aberdeen drilling school - hpht

DRILL FLOOR LEVEL

TO SHALE SHAKER

MAIN DECK LEVEL

36" DIAMETERMUD - GAS

SEPERATOR

VENT TO TOP OFDERRICK10" VENT

FROM C & KMANIFOLD, 4" PIPE

REMOTECHOKE

TO SHALESHAKER TO CEMENT UNIT

MUD PUMPS

REMOTECHOKE

TOSTARBOARDFLARE LINE

KILL LINE CHOKE LINE

SEA LEVEL

FLEX JOINT

ANNULARPREVENTEE

6

TO PORTFLARE LINE

REMOTELYACTUATED

TO MUD/GASSEPARATOR

MANUALCHOKE

MANUALCHOKE

6 Meters

GLYCOLINJECTION

POINT

5

4

3

21

8

7DIP TUBE

PRESSURESENSOR

MGSPRESSURE

SENSOR

DOWNSTREAMCHOKE TEMP.

SENSOR

DOWNSTREAMCHOKE TEMP.

SENSOR

UPSTREAMCHOKE TEMP.

SENSOR

UPSTREAM KILLLINE TEMP.

SENSOR

REMOTE CHOKE AREA SUBSEA TEMP.SENSORSUBSEA TEMP.

SENSOR

PORTSTBDMGS

DATA MONITORING SYSTEMAND BYPASS CONTROL UNIT

UPSTREAMKILL LINE

TEMP.

DOWNSTREAMCHOKE

TEMP.

MGS

7

8

1,2

3

5,6

4

OPEN CLOSED OPEN CLOSED OPEN CLOSED

DECK LEVEL

UPSTREAMCHOKE LINE

PRESSURE TEMP.

DIP TUBE BOP

ALARM

TEMP.PRESSURE

HPHT

HIGH PRESSUREHIGH BOTTOM HOLE TEMPERATURE

Aberdeen Drilling Schools&Well Control Training Centre

This course has been prepared by Aberdeen Drilling Schoolsusing industry standard HPHT operational guidelines.

OBJECTIVES OF THE COURSE

To introduce HPHT operations and highlight the concernsand hazards of drilling HPHT wells.

To encourage operational personnel to offer suggestionsand recommendations to improve the existing guidelinesand procedures for drilling HPHT wells.

To promote team building between onshore and offshore drilling personnel.

50 Union Glen, Aberdeen AB11 6ER, Scotland, U.K. Tel: (01224) 572709 Fax: (01224) 582896E-mail [email protected] www.aberdeen-drilling.com

AB

ERDE

EN DRILLING SCHOOLS

&WELL CONTROL TRAINI

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Section

1 COURSE INTRODUCTION

2 GAS BEHAVIOUR, KICKS AND CONTROL

3 GAS SOLUBILITY IN OBM'S - EFFECTS ON KICKBEHAVIOUR

4 RIG EQUIPMENT SUMMARY

5 SURFACE GAS HANDLING CAPACITIES ANDPROCEDURES FOR HPHT WELLS

6 DRILLING AND WELL CONTROL PROCEDURES FORHPHT WELL PROGRAMMES, TRAINING ANDCOMMUNICATION

7 SHUT-IN PROCEDURES AND DECISION TREES

8 BULLHEADING OVERVIEW

9 VOLUMETRIC METHOD OF WELL CONTROL

10 STRIPPING

11 THE EFFECTS OF TEMPERATURES ANDPRESSURES ON MUDS

12 THE EFFECTS OF BOREHOLE BALLOONING ONDRILLING RESPONSES

13 MANAGEMENT OF OPERATIONS

14 SAMPLE HPHT WELL CONTROL PROCEDURES (SEMI)

15 SAMPLE HPHT WELL CONTROL PROCEDURES (JACK-UP)

Appendix 1. UKOOA GUIDELINES FOR HPHT WELLSAppendix 2. NPD GUIDELINES FOR HPHT WELLSAppendix 3. HPHT MUD PRESENTATION

Appendix 4. HPHT CEMENT PRESENTATION

CONTENTS

HPHT Course ABERDE

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1. COURSE INTRODUCTION

CONTENTS

1.1 GENERAL OVERVIEW

1.2 LEARNING FROM THE PAST

1 - 2

HPHT Course - Section 1

1.1 GENERAL OVERVIEW

HSE Definition for HPHT Wells:

Where the undisturbed bottomhole temperature is greater then 150o C/300o Fand where either the maximum anticipated pore pressure of any porousformation exceeds 0.8 psi/ft., or pressure control equipment with a ratedworking pressure in excess of 10,000 psi, is required.

1.2 LEARNING FROM THE PAST

BACKGROUND AND HISTORY OF HPHT WELLS

(A)

Primary Well Control

B.H.P. > Pf(i.e.) Mud

(B)

Secondary Well Control

B.O.P.E. Equipment

(C)

Tertiary Well Control

Special or Unusual Problems

1 - 3


DRILL PIPE :SIDPP + HYDROSTATIC PRESSURE OF MUD = FORMATION PRESSURE

ANNULUS :SICP + HYDROSTATIC PRESSURE OF MUD + HYDROSTATICPRESSURE OF INFLUX = FORMATION PRESSURE

800 psi / 55 bar

1220 psi / 84 bar

9100 psi / 628 bar

9900 psi / 683 bar

9900 psi683 bar

FORMATIONPRESSURE

DRILL PIPEPRESSURE

CASINGPRESSURE

MUD HYDROSTATICPRESSURE IN THEANNULUS

TOTAL PRESSUREACTING DOWN(8613 + 1220 + 67 =9900 psi)(594 + 84 + 5 = 683 bar)

MUD HYDROSTATICPRESSURE IN THEDRILL PIPE

TOTAL PRESSUREACTING DOWN(9100 + 800 = 9900 psi)(628 + 55 = 683 bar)

DRILL PIPE ANNULUS

8613 psi / 594 bar

67 psi / 5 bar

9900 psi / 683 bar

9900 psi / 683 bar9900 psi / 683 bar

1 - 4


OPERATIONAL OVERVIEW

SUBJECT :

DISPERSED / NON DISPERSED INTRUSIONS / KICKSW.B.M.O.B.M.

WHAT HAPPENS :

BASIC PHYSICS ?

THE WORD IS -

PREVENTION !EARLY DETECTION !

YOU WORKING AS A TEAM IS THE KEY.

1 - 5


OPERATION IN PROGRESSWHILE THE KICK OR BLOWOUT OCCURRED

NUMBER OFDRILLING COMPLETION WORKOVER (WELL KILLED) BLOWOUTS

1 Bit on bottom 19 2 Pulling out of hole (POOH) 17 3 Going in hole (GIH) 4 4 Circulating 3 5 Fishing 2 6 Logging 1 7 Casing running 2 8 Primary cementing (incl. Nipping down BOP) 9 9 Drill stem testing -10 Exchanging BOP Xmas tree (excl. cementing) 111 Running tubing and packer 312 Killing -13 Perforation 114 Squeeze cementing 115 Stimulation -16 Cleaning 117 Gravel packing 118 Pressure testing (Production well alive) -19 Regular production 620 Production testing -21 Wireline work 422 Maintenance (Xmas tree, wellhead) 423 Freezing -24 Production logging -25 Testing of safety valves 126 Stimulation (without killing) 127 Gas lifting 128 Misc. concentric tubing operations -29 Water injection -30 Gas injection -31 Operation unknown 18

100* Worldwide statistics based on case histories.

1 - 6


WELL CONTROL INCIDENT RATEfor NORMAL PRESSURE WELLS

Incident in 20 to 25 Wells

or

4% - 5%

* Worldwide statistics based on verbal survey of oilfield personnel.

WELL CONTROL INCIDENT RATEFOR HPHT WELLS WITH ABNORMAL PRESSURES

1 to 2 Incidents per Well

or

100% to 200%

* Worldwide statistics based on verbal information supplied by N.S. Operating Companies.

1 - 7


HUMAN FACTORS REVIEWFOR OFFSHORE BLOWOUTS DURING DRILLING,

COMPLETION OF WORKOVER

1 INATTENTION TO OPERATIONS 26%

2 INADEQUATE SUPERVISION/WORK PERFORMANCE 20%

3 IMPROPER MAINTENANCE OF EQUIPMENT 21%

4 IMPROPER INSTALLATION/INSPECTION 2%

5 INADEQUATE TESTING -

6 INADEQUATE DOCUMENTATION 2%

7 IMPROPER METHOD PROCEDURE 11%

8 IMPROPER PLANNING 12%

9 NO DIRECT HUMAN ERROR INVOLVED 8%

* Worldwide statistics based on case histories.

