.0634 bbl/ft, d
j =8.0 in.,Leq =0.062 miles, Ti = 1.208 ft, andK=0.18. The typical
North Sea gas specific gravity relative to air, 0.7, was used.The
KDM calculations show that a maximum kill pump rate of 1.0 bbllmin
shouldhave been used. A secondary kick was allowed into the
wellbore, however, resultingin 8,OOO-psi casing pressure. The KDM
wasadjusted to reflect this situation, with a resulting kill rate
of 0.7 bbllmin.This was a problematic kill, partly because of the
large gas/condensate disposalproblem. The KDM could have assisted
withthis problem to reduce severe gassing of therig.Example 3.
Here, the kick decision andseparator control concepts were
integratedfully into the policies of Deminex U.K. Oil& Gas Ltd.
when they drilled a highpressure well in Block 22/16b of the
U.K.Continental Shelf in 1990. On this well, asevere kick was taken
at 13,080 ft in a574
12 IA-in. hole. The initial kick parameterswere shut-in
drillpipe pressure, 2,000 psi;shut-in casing pressure, 2,170 psi;
pit gain,7 bbl; TVD, 13,080 ft; mud (oil-based)weight in use, 13
Ibm/gal; and BHST,276F (calculated). The following data alsoare
required for the calculations: Lcl=400.0 ft, Vel =0.0087 bbllft,
Vann =0.1237bbllft, d; = 10.0 in., Leq =0.0642 miles,T;=1.239 ft,
and K=0.18. The typicalNorth Sea gas specific gravity relative to
air,0.7, was used.The KDM was run and an anomaly washighlighted.
The influx hydrostatic gradientwas negative. This situation can
occur if theinflux volume has been underestimated, theinflux has
migrated, or pressure has beentrapped during shut-in. None of
theseprovided a satisfactory explanation in thiscase. Gauge error
is believed to have causedthe problem. The difference between
thedrillpipe and casing pressures is used in thegradient
calculation. This value is small, andthe normal inaccuracy of both
gauges wouldbe sufficient to account for the anomaly.The reduced
kill pump rate was calculated as 1.6 bbllmin. The kick was
circulatedout with the reduced kill pump rate throughout. The small
volume of the influx madeidentification difficult even at surface.
It didcontain gas but in an insufficient amount toaccount for the
entire volume.Perhaps this illustration of the usefulnessof the KDM
is less-than-optimal, but it doesindicate that the concept has been
adoptedand applied by a North Sea operator. Theadvantages of using
the KDM on this occasion may have been limited, but its useprovided
clear insight, boosted confidencein the company's ability to
dispose of theinflux, and strengthened the company'sresolve to
devote 15 hours to completing thekill circulation.ConclusionsThe
procedural technique presented will inhibit atmospheric MGS
blowdown duringwell-control operations. The technique hasbeen
verified with high-severity-kick datafrom North Sea wells. The
following conclusions are drawn.1. It is feasible and desirable to
controlthe maximum rate at which gas enters anMGS.2. The risk of
blowdown in an MGS isreduced greatly if gas is limited to
separation capacity.
3. A kill pump rate that expels the influxat a rate that does
not exceed the separationcapacity can be calculated.4. This kill
pump rate itself is an assessment of the ability of the MGS to
handle theinflux safely.5. This assessment can be used as a
basisfor selecting optimal well-control
procedures.AcknowledgmentsWe thank Deminex U.K. Oil & Gas
Ltd.,for whom this work was carried out, fortheir kind permission
to publish this paper.
Thanks also are due Eric Turner, who encouraged us to
publish.Nomenclature
A = 86,400 seconds (conversionconstant from seconds todays), t,
secondsd j = ID, L, in.D IV = TVD, L, ftgm = mud gradient, psi/ftK
= constant, Lit, secondsLel = chokeline length, L, ftLeq =
equivalent length, L, milesLm = mud seal length, L, ftP = pressure,
m/Lt2, psiPa = atmospheric pressure, m/Lt2,14.7 psiPcs = shut-in
casing pressure,m/Lt2, psiPsp = MGS pressure, m/Lt2, psiPws =
shut-in BHP, psiPI = choke pressure with 100%gas, m/Lt2, psiaP2 =
pressure in the separatorvessel that, at separation
capacity rates, will be closeto atmospheric pressure(14.7 psia),
m/Lt2q = kill pump rate, L 31t, bbl/min
qg = gas flow rate, L 31t, sefIDqsP = separation capacity,
L3/t,scf/D
Ti = internal radius, L, ftT = temperature, T, ORTabs = standard
absolute temperature,