1 - 8


CAUSES OFPROBLEMS AND LOST WELLS

RIG AND SYSTEM PRESSURE CAPABILITIES

LACK OF PORE PRESSURE KNOWLEDGEAND SIGNAL NEGLIGENCE

WILDCAT TYPE GEO PROGNOSIS

TOO SHALLOW SETTING OF INTERMEDIATECASING

LACK OF CASING PROGRAMME FLEXIBILITIES

OPERATIONAL MISCONDUCT

1 - 9


COMMON DIFFICULTIES

KICKS(AVERAGE KICK FREQUENCY : 2 PER HPHT-WELL)

PROBLEMS GETTING THE WELL KILLED

LOST CIRCULATION

STUCK PIPE

1 - 10


WELL CONTROL AND HOLE CONSIDERATIONS

DEPTH

PRESSURE

13,000 ft 4000 mtr

TRANSITIONZONE

FRACTUREPRESSURE

POREPRESSURE

1 2 3 4

4 to 7 PPG / .48 to .87 SGOPERATING MARGIN

NORMALPRESSURE

ABNORMALPRESSURE

0

1 to 2 PPG / .12 to .24 SGOPERATING MARGIN

1) SAFE TRIP MARGIN2) ECD OVER BALANCE3) SWAB AND SURGE PRESSURE4) SAFETY FACTOR

HPHT Course ABERDE

EN DRILLING SCHOOLS


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2. GAS BEHAVIOUR, KICKS AND CONTROL

CONTENTS

2.1 THE BEHAVIOUR OF GASES

2.2 REAL GAS BEHAVIOUR

2.3 CHANGE OF STATE FROM P1, V1, T1 AND Z1 TO STATE 2

2.4 STANDARD CONDITIONS

2.5 GAS EXPANSION RATIO

2.6 GAS KICK AND EXPANSION WHILE CIRCULATING OUT

2.7 DISPERSED KICKS AND NON-DISPERSED KICKS

2.8 GAS MIGRATION EFFECTS

2.9 KICK TOLERANCE

REFERENCES FOR SECTION 2

2 - 2


2.1 THE BEHAVIOUR OF GASES

Gases and liquids are both fluids. That is they can both flow or be pumped.

Gases are compressible whereas liquids are almost incompressible. This meansthat a change of pressure will cause a large change of volume of a gas, but thesame change of pressure will cause only a very small change of volume of a liquid.

Gases can be changed into their associated liquids at the correct conditions ofpressure and temperature. This means that a gas is an evaporated (or boiled-off)liquid and a liquid is a condensed gas.

An equilibrium mixture of a gas and droplets of its associated liquid is called avapour.

When the pressure or temperature of a gas change then the volume also changesaccording to the appropriate gas laws.

The basic equation of state for a unit of mass (ie 1 mol) of a perfect or ideal gas is:-

P x V = R x T [Eqn 2.11]

Where P = the pressure in the gas, in absolute units.V = the gas volume.T = the temperature of the gas, in absolute units.R = the Universal Gas Constant. The value of this depends on the

system of units in use, as shown below in TABLE 2.1.1 mol = a mass of gas, expressed in lbm or Kg, equal to its molecular weight.

When the mass of gas is n mols, then the equation of state for a perfect gas becomes:-

P x V = n x R x T [Eqn 2.11a]

TABLE 2.1

Pressure Volume Temperature Value ofunits units units constant Rabs. abs.

lbf/ft2 cu.ft R 1545lbf/in2 US gal R 80.3N/m2 cu.m K 8314bar cu.m K 0.08314

For R = 1545 its units are ft lbf/lb-mol/R. For R = 8314 its units are N m/KG-mol/K (or Joules per Kg-mol/K)

2 - 3


NB Pressure and temperature units are in absolute terms,

Abs pressure = gauge pressure + atmospheric correction

Abs temperature = F + 460 = R (ie deg Rankine) or= C + 273 = K (ie deg Kelvin).

For oilfield units, the ideal gas equation becomes:

P x V = n x 80.3 x T [Eqn 2.12]

Where P = pressure in psia.V = gas volume in US gallons.T = gas temperature in R absolute.

mass = n lb-mol.

NB: For all gases 1 lb-mol has a volume of 359 cu ft at a pressureof 1 atmosphere and a temperature of 32F or 1 Kg-mol occupies22.41 cu m at 1 atmosphere and 0C.(Avogadros Hypogthesis of 1811).

WORKED EXAMPLE 2.1

What is the volume of 8 lbm of methane gas (Mol wt = 16) at a pressure of 350 psiaand a temperature 100F?

SOLUTION

By definition, the number of lb mols of mass of a gas is:

n = mass(in lbm) / Molecular weight.

In this case, n = 8/16 = 0.5 lb-mol.

Then, in 2.11a, 350 x V = 0.5 x 80.3 x (460 + 100)

Hence V = 0.5 x 80.3 x 560 / 350 = 64.24 gal

= 64.24/42 = 1.5295 bbl = 8.588 cu ft.

2 - 4


2.1.1 Units Systems and Units Conversions.

In many cases drilling operations are planned using a system of units which iseither the SI or Oilfield systems. Some conversion factors between the two systemsare shown in TABLE 2.2.

TABLE 2.2

Quantity Units used Oilfield Units

Depths metres feetVolumes litres or cu metres US barrels or gallonsDensity Kg/litre(ie SG) lbm/US gallon (ie ppg)Pressure N/m2 or bar lbf/in2, ie psiPress grad bar/10m psi/ftPipe dias mm insCapacities litres/m or cu.m/m bbl/ftOther dimensions cm or m ins or ftWeight, force Kgf lbf or tonfMass Kgm lbm or tonmTemperature C FFlowrates litres/min bbl/min or gal/min

SI OR METRIC -> TO -> OILFIELD

metres x 3.281 = ftlitres x 0.2642 = US gallonsKg/litre (or SG) x 8.33 = ppgbar x 14.504 = psibar/10m x 0.4415 = psi/ftlitres/m x 0.0001917 = bbl/ftKg x 2.2046 = lbcm x 2.54 = ins1 atmosphere x 14.695 = psiaC x 1.8 + 32 = F

In some cases metric pressure in units of Kgf/cm2 may be used. In this case theadded conversions are:

Kgf/cm2 x 14.22 = psiKgf/cm2/10m x 0.433 = psi/ft(ie SG)1 atmosphere = 1.0332 Kgf/cm2

In the above table, to convert from Oilfield units to SI, then divide the Oilfield unitvalue by the above listed conversion factors.

2 - 5


2.2 REAL GAS BEHAVIOUR

Real gases do not behave exactly according to the ideal equation of state [2.11a]given above, particularly at high pressures and temperatures. To account for suchvariations the equation of state is modified to the form:-

P x V = n x Z x R x T [Eqn 2.21]

Where Z = the gas compressibility or gas deviation factor.A graph of Z value variation is shown in FIG 2.1.

The value of Z depends upon the SG of the gas, its pressure and temperature. Thevalue of Z is 1 at atmospheric conditions and it varies between 1, down to about 0.6and then up to a value which may be greater than 2.4. The variation of Z for a gaswith a molecular weight of 23.5 is as is shown in FIG 2.1.

An iterative method of calculating the value of Z is contained in the paper How toSolve Equation of State for Z-Factors by L.Yarborough and K.R.Hall. SPE ReprintSeries No 13 Vol 1 (1977) pp 233-235.

FIG 2.1

0.8

1.0

1.2

1.4

1.6

1.8

2.0

2.2

00.6

2 4 6 8 10 12 14 16 18 20

GAS PRESSURE 1000'S (psia)

GA

S C

OM

PR

ES

SIB

ILIT

Y F

AC

TOR

Z

300 OF

Z = Value of Gas

Mol. Wt = 23.5

SG = 0.8114 (Relative to air)

22

250 OF

200 OF

150 OF

300 OF

150 OF

2 - 6


2.2.1: The density and pressure gradient of a real gas, of molecular weight M, inoilfield units and in SI units is given by:-

Density Pressure gradient

P.MOilfield : w = (ppg) Gg = 0.052 x w (psi/ft)

80.3 x Z x T

.001 x P x MSI : w = (Kg/l) Gg = 0.981 x w (bar/10m)

8314 x Z x T = 0.433 x w (psi/ft)

The specific gravity of a gas is measured relative to the density of air rather thanfresh water. (As for liquids and solids.)

The SG of a gas relative to air is then:

Density at standard conditions SGg = Density of air at standard conditions

= Gas molecular wt / 28.964 [Eqn 2.22]

WORKED EXAMPLE 2.2

A gas has a pressure of 12000 psia and a temperature of 300F. The molecularweight is 23.5. What will be its density and pressure gradient. Use FIG 2.1 for the Zvalue.

SOLUTION

From FIG 2.1 at 12000 psia and 300F, the Z value is 1.59. Substituting this intothe density formula (TABLE 2.2), gives:

P x M 12000 x 23.5 w = = 80.3 x Z x T 80.3 x 1.59 x (300 + 460)

= 2.906 ppg 0.349 SG relative to water.

Gg = 0.052 x ppg = 0.052 x 2.906 = 0.151 psi/ft

2 - 7


2.3 CHANGE OF STATE FROM P1,V1,T1 AND Z1 TO STATE 2

If a gas undergoes a change of state from conditions of P1, V1, T1 and Z1 to thoseat a new condition of P2, V2, T2 and Z2 (as shown in FIG 2.2) then, fromEqn 2.21 :

PV/ZT = constant = R, then:-

P1 x V1 P2 x V2 = [Eqn 2.31] Z1 x T1 Z2 x T2

This assumes that the gas remains as a gas and that there is no change of mass byleakage or addition.

FIG 2.2

Expand

Compress

State 1

P1 V1Z1 T1

State 2

P2 V2Z2 T2

R= =P1 V1Z1 T1

P2 V2Z2 T2

2.3.1 Boyle's Law

Boyles Law (1662) is a simplification of the above statement in which thetemperature and compressibility products are taken to be constant ie:

P1 x V1 = P2 x V2 [Eqn 2.32]

Boyles Law is commonly used in drilling practice to give an approximate answer.If the Z and T values are not constant, the use of Boyles Law will produce errorswhich may be interpreted as being on the safe side. However, in some shallowwells, Boyles Law may be quite accurately applied.

2 - 8


2.3.2 Gas Gradient

The density of a gas is proportional to the gas pressure. The gas pressure gradientformula is given above in 2.2.1.

As a gas bubble is expanded to the surface, its pressure and its pressure gradientmust change (and reduce). However, it can be shown that, as the gas bubbleexpands and its gradient reduces, the length of the gas bubble increases so thatthe total pressure drop across the bubble is constant for constant T and Zconditions.

2.4 STANDARD CONDITIONS

In oilfield practice, gas volumes are usually compared by reference to StandardCubic Feet (SCF) or Standard Cubic Metres (SCM).

The standard volume of a gas (Std cu m) is the equivalent volume which the gaswould occupy at standard atmospheric conditions of 14.695 psia (usually quoted as14.70) (1.0132 bar) and 60F (15.6C). The value of Zs is taken as 1. Thus a gaswhich has a volume of V (cu ft) at P, T and Z will occupy a standard free volume (cuft) of:-

P x V x 520 x 1 35.37 x P x V Vs = = [Eqn 2.41] 14.70 x T x Z T x Z

2.5 GAS EXPANSION RATIO

Expanded volume at surface (Std conditions) Gas expansion ratio =

Original volume at downhole conditions

Vs 35.37 x Pbh Expn ratio = = [Eqn 2.51]

V Zbh x Tbh

Where : Pbh = downhole pressure, psia units.Tbh = downhole gas temperature, R units.Zbh = value of gas compressibility factor at the downhole conditions.

Vs 284.8 x PbhFor SI Units, the expansion ratio is =

V Zbh x Tbh

The expansion ratio of 1 unit of methane gas expanded from a TVD of 14000 ft in awell with 18.2 ppg mud and BHT of 300F is shown in FIG 2.3.

2 - 9


FIG 2.3

Real Gas Law

1 ft BOTTOMHOLE3

Assumed Conditions

0

600

1000

2000

4000

6000

8000

10000

12000

14000

Depthft

564

940

1880

3760

5640

7520

9400

11280

13160

Pressure(18.1ppg)

PSIG

354

10.7

6.1

(5.1)

3.0

(2.91)

1.77

(1.58)

1.23

(1.32)

1.12

(1.16)

1.05

(1.08)

0.98

(1.03)

1

Volumeof Gas

ft .3

23.0

0.7

0.4

0.195

0.115

0.08

0.073

0.068

0.064

0.065

SpecificVolume ofMethane

ft /lb3

85

130

135

150

180

210

235

260

280

300

(Est)TempF

23 ft3

VOLUME OF GAS (INCREASING)

Figures in bracketsare for 10.5ppgMud and 260 bht

Volume of 1 ft3 ofMethane at BottomHoleCondition

SURFACE VOLUME 354 ft3

878 ft3

VOLUME OF GAS (INCREASING)

Boyle's Law

EXPANSION

2 - 10


This produces a straight ratio, ie SCF/downhole cu ft,or bbl/ downhole bbl,or SCM/ downhole cu m,or SC litres/litre downhole.

A graph of calculated expansion ratios for a gas (23.5 Mol.Wt) for a well of about16000 ft TVD (4900m) and with a mud density programme as specified, is shownin FIG 2.4.

FIG 2.4

2000 3000 4000 5000

220

240

260

280

300

320

340

360

1.56 SG 1.66 SG 1.77 to2.01 SG

CURRENT TVD of Drilling (m)

GA

S E

XPA

NS

ION

RA

TIO

(m3 a

t su

rfac

e p

er. m

3 at

form

atio

n)

Estimated Gas Influx.

Expansion Ratio from Bottom Hole to Standard Surface Conditions.

Gas MW = 23.5

2 - 11


2.5.1 WORKED EXAMPLE:

A 10 bbl (1590 litre) gas kick is taken at 15420 ft (4700m) TVD in a well with 1.95SG mud and the SIDPP is 350 psi (24.13 bar). The downhole temperature isestimated to be 320F (160C) and the downhole Z value of the gas is 1.677.

Question:

Calculate (a) the overall gas expansion ratio.(b) the rate of gas production in Standard Cubic Feet, if the slow

circulation rate is 2.5 bbl/min (397 litres/min).(c) the time to drive the gas out of the choke, if the gas expansion

ratio to the choke is 6.5:1

Solution:

Part (a): The bottom hole pressure of the gas influx is:Pbh = SIDPP + mud hydro = SIDPP + Gm x TVD

= 350 + 1.95 x 0.433 x 15420= 13370 psig = 13385 psia (935 bar)

Tbh = 320 + 460 = 780R

Then the expansion ratio is:

Vs 35.37 x Pbh 35.37 x 13385 = = Vbh Zbh x Tbh 1.677 x 780

= 361.9 : 1 Std CF/Res CF (or Std cu m/Res cu m)

Part (b) : The rate of production of gas at the surface for a slow circulation rate of2.5 bbl/min is then:

Surface gas rate = 361.9 x 2.5 = 904.75 Std bbl/min

= 904.75 x 5.615 x 1440 SCF/day

= 7.315 MMSCF/D (0.207 MMSCM/D)

Part (c) : The expanded gas volume at the choke is:

Vchk = 6.5 x 10 = 65 bbl (10.335 cu m)

Time to exhaust = 65/2.5 = 26 minutes at the choke.

2 - 12


2.6 GAS KICK AND EXPANSION WHILST CIRCULATING OUT

Prediction of Maximum Pressures at the Casing Shoe and Choke. Refer toFIG 2.5.

FIG 2.5

Pbh = Ppore

SIDPP

SICP

MudGm

GasGi Vg

MudGm

Ca =m

bblLinear

CapacityGm

Dep

th o

f In

tere

st D

i

Lg

as

TV

D -

D

Initial assumptions

(a) The Drillers Method is used initially.(b) Temperature is constant.(c) An ideal gas is used ie Z = 1 = const.(d) The kick is not dispersed.(e) Pressure drop across the gas is neglected.

The maximum pressure Pi at any depth of interest Di below the surface occurswhen the top of the gas bubble is adjacent to the point at depth Di.

2 - 13


Then:- P

i = P

bh - G

m x (D - D

i - L

g) [a]

Where D = TVD (ft or m)Lg = length of gas at Di (ft or m)

Gm = current mud pressure gradient (psi/ft or N/m2/m)

Pbh = bottom hole pressure (absolute) at shut-in, (psia or N/m2abs)

NB:The above equation is written in consistent units.

Hence by further algebraic arrangement:

Pi = 0.5 x (b2 + 4c) + 0.5 x b [Eqn 2.61]

Where b = SIDPP + Gm.Di c = Gm x Vg1 x Pbh/Ca

Pdp = SIDPP ( psia or N/m2abs)

Vg1 = initial influx volume (bbl or cu m)Ca = the linear capacity of the annulus at the level of the depth

of interest Di in units of bbl/ft or cu m/m.Pi = maximum pressure at depth Di (psia or N/m

2abs)

The pit gain at the depth of interest Di is then:

Vg = Vg1 x Pbh/Pi [Eqn 2.62]

And the pressure at the choke is then :

Pchk = Pbh x ( 1 - Vg1 x Gm/Pi) [Eqn 2.63]

To calculate the maximum pressure at the casing shoe, substitute Dshoe in place ofDi. To calculate the maximum pressure at the choke, substitute 0 for Di. The aboveanalysis is primarily for a surface BOP stack. For a sub-sea well head, the methodcan be adapted .

2 - 14


2.6.1 CORRECTIONS for Z, T and W & W Method

The above anaylsis ignores changes in temperature, gas Z values and also thepressure drop across the gas influx. Corrections for those can be made andincorporated into the values of coefficients b and c as well as modifying theanalysis for the Wait and Weight method of pressure control.