T,520oRTbh = BHST, T, ORTI = gas temperature upstream ofthe
choke, T, ORT2 = temperature inside theseparator, T, ORva =
allowable superficial velocity,Lit, ft/secV = volume, L3, bbl
Vann = annular volume, L3/L, bbllftVbh = bottornhole influx
volume,L3, bblVel = chokeline volume, L3/L,
bbllftz = gas compressibility factor,dimensionless
Zbh = gas compressibility factor inbottomhole
conditions,dimensionlessZ I = gas compressibility factor
inconditions upstream of thechoke, dimensionlessZ2 = gas
compressibility factor inthe conditions inside theseparator,
dimensionless'Yg = specific gravity of gas relativeto air,
dimensionlessPg = gas density, m/L3, Ibm/ft3PL = liquid density,
m/L3, Ibm/ft3
Subscriptsmax = maximumJune 1993 JPT
-
7/28/2019 00021964.pdf
6/6
References1. Low, E. and Seymour, K. P.: "The Drillingand
Testing of High-Pressure Gas Condensate Wells in the North Sea,"
paper SPE17224 presented at the 1988 IADC/SPE Drilling Conference,
Dallas, Feb. 28-March 2.2. Turner, E.B.: "Well Control When
DrillingWith Oil-Based Mud-Recent British Experience in Deep
Wells," Offshore Technolo
gy Report OTH 86 260, Her Majesty'sStationary Office, London
(1986).3. Prieur, J.M. : "Drilling and Control Aspectsof
High-Pressure Deep Wells," paper SPE19245 presented at the 1989 SPE
OffshoreEurope Conference, Aberdeen, Sept. 5-8.4. Spec. 12J Oil and
Gas Separators, seventhedition API, Dallas (Oct. 1, 1989).5. Safety
Notice PED4 11170, U.K. Dept. ofEnergy, Her Majesty's Stationary
Office,London, Nov. 1990.6. Slider, H.C.: Worldwide Practical
Petrole-um Reservoir Engineering Methods, PennWell Publishing Co.,
Tulsa, OK (1983).
7.0'Bryan, P.L. and Bourgoyne, A.T. Jr.:"Swelling of Oil-Based,
Drilling Fluids Re-sulting From Dissolved Gas," SPEDE (June1990)
149-55.8. O'Bryan, P.L. and Bourgoyne, A.T. Jr.:"Methods for
Handling Drilled Gas in OilBased Drilling Fluids," SPEDE (Sept.
1989)237-46; Trans., AIME, 287.9. Thomas, D.C., Lea, J.F., and
Turek, E.A.:"Gas Solubility in Oil-Based Drilling Fluids:Effects on
Kick Detection," JPT(June 1984)959-68.10. O'Brien, T.B.: "Handling
Gas in Oil MudTakes Special Precautions," World Oil (Jan.1981)
83-86.11. Swanson, B.W. et al.: "Experimental Measurement and
Modeling of Gas Solubility inInvert-Emulsion Drilling Fluids
Explains Surface Observations During Kicks, " paper SPE18371
presented at the 1988 SPE EuropeanPetroleum Conference, London,
Oct. 16-19.
JPT June 1993
General ReferencesTurner, E.B.: "Rig Procedures and Handling
De-cisions for Kicks in Deep Hot Holes With OilBased Mud," Drilling
and Production Training Centre, Aberdeen.Hoopingarner, J.B. et al.:
"Rig ModificationsMeet New U.K. High-Pressure Requirements," paper
SPE 19976 presented at the 1990IADC/SPE Drilling Conference,
Houston, Feb.
27-March 2.White, D.B. and Walton, I.C.: "A ComputerModel for
Kicks in Water- and Oil-BasedMud," paper SPE 19975 presented at the
1990IADC/SPE Drilling Conference, Houston, Feb.27-March 2.SI Metric
Conversion Factors
bbl x 1.589 873ft x 3.048*ft3 x 2.83\ 685OF (OF-32)/1.8gal x
3.785412in. X 2.54*Ibm x 4.535 924mile x 1.609 344"psi x 6.894
757OR R/I.8
Conversion factor is exact.
Provenance
E-OI = m3E-OI = mE-02 = m3
= CE-03 = m 3E+OO = emE-OI = kgE+OO = IanE+OO = kPa
= K
Original SPE manuscript, A Method forHandling Gas ,Kicks Safely
in HighPressured Wells, received for reviewMarch 11, 1991. Revised
manuscript received Nov. 19, 1992. Paper accepted forpublication
Jan. 4, 1993. Paper (SPE 21964)first presented at the 1991 SPE/IADC
Drilling Conference held in Amsterdam, March11-14.JPT
Authors
Low JansenEric Low Is a consultant drilling su-perintendent for
Demlnex U.K. 011 & GasLtd. His experience with HPHT wells
be-gan in 1979, when he worked in the Tus-caloosa trend, with
Chevron U.S.A. Itcontinued with Ranger Oil U.K. Ltd where he became
drilling manager. Heholds a as degree in physics and adiploma In
offshore engineering fromRobert Gordon U. in Aberdeen. Ca..Jan.. Is
head of Drl1l1ng with Demlnex Norge In Stavenger. In 1964. hejoined
Royal Dutch Shell and worked asa drilling operations engineer In
variouscountries. He Joined Demlnex In 1980 asdrill ing manager. In
1989-90, he was In-volved in the programming and manage-ment of
their first HTIHP well In the U.K.Jansen holds a as degree In
mechanl-cal engineering from the Technical U. atDelft, The
Netherlands.
575