Those corrections are summarised below in TABLE 2.3.

TABLE 2.3

Condition Driller's Method W & W Method

1. As above, but b = Pdp

+ Gm

x Di - d P

g P

dp x V

dsalso include b = + Gk D

1 - d P

ggas gradient. d P

g = H

1 x G

g D x C

a

C = no change C = Gk x V

g1 x P

bh/C

a

2. As in 1 above b, as in 1 above. b, as in 1 above.and includechange g T and

C = Gm x Vg1 x Pbh x Ti x Zi C, as for driller's, but

Z values. Ca Tbh x Zbh use Gk instead of Gm.

Vg = Vg1 x

Pbh x Ti x Zi Vg, as for Driller's. Pi x Tbh x Zbh

Where : Vds= Total volume of drillstring, litres or bbls.Gg = Gas gradient, Kgf/cm

2/m or psi/ft.Gk = Kill mud gradient, Kgf/cm

2/m or psi/ft.H1 = initial length (vertical) of influx, m or ft.

In addition, a set of graphs, as shown in FIG 2.6 can be used to make approximateestimates of changes in Z values between two circulation depths.

2 - 15


FIG 2.6

SURFACE PRESSURE

2.0

1.9

1.8

1.7

1.6

1.5

1.4

1.3

1.2

1.1

1.0

0.9

5000 7000 9000 11,000 13,000 15,000 17,000

Z

TOTAL DEPTH FT

Z=Z

/Z

21

1211

13

14

151617

18

KIL

L M

UD

WE

IGH

T, L

B/G

AL

Compressibility ratio vs depth for different kill weight muds.

2.6.2 WORKED EXAMPLE:

The following data is for a well in which a gas kick occurred:-

TVD of the well = 14000 ft (4267 m)TVD to casing shoe = 10500 ft (3200 m)

SIDPP = 520 psig (35.85 bar)SICP = 830 psig (57.23 bar)

Influx volume = 12.6 bbl (2.0 cu m)DC/OH linear cap. = 0.030 bbl/ft x 500ft.

DP/OH/Csg linear cap. = 0.046 bbl/ft.Fracture grad at shoe = 0.930 psi/ft (2.104 bar/10m)

Current mud grad. = 0.832 psi/ft (1.882 bar/10m)

Calculate : (a) The maximum pressure at the casing shoe and the associated choke pressure. Has the MAASP been exceeded?

(b) The maximum pressure and gas volume at the choke.

2 - 16


Solution:

Part (a) :

Bottom hole pressure = SIDPP + Gm.TVD

= 520 + 0.832 x 14000 = 12168 psig = 12168 + 15 =12183 psia

At the shoe, the depth of interest, Di = Dshoe = 10500ft.

For Eqn 2.61,

b = SIDPP + Gm x Di = 520 + 0.832 x 10500 = 9256 psig = 9256 + 15 = 9271 psia

c = Gm x Vg1 x Pbh/Ca = 0.832 x 12.6 x 12183 / 0.046 = 2776452 psia2.

Then Pi = Pmax at shoe = 0.5 x (92712 + 4 x 2776452) + 0.5 x 9271

ie Pshoe = 9561 psia = 9546 psig.

Then the gas volume at the shoe is:

Vgsh = Vg1 x Pbh/Psh = 12.6 x 12183/9561

= 16.06 bbl.

Length of gas at shoe = 16.06/0.046 = 349 ft

Hence the pressure at the choke, with the gas at the shoe is:

Pchk = Pbh - Gm x Dmud = Pshoe - Gm x Dshoe

= 9546 - 0.832 x 10500 = 810 psig.

The MAASP = (Gfrac - Gm) x TVD shoe

= (0.93 - 0.832) x 10500 = 1029 psig

Hence the MAASP has not been exceeded neither at shut-in (830 psig) at theshoe (810 psig).

2 - 17


Part (b) :

For maximum pressure at the choke the depth of interest is Di = 0.

Thus b = SIDPP + 15 + 0 = 535 psia.The value of c is unchanged = 2776452 psia2.

Hence in Eqn 2.61 Pi = Pchk max = 1955 psia. = 1940 psig.

The volume of gas at the choke is:

Vg chk = Vg1 x Pbh /Pchk = 12.6 x 12183/1955 = 78.5 bbl.

2.6.3 Pressure at the Choke for a Sub-sea Wellhead System

The method used in Section 2.6.1 can be adapted to calculate the pressure at thechoke for the sub-sea wellhead condition. Refer to FIG 2.7.

FIG 2.7L is the vertical depth from the RKBto the sub-sea wellhead.

The depth of interest Di is measuredfrom the RKB as before.

For the condition when the influx isat the top of the annulus, Di = L andthe value of the pressure at the topof the annulus and the choke pressurecan be calculated from Eqns 2.6 and2.63, as Pwhd and Pckwhd.

Once this has been done, the maximumpressure at the choke, when the gas isat the choke will be approximately:

Pckmax = Pckwhd + L x (Gm - Gg) [Eqn 2.64]

Mud Line

Gas

Ca ft/bbl

Mud Wm ppgHm

DiL

D

RKB

Pdp Pck

Cc ft/bbl

Pbh

2 - 18


2.7 DISPERSED KICKS AND NON-DISPERSED KICKS

In most simplified kick analyses it is assumed that the kick is non-dispersed amongthe mud. ie it is assumed that a gas influx is a single large gas bubble. Non-dispersed kicks do occur in the cases where an influx is swabbed in or when thewell flows with no mud circulation from the pumps.

However, in cases of drilled kicks, when the well flows whilst the mud is beingcirculated, the influx will be mixed with and dispersed within the mud as the influxenters, as shown in FIG 2.8. As a consequence the following may be deduced:

FIG 2.8

500 ft

167 ft

1152 ft

DispersedKick Zone

Mud

Mud

0.046 bbl/ft

0.03 bbl/ft

(a) (b)

(a) 5 bbl non-dispersed influx

(b) 5 bbl dispersed influx(b) in 5 minutes at mud rate(b) of 8 bbl/min

for sameSICP-SIDPP = 86 psi

Mixed Zone = 45 bbl

Gm = 0.75 psi/ft

Gi (by "standard"formula) = 0.235 psi/ft

SICP-SIDPP = 86 psi

Gm = 0.75 psi/ft

Gi (correct) = 0.08 psi/ft

(a) The simplistic single bubble model is not strictly correct.

(b) The influx will be dispersed much higher up the annulus than the value fromthe simple calculation. This means that the influx will arrive at the chokesometime earlier than expected.

(c) The influx gradient and density will in fact be lower than those calculatedby the method :

Gi = Gm - (SICP - SIDPP)/Hi

(d) These will result in a slightly lower kick tolerance than may be expected fromthe usual calculations.

2 - 19


The main reason why the more accurate calculation of influx gradient is not made isthat the time interval of flow, whilst the mud is being circulated and the influx enters,must be known. This is at present unlikely to be available, with any reliability, onthe rig.

If it is necessary to make an estimate of what the influx gradient is, as calculatedfrom a dispersed kick, then the formula given below can be used:

Vmz x (SICP - SIDPP) Gi = Gm - [Eqn 2.71] Vi x Hmz

Where : Vmz = volume of mixed mud and influx, bbl= Vi + Qm x tk

Vi = measured influx volume (pit gain) bblQm = mud circulation rate, bbl/min

tk = time interval during entry of kick, minGm = current mud pressure gradient, psi/ftGi = influx gradient, psi/ft

SICP = shut-in casing pressure, psigSIDPP = shut-in drillpipe pressure, psig

Hmz = height of mixed or dispersed zone, ft, as calculated normallyfor a total mixed volume of Vmz

2.7.1 Worked Example

A 26 bbl gas influx entered a well whilst the pumps were running. The SICP andSIDPP values recorded were as 650 and 300 psig, with current mud of 12.0 ppg at11500 ft TVD. The time interval of flow was estimated to be 5 minutes and the mudcirculation was 8 bbl/min whilst the influx flowed.

The annulus capacities were:

DC/OH = 0.03 bbl/ft x 600 ft. DP/OH = 0.0459 bbl/ft x 2000ft.

Calculate : (a) The influx gradient by the normal method.

(b) The height and volume of the mixed zone and the influx gradient for this case.

2 - 20


SOLUTION

Part (a) : Volume of the DC/OH annulus = 600 x 0.03 = 18 bbl

For a non-dispersed kick of 26 bbl, the influx height Hi is:

Hi = 600 + (26 - 18)/0.0459 = 774 ft.

The influx gradient is Gi:

Gi = 0.052 x 12.0 - (650 - 300)/774

= 0.172 psi/ft.

Part (b) : For a dispersed kick over a 5 minute flow period:

Mud volume = 8 x 5 = 40 bbl.

Influx volume = 26 bbl.

Mixed zone volume = 66 bbl.

Height of mixed zone: Hmz= 600 + 48/0.0459= 1646 ft.

Hence from Eqn 2.71, the influx density is :

Vmz x (SICP - SIDPP) Gi = Gm - Vi x Hmz

66 x 350 = 0.624 - = 0.084 psi/ft. 26 x 1646

This is only about 49% of the value calculated by the simpler method, for anon-dispersed kick.

2 - 21


2.8 GAS MIGRATION EFFECTS

Any body which is immersed in a fluid is subjected to an upward buoyancy force.See FIG 2.9

The buoyancy force = weight of the volume of displaced fluid.

If the buoyancy force is greater than the weight of the immersed body, then thisbody will rise upwards within the fluid. This is called migration (or percolation).

Generally, if an immersed body has a density which is less than the surroundingfluid, then it will migrate upwards. The greater the density difference, the greater willbe the migration rate, all other factors being equal.

The factors which govern the rate of migration of an immersed body are:

(a) Difference in density. FIG 2.9 (b) Fluid viscosity. (c) Fluid gelling. (d) Surface tension. (e) Size and shape of the immersed body.

Gas

Weight

Liquid

BuoyancyForce > Wt

Upward Velocity

2 - 22


2.8.1 Gas Migration in a shut-in well

The fundamental concept of pressure control is CONSTANT BOTTOM HOLEPRESSURE. This means that normally, in a circulation, gas MUST BE ALLOWEDTO EXPAND IN A CONTROLLED WAY.

If a gas bubble migrates in a static shut-in well and it is not allowed to expand, thenthe gas pressure will not change (except for temperature changes), and so it willbring formation pressure up with it. This means that all well-bore, bottom-hole andsurface pressures will also rise, with consequent dangers to the well. See FIG 2.10

FIG 2.10

The static rate of gas migration in ft/hr is:

Rate of rise of SIDPP or SICP (psig/hr) Vel. = [Eqn 2.81] Mud gradient ( psi/ft)

This is usually quoted as lying in the range 450 to about 1500 ft/hr.

However, recent research, published in June 1993, indicates that even in a shut-inwell, free gas migration rates ARE SIGNIFICANTLY HIGHER THAN THOSEVALUES.Experiments on real wells and computer studies have confirmed that gas cooling,

Ppore

Vg

Pbh = Ppore + 400Pp

SICP800

SIDPP400

VgPp

SICP1200

SIDPP800

Ppore

2 - 23


mud seepage to open hole sections and wellbore elasticity can give values of SICPand SIDPP which are much lower than they would be otherwise. If gas migrationrates are calculated on surface-read changes in SICP and SIDPP, then they arelikely to produce gas migration rates which are significantly lower than true values.

To counteract the adverse pressure effects of migration, it is necessary to allow acontrolled expansion of gas. This can be done by bleeding off surface pressure atthe choke.

CASE 1 : Bit at or near bottom

In this case, pressure at the choke is bled off until the SIDPP has fallen to itsoriginal value by an amount dP. This allows the gas to expand by an amount dV1and a similar volume of mud issues from the choke. It also allows the BH pressureto fall to its original value. This process is repeated periodically. Since the gas isallowed to expand in the annulus, the SICP will not fall back to its starting value.The anticipated pressure profile for the SIDPP and SICP is as shown in FIG 2.11.

Eventually, the gas may be brought to the choke and the situation is then similarto the first circulation of the Drillers Method with the gas at the choke.

FIG 2.11

SICP

SIDPP

Time

Pre

ssu

re

CASE 2 : Pipe out of the hole

In this situation, no U-tube exists, and the SICP is used to monitor pressures. It isthen necessary to allow gas to migrate to the surface and control surface (andbottom hole pressure) by the volumetric method.

2 - 24


2.8.2 Gas Migration in a Circulation Case

Research carried out in the UK and Norway indicates that, when the pumps arestarted and circulation is established, the gas migration rate is likely to be muchhigher than the values quoted above. The shear-thinning effects on the mud andreduced gels allow larger gas bubbles to overtake smaller ones, when circulationis in progress.

Data on this has been published in the paper Gas Rise Velocities During Kicks byA.B.Johnson and D.B White (SPE Drilling Engineering December 1991 pp256-263).This migration velocity is added to the upward velocity of the mud in the annulus asthe kick is circulated. This has the effect of causing gas to arrive at the surfacemuch earlier than anticipated, and higher gas flow-rates to be produced.

NB: The above has been written with respect to gases. For liquid influxes, thelaws of buoyancy still apply as they do with solids (eg wood) in liquids. Therelative incompressibility of a liquid influx is likely to mask any significantchanges in SIDPP or SICP. The fact that no such changes may be recordedshould not be taken to imply that liquid or dense gas influxes do not migrate.

2 - 25


2.9 KICK TOLERANCE

Gas influxes must be allowed to expand. The initial SICP should obviously be lessthan MAASP, but to circulate a gas kick safely, then it is also necessary that thechoke pressure of the expanding gas at the casing shoe should not exceedMAASP.

A definition for a gas Kick Tolerance is thus:

Kick Tolerance is the maximum tolerable gas influx volume which can be taken andcirculated safely to the surface.

Kicks generally fall into at least 2 categories:

(a) Swabbed kicks, when initially the well was balanced.(b) Drilled kicks into an overpressurised formation.

Case (b) results in a SIDPP.

FIG 2.12

0 PRESSURE

DE

PT

H (

TV

D)

SIDPP

Phyd Ppore

A BC

DM

H1 (gas)

H max (gas)

KNSShoe

Mud Gradient/Pressure Line

F

NB. Well geometry assumed to be constant.

SICP

MAASP

Fracture Line

E L

2 - 26


From the diagram it can be shown that the maximum tolerable influx length Hmax,either at the bottom of the hole or at the shoe is given by:

MAASP - SIDPP Hmax = [Eqn 2.91] Gm - Gi

Where : Hmax = maximum length of influx, at BH or shoe, in ft or m.Gm and Gi are the current mud and assumed influxgradients in psi/ft, psi/m, bar/m or Kgf/cm2/m.MAASP and SIDPP are in psi or bar or Kgf/cm2

When the value of SIDPP is > 0, then this is for a drilled kick.

When the value of SIDPP = 0, then this is for a swabbed kick, with the bit strippedback to bottom.

Once Hmax is calculated it is then converted back into a volume,

(i) at the casing shoe, which is then reduced to an equivalent volume at the bottom of the hole, or

(ii) at shut-in, and then converted back into a volume at bottom hole.

The Kick Tolerance is the smaller of the values calculated from (i) and (ii).

For many applications of a drilled kick, it is most likely that the value of Hmax forthe bottom hole condition will determine the kick tolerance.

HOWEVER in cases where there are long open hole sections, the value of Hmax atthe shoe may be the more important and thus set the kick tolerance.

Kick Tolerance, for oilfield unis, may also be expressed in terms of tolerable SGaddition, from Eqn 2.91, as follows :

MAASP - (Gm - Gi) x Hi Kick tolerance, SG = [Eqn 2.92]

0.433 x TVD

An alternative way of showing Kick Tolerance is in a graphical method, as shownin FIG 2.13. The output from a computer program to calculate a range of kicktolerances for a well with data as given below in WORKED EXAMPLE 2.9.1 is alsoshown and has been used as the basis for the graph.

Further work on this topic is contained in the paper Understanding Kick Toleranceand its Significance in Drilling Planning and Execution,by K.P Redman (SPE Drilling Engineering December 1991 pp 245-249).

2 - 27


FIG 2.13

Tolerable Influx Volume bbl

Tole

rab

le S

IDP

P

CirculateKick Out


The following data relates to a well:

TVD of drilling = 16000 ft.TVD of shoe = 12000 ft.

Frac gradient(shoe) = 0.950 psi/ft.Current mud = 0.860 psi/ft.

DC/OH capacity = 0.0292 bbl/ft x 400 ft.DP/OH capacity = 0.0459 bbl/ft.

Calculate the Kick Tolerance for a gas influx with gradient of .15 psi/ft for aSIDPP = 450 psig.

Solution

The MAASP = (Gfrac - Gm) x Dshoe= (0.950 - 0.860) x 12000 = 1080 psig.

Then Hmax = (MAASP - SIDPP)/(Gm - Gi)= (1080 - 450) /(0.860 - 0.15)= 887 ft.

The fracture pressure at the shoe is:

Pfrac = Gfrac x Dshoe = 0.950 x 12000 = 11400 psig.

The bhp for the drilled kick = SIDPP + Gm x TVD:

bhp = 450 + 0.86 x 16000 = 14210 psig.

2 - 28


When Hmax is converted into a volume then:

Case 1 : Hmax at the shoe

Vg shoe = 887 x 0.0459 = 40.7 bbl at Pfrac

The equivalent volume of this gas at bottom hole conditions, by Boyles Law is:

Veq bh = 40.7 x Pfrac/Pbh = 40.7 x 11400/14210

= 32.7 bbl and the length is = 858 ft

Case 2 : Hmax at bottom hole

In this case Hmax = 887 ft and BH volume is 34.1

Thus the kick tolerance for this influx condition is 32.7 bbl rather than 34.1 bbl.

NB. In some cases the W & W method will give a greater safety margin onformation breakdown than the Drillers method. The condition for thisbenefit is:

open hole volume + influx volume > drillstring volume

The W & W method, however, will usually always give a lower value of maximum

2 - 29


pressure at the choke than the Drillers method.

References for Section 2

1. "Practical Natural Gas Engineering"

by R.V.Smith : PennWell Books.

2. Understanding Kick Tolerance and Its Significance in Drilling, Planningand Execution.

by K.P Redman : SPE Drilling Engineering, December 1991.

3. Gas Rise Velocities During Kicks

by A.B. Johnston and D.B.White : SPE Drilling Engineering, December 1991.

4. Field Calculations Underestimate Gas Migration Velocities.

by A.B. Johnston and J.A.Tarvin : EWCF Conference, Paris June 1993.

HPHT Course ABERDE

EN DRILLING SCHOOLS


NG

CENT

RE

3. GAS SOLUBILITY IN OBMS - EFFECTS ON KICK BEHAVIOUR.

CONTENTS

3.1 PHASES OF HYDROCARBON FLUIDS

3.2 PHASE BEHAVIOUR

3.3 GAS SOLUBILITY

3.4 DRILLED GAS AND KICK GAS

3.5 INFLUX TO PIT GAIN RATIO

3.6 REFERENCES FOR SECTION 3

APPENDIX TO SECTION 3 - FORMULAS

3 - 2

HPHT Course- Section 3

3.1 PHASES OF HYDROCARBON FLUIDS

Hydrocarbon reservoirs fall into 3 classes:

Liquid reservoirsHere the reservoir fluid is a homogeneous liquid and the following points maybe noted:

a) A liquid influx will remain as a liquid, but some gas may be produceddownstream of the choke, if the liquid has dissolved gas within it. Anaverage gas production rate in North Sea hydrocarbon liquid reservoirsis about 1,000 - 1,500 SCF/Res bbl of oil.

b) The liquid will not mix with water based muds, although the kick maybe dispersed in the mud. A liquid influx will mix readily with the oil phaseof oil based muds.

c) The pressure at the choke will change only a little as the influx iscirculated to the choke. The measured pit gain will be a reasonablyaccurate measure of the influx volume.

Gas reservoirsThose are reservoirs in which the fluid is free gas and when this is producedto surface, there is free dry gas at the surface.

a) Such a gas influx will not dissolve readily in water-based muds, thesolubility being about 1% of the gas solubility in oils.

b) The pit gain as measured will be a reasonably accurate measure of theinflux volume.

c) A free gas influx in WBM will expand as it is circulated up to the choke,with a rising choke pressure. The rate of expansion will increase thecloser the gas gets to the choke.

d) An influx from a free gas reservoir in an oil based mud will dissolvereadily in the oil phase of the OBM.

e) A dissolved gas influx in OBM will behave as a liquid influx until itsbubble point pressure is reached, after which large volumes of gas maybe released in the annulus, with rapid rises in choke pressure.

f) The measured pit gain will generally be somewhat smaller than the truefree gas influx volume, the discrepancy becoming larger at lowpressures.

3 - 3


Gas condensate reservoirsSuch reservoirs are now being drilled and they are mainly in high pressureregions. Free gas production rates lie in the range 8,000 - 16,000 SCF/Stbbl.

a) Generally the fluid in the reservoir will be a free dense gas, at atemperature above its critical temperature.

b) A gas influx from a gas condensate reservoir may start to condense inthe annulus as its pressure and temperature are reduced. If the mud iswater based, the effect will be largely that of a free gas. If the mud isoil-based, then the effect will be similar to that of a dissolved gas kick.

The effects of such kicks on choke pressure are indicated in FIG 3.1.

FIG 3.1

PR

ES

SU

RE

AT

CH

OK

E

PUMP STROKES

A = 10 bbl free gas in WBM.

B = 10 bbl liquid influx.

C = 10 bbl gas influx desolved in oil-based mud.

Q = Position of bubble point.

A

C

B

Q

A & C

3 - 4


3.2 PHASE BEHAVIOUR

A typical phase equilibrium diagram for a hydrocarbon system is shownin FIG 3.2. The following should be noted:

a) For pressures above the bubble point line and below the criticaltemperature, ie ZONE A: the material in the reservoir is a liquid.

b) For pressures above the dew point line, ie ZONE B: the material inthe reservoir is a gas.

c) For material outside the dew point line ie ZONE C: the material isalways a gas.

d) For material within the phase envelope, ie ZONE D: the material isa 2-phase equilibrium mixture of free gas and its associated liquid.

e) If a hydrocarbon liquid at point 1 is expanded down line 1 to 2, thenwhen the pressure reaches the bubble point line, the liquid starts toevaporate (ie boil) and bubbles of gas appear within the liquid. Asthe expansion proceeds, more gas is produced at the expense ofliquid.

f) If a hydrocarbon gas at point 3 is expanded down a line to point 4,then when the pressure is reduced to the dew point line, droplets ofliquid start to appear in the gas (ie the gas condenses). As theexpansion proceeds, more liquid is produced at the expense of gas

FIG. 3.2

Temperature F

Pre

ssu

re p

sig

CriticalPoint

7000

6000

Liquid

Zone A Zone B Zone C

Bub

ble

Po

int

Lin

e

DewPoint Line

40%

0-200 400 800

42

13

Free Gas

CP

2 - Phase Zone D

25%

10%

3 - 5


3.3 GAS SOLUBILITY

Hydrocarbon gases are highly soluble in hydrocarbon liquids. Some work onthis was published by Thomas, Lea and Turek in 1982 and by OBryan,Bourgoyne, Monger and Kopcso in 1986.

Graphs of the solubility of (a) methane gas (CH4) in diesel and (b) thesolubility of methane, carbon dioxide (CO2) and hydrogen sulphide (H2S) indiesel are shown in FIGS 3.3 and 3.4.

FIG. 3.3

2000 4000 6000 8000

Pressure psia

1000

scf

CH

4/st

d b

bl O

il H2S

at

250

F

600

F

500

F

400

F

200

F

2

4

6

8

GAS SOLUBILITY IN DIESEL (Methane Gas)

Gas solubility toachieve saturation.

Increase oftemperature reduces

pressure to getsaturation.

At constant pressure,increase of

temperature increasessaturation.

FIG. 3.4

100 200 300 400

Temperature, F

Mis

cib

ility

Pre

ssu

re, 1

000

psi

a

2

4

6

8

MISCIBILITY PRESSURE FOR VARIOUS GASES IN NO. 2 DIESEL OIL10

0

Methane

Carbon D

ioxide

Hydrogen Sulp

hideEthane

3 - 6


From FIGS 3.3 and 3.4 it can be noted that:

a) The solubility of methane in diesel may be many 1,000s of SCF/bbl ofdiesel.

b) At each temperature he solubility graphs turn almost vertical at aparticular pressure. This is the miscibility pressure for methane/dieselmixtures at those specific temperatures. At the miscibility pressure, thediesel appears to have an infinite capacity to dissolve methane andproduce a homogeneous liquid.

It should be further noted that the solubility of hydrocarbon gases in water is about1% of the solubility in hydrocarbon liquids.

3.3.1 Gas Kick Solubility in Oil-based Mud

Effects on Kick DetectionA gas kick from a gas reservoir will behave according to the gas law and to thephase behaviour for that fluid, as long as it is not exposed to other fluids.

However, when a gas kick enters a well-bore with oil-based mud, the gasdissolves in the oil phase of the OBM, producing a new fluid mixture, whichwill have an entirely unique phase equilibrium diagram, with the new mixturebeing in the liquid phase of the phase relationship. This liquid will have itsown distinctive bubble point pressure, depending upon the gas/liquidconcentration and temperature.

Thomas, Lea and Turek in their paper Gas Solubility in Oil-Based DrillingFluids-Effects on Kick Detection (SPE 11115 1982), conclude the following:

a) Pit gain (in 1982) was the most reliable kick indicator in both WBM and OBM.Regardless of solubility or not, there is a volume increase which should bedetectable.

b) Short flow-checks are not reliable in OBMs. Extended flow checks(>10 minutes) may be necessary to detect flow.

c) The pit gain detected is limited to the condensed volume of the free gasentering from the reservoir.

d) As a gas influx dissolves in the oil phase of the OBM, this masks the surfaceresponses of pit gain and flow, which are less pronounced than in WBM.

It can also be concluded that ANY SMALL UNDETECTED DISSOLVED GASINFLUX which is circulated in an OPEN WELL, will reach a bubble point pressurewhich is likely to occur in the annulus (or marine riser) near to the surface. Thegas expansion ratio at this point may be in excess of 300, as demonstratedin Section 2 of the manual!

3 - 7


The consequence of this is that a small, undetected, dissolved swab of 1/4 bbl maynot be detected until it reaches its bubble point and becomes 75 bbl of free gas inthe annulus just below the slip joint.

3.3.2WORKED EXAMPLE

A gas influx of 10 bbl flowed into a well in a period of 10 minutes, when the mudcirculation rate was 8 bbl/min. The bottom hole pressure was 12,000 psia, thegas Z value was 1.7 and the temperature was 260F.

Calculate :

a) The gas/mud and the gas/oil concentrations, if the oil volume factor in theoil-based mud was 0.55.

b) The bubble point pressure when the temperature was 140F and the gasSG relative to air was 0.75. Use the formula given in Equation 3.32 in theREFERENCE to Section 3.

SOLUTION

Part (a)

The gas equivalent volume of gas at standard conditions is:

35.37 x Pbh 35.37 x 12,000V

s = x V

bh x 5.615 = x 56.15

Zbh . Tbh 1.7 x (260 + 460)

= 19,471 SCF influx in 10 minutes

Hence the kick influx rate was Qgk = 19,471/10 = 1,947 SCF/min.

Thus the gas/mud concentration was Rgm = Qgk/Qm

Rgm = 1,947/8 = 243 SCF/bbl

And the gas/oil concentration was Rgm/fo = 243/0.55

ie Rgo = 442 SCF/bbl.

3 - 8


Part (b)

The bubble point pressure will be the saturation pressure at which the above is thegas/oil concentration at 140F.

Using the values for a and b as quoted in Equation 3.3.1 and calculating nfrom:

n = 1.24 - 1.08 x SGg + 1.16 x SGg2 and the gas SG was

0.75 relative to air, then:

n = 1.24 - 1.08 x 0.75 + 1.16 x 0.752 = 1.0825

This value is then substituted in Equation 3.3.2 to calculate the bubble pointpressure as:

Pb = a x Tb x Rgo1/n

= 1.922 x (460+140)0.2552 x (442) (1/1.0825)

= 1.922 x 5.1166 x (442) 0.92378

= 9.8341 x 277.8 = 2,732 psia = 2,717 psig.


The rate at which drilled gas is released into the mud in the annulus is related tothe volumetric rate at which the rock is being drilled and to the gas content of thepore spaces:

The rate of release of drilled gas into the annulus is likely to be small in relation tothe rate of inflow in a kick situation. This produces very low gas/oil concentrationsin the mud, if the gas dissolves, and those would produce low bubble pointpressures.

3 - 9


Some typical drilled gas/oil concentrations are shown in FIG 3.5 below.

Some extreme values for a drilled gas example may be:

TVD = 15,000 ftROP = 100 ft/hrMud = 15 ppgGas/oil = 10 SCF/bbl oil in mudBubble pt = 67 psigDepth = 86 ft to bubble point

FIG 3.5

40 80 100

Penetration Rate ft/hrDri

lled

Gas

Co

nce

ntr

atio

n S

CF

/bb

l Oil

in M

ud

5

10

15

20 60

15 ppg 4,000 ft

15 ppg 8,000 ft

15 ppg 15,000 ft

Kick gas is likely to enter a well at a very much higher rate than drilled gas,due to the pressure underbalance. It is not generally possible to measure therate at which a reservoir flows, in a drilling situation, but some estimates canbe made using a radial transient flow model and some typical values areshown on the graphs in FIG 3.6.

3 - 10


FIG 3.6

500 1500

SIDPP - psia

Gas

Kic

k In

flo

w R

ate

SC

F/m

in

3000

1000

2000

1000

Gas SG = 0.60

4000

Gas SG = 0.65

Gas SG = 0.70

Data: TVD = 16,000 ftK = 40 MD = 25%Mud = 0.8 psi/ftBHT = 240FDia = 8.5 inROP = 7.5 ft/hr

Gas inflow rate at any other ROB, Rp is :-Qgk = Graph Value x RpQgk = Graph Value x SCF/minQgk = Graph Value x 7.5

If there is drilled gas plus influx flowing gas then the total gas production flow-ratewill be Qdg + Qkg = Qg. However, as indicated above, the drilled gas rate is sosmall in relation to the influx flow-rate that it is reasonable to neglect it.

3 - 11


3.5 INFLUX TO PIT GAIN RATIO

It is normal to assume, with water based muds, that the pit gain as measured fora drilled kick is the same as the influx volume.

It has been indicated above that when a kick gas dissolves in an oil based mud,the pit gain is limited to the CONDENSED volume of the influx gas, and so:

Measured pit gain is less than true influx volume.

This can be illustrated by values from a laboratory test carried out by BP at asimulated TVD of 20000 ft, 16840 psi and 350F ie:

3 bbl methane + 1 bbl diesel gave 3.72 bbl of liquid mixture.

In this case the influx was 3 bbl and the measured pit gain was 2.72 bbl. ie theratio:

Influx volume/pit gain = 3.0/2.72 = 1.10

OBryan and Borgoyne in their paper Swelling of Oil-Base Drilling Fluids Due toDissolved Gas (SPE Paper No 16676 Dallas Sept 1987) base a simple method(and approximate) for predicting this expansion ratio upon the behaviour ofmethane/diesel solutions. Typical graphs of the swelling of such solutions from20,000 psia to bubble points at 100, 200, 300 and 400F are given in the paper,and shown below in FIGS 3.7(a) and 3.7(b).

FIG 3.7(a)

1.4

1.3

1.2

1.1

1.0

0.90 2 4 6 8 10 12 14 16 18 20

Bubb

le P

oint

Pre

ssur

e

T = 200 FOil = No.2 DieselGas = Methane

800 SCF/STB

600

400

200

0 Miscibility Pressure

Pressure (1000's psia)

Vol

ume

Fac

tor

Bo,

BB

L/S

TB

3 - 12


FIG 3.7(b)

1.4

1.3

1.2

1.1

1.0

0.90 2 4 6 8 10 12 14 16 18 20

Bubb

le Po

int P

ress

ure


600 SCF/STB

400

200

0

Miscibility Pressure


Vol

ume

Fac

tor

Bo,

BB

L/S

TB


The method for determining the influx multiplier, for a dissolved gas kick is shownbelow by means of worked example:

A gas influx has entered a well while drilling ahead and the gas is believed tohave dissolved in the oil-based mud. The following is the relevant data:

TVD = 15,000 ft Mud density = 16.3 ppgSIDPP = 700 psi Pit gain = 7.5 bblGas SG = 0.65 (rel to air) BHT = 200FGas Zbh = 1.740 APL = 250 psiSICP = 810 psi Oil vol fraction= 0.460Pump o/p = 7.8 bbl/min

What would be an estimate for:

a) The influx: pit gain multiplier.

b) The bubble point pressure if the gas is released when the temperature isabout 150F.

c) The depth at which the gas is released.

3 - 13


SOLUTION:

PART (a)

(i) From the graph on FIG 3.6 the rate of gas inflow for the above conditionsis given as 2154 SCF/min (Qgk) at a SIDPP of 700 psi.

(ii) The gas/mud concentration for the contaminated mud zone is:

Rgm = Qgk/Qm = 2154/7.8 = 276 SCF/bbl mud.

(iii) The gas/oil concentration in the mud is:

Rgo = Rgm/fo = 276/0.46 = 600 SCF/bbl oil.

(iv) Select the graph of swelling of methane/diesel solution:pressure for the BHT of 200F, as in FIG 3.8.

FIG 3.8

1.4

1.3

1.2

1.1

1.0

0.90 2 4 6 8 10 12 14 16 18 20

Bubb

le P

oint

Pre

ssur

e


800 SCF/STB

600

400

200

0


Vol

ume

Fac

tor

Bo,

BB

L/S

TB

Pbp = 4444 psia

c

d

a

b

Miscibility P

ressure

c = Bo = 0.9836d = Bog = 1.123

(v) Enter the graph at a pressure of 13,679 psia and draw a line vertically upfrom this to cut the 600 SCF/bbl gas/oil line at point b and the zeroconcentration line at a.

Draw horizontal lines from b and a to cut the end vertical axis (volumefactors)

.(vi) Scale off from the vertical axis the values of Bog and Bo as the volume factors

for the 600 SCF/bbl solution and pure diesel.

3 - 14


From the graph those give values of:

Bog = 1.1283 Bo = 0.9836

(vii) Calculate the pit gain (bbl) per 1,000 SCF of dissolved gas from:

Vgo = 1,000 x fo x (Bog - Bo)/Rgm

= 1,000 x 0.46 x (1.1283 - 0.9836)/276

= 0.2417 bbl/1,000 SCF

(viii) Calculate the pit gain which would have been seen, per 1,000 SCF ofundissolved gas (ie as if in a water based mud) from:

1,000 x 14.7 x Tbh x ZbhVgf = bbl/1,000 SCF

Pfp x 520 x 5.615

1,000 x 14.7 x 660 x 1.74 = = 0.4227 bbl/1,000 SCF

13,679 x 520 x 5.615

(ix) Calculate the pit gain multiplier from:

Vgf/Vgo = 0.4227/0.2417 = 1.75 bbl/bbl of pit gain.

This means that the pit gain of 7.5 bbl dissolved gas represented1.75 x 7.5 = 13.1 bbl of free gas influx.

PART (b)

To estimate the bubble point pressure at 150F, use the graphs in FIG 3.7 for 100and 200F at 600 SCF/bbl and interpolate between to get the Pbp value at 150F,as follows:

On the 200F graph, Pbp at 600 SCF/bbl = 4444 psia

On the 100F graph, Pbp at 600 SCF/bbl = 3651 psia

By interpolation at 150F and 600 SCF/bbl, Pbp = 4048 psia

= 4033 psig

3 - 15


Part (c).

The pressure at the choke will stay almost constant while the gas remains insolution. Hence at the bubble point depth,

Pbp = SICP + Gm x Depth to bubble point

Depth = (4,033 - 810)/.8476 = 3803 ft below the RKB

This example indicates that the pit gain as measured, for a dissolved gas influx, isless than the real volume of dense free gas flowing from the reservoir.

This will be the case when the pumps are running, as for a drilled kick. In the caseof a swabbed kick, with the pumps off, there will be only a small amount of mixingand the influx gas will not dissolve fully, at least until gas streaming causessufficient mixing for this to occur. In the case of no mixing, the recorded trip tankgain will be approximately equal to the influx volume.

The graphs shown in FIG 3.7 also show that the bubble point pressure reduces asthe gas/oil concentration is reduced. This means that a small dissolved influx maynot reach its bubble point pressure until it has passed through the choke.

In a recent publication by Lindsay & White, the "influx volume/pit gain" ratiodescribed above has been drawn in graphical form for an 88:12 OWR oil-basedmud between 2,000 and 9,000 ft TVD. This is shown below in FIG 3.9.

FIG 3.9

1.0

INF

LU

X :

PIT

GA

IN V

OL

UM

E R

AT

IO

8000

1.5

2.0

2.5

3.0

3.5

4.0

7000600050004000300020001000

BOTTOM HOLE PRESSURE (PSI)

100009000

EXTRA GAS HELD IN SOLUTIONOBM COMPARED TO WBMFOR THE SAME PIT GAIN

3 - 16


3.6 REFERENCES FOR SECTION 3

1. Gas solubility in oil-based drilling fluids : Effects on kick detection.

By Thomas, Lea and TurekSPE Paper 11115 New Orleans Sept 1982

2. An experimental study of gas solubility in oil-based drilling fluids.

By OBryan, Burgoyne, Monger and KopcsoSPE Paper No 15414 : New Orleans Oct 1986.

3. The swelling of oil-based drilling fluids due to dissolved gas.

By OBryan and BurgoyneSPE Paper 16676 : Dallas Sept 1987.

4. The use of a gas kick simulator to produce an oil-based mud trainingpackage.

By Lyndsay and White1993 IADC European Well Control Forum : Paris June 1993..

3 - 17


APPENDIX TO SECTION 3 : FORMULAS

3.3.1 Gas Solubility in OBM : Bubble Point Pressure

In the above papers, it is indicated that there is a relationship betweenthe saturation concentration, the temperature and the bubble pointpressure, as given by:

P n

Rso

= [Eqn 3.31] a.Tb

Where:

Rso = saturation gas/liquid concentration, SCF/bblP = saturation, or bubble point pressure, psiaT = mixture temperature Ra = a constant = 1.922 for hydrocarbon gas in base oilb = a constant = 0.2552 for hydrocarbon gas in base oiln = an index = 1.24 - 1.08 x SGg + 1.16 x SGg

2, forhydrocarbon gas in base oil

SGg = gas specific gravity, relative to air.

From this it can thus be shown that the bubble point pressure for aspecific gas/liquid concentration of Rgo is:

Pb = a.Tb . R

go (1/n) [Eqn 3.32]


The rate at which drilled gas is released into the mud in the annulus isrelated to the volumetric rate at which the rock is being drilled and to thegas content of the pore spaces:

Pb x d2 x f x Sg x Rp

Qgd

= SCF/min [Eqn 3.41] 310.97 x Zb x Tb

Where: Pb = bottom hole pressure, psia.d = bit diameter, in.f = rock porosity, decimal.

Sg = gas saturation fraction of the pores, decimal.Rp = rate of drilling penetration, ft/hr.Zb = gas Z value at bottom hole conditions.Tb = bottom hole temperature, R.

[ ]

3 - 18


The radial flow rate of kick for a uniform thickness transient gas reservoir isgiven by:

k x h x (Pf2 - Pb

2)Q

gk = MSCF/day [Eqn 3.42] 1424 x Pd x Zb x Tb x

Where: Pb = the dynamic value of the bottom hole pressure, psia.k = formation permeability, milli dArcy units.h = thickness of permeable rock exposed or drilled in

a known or assumed time interval, ft. = gas viscosity, cP.

Pf = the effective formation pressure, psia, while flowing.Pd = a dimensionless pressure group,

= 0.5 x [Log(Td) + 0.81]Td = a dimensionless time group

=0.0002634 x k x t f x x c x (Rw2)

c = fluid (liquid) compressibility, 1/psi.Rw = wellbore radius, ft.

t = time interval of influx, hours.

The gas viscosity, cP, at inflow conditions is given by:

= 0.0001 x K1 x e (Xg y) [Eqn 3.43]

(9.4 + 0.02 M) x Tb1.5

Where: K1

= (209 + 19 M + Tb)

X = 3.5 + 986/Tb + 0.01 M y = 2.4 - 0.2 X

g = gas SG (Relative to water) = 0.0014926.Pf.M/(Zb.Tb)

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4. RIG EQUIPMENT SUMMARY

4 - 1


RIG EQUIPMENT SUMMARY

Aberdeen Drilling Schools & Well Control Training Centre.

GUIDANCE NOTES

HIGH PRESSURE WELL CONTROL SYSTEM

Fail-safe Valves: Sequenced (manual or automatic) closing of the fail safevalves on a subsea stack, with the outer valve closing first, should be usedto limit the effects of cutting out of the gates. Also consideration should begiven to the closure mechanism and whether additional hydraulic assistshould be incorporated in order to increase closing force.

Flexible HosesStrict attention must be given to the flexible hoses to ensure that they aredesigned for appropriate temperatures, pressures and well fluids. The hoseshould be checked to ensure that it is the correct length for the given stack.

BOP Stack OutletsThere should be a minimum of two outlets to the choke manifold below theupper set of pipe rams on a subsea stack.

Hang Off RamsThe upper pipe rams should be positioned in the stack so that they can beused to hang off the drillstring with the blind/shear rams closing above.

ChokesThe choke manifold should be equipped with two remote hydraulic chokesand at least one manually operated choke.

SURFACE GAS HANDLING SYSTEM

Mud Gas Separator (MGS):The mud gas separator must be designed and certified for a given capacityof gas and mud. Design will include vessel working pressure, sizing ofvent lines, length of mud seal, retention time, and control system. Thedegasser should be designed, constructed, inspected, tested and stampedin accordance with ASTM VIII Division 2 - Boiler and pressure vessel codeor similar pressure vessel code.

MGS InstrumentationThe MGS should be instrumented and controlled so that the workingpressure is not exceeded.

MGS BypassAn alternative method to dispose of produced fluids must be provided inthe event the capacity of the MGS is exceeded.

Glycol Injection SystemA system for injection of glycol upstream of the choke to prevent hydrateformation should be available.

4 - 2


General Layout 13 5/8" - 15,000 psi BOP StackFIG. 1

4 - 3


WELL CONTROL AND SURFACE EQUIPMENTTemperature Limitations and Pressure Ratings

The following limitations apply to this equipment:

Continuous EmergencyService Service

Equipment Rating(1 Month) Rating(1 Hour) Pressure (psi)

Max Deg F Max Deg F

PIPE RAMS 250 350 15,000

VARIABLE RAMS 190 N/A 15,000

BOP CHOKE AND 250 350 15,000KILL VALVES

SHEAR RAMS 190 N/A 15,000

RAM DOOR SEALS 250 350 15,000& RAM SHAFT SEALS

ANNULARS 170 225 5,000/10,000

FLEXIBLE HOSE 212 320 15,000

CHOKE AND KILL 250 350 15,000LINE STAB SEALS

CHOKE MANIFOLD 250 350 15,000VALVES, UPSTREAMOF THE BUFFER TANK

CHOKE MANIFOLD 250 350 5,000VALVES, DOWNSTREAMOF THE BUFFER TANK

CHOKE MANIFOLD 250 350 5,000OVERBOARDPIPEWORK

SLIP JOINT - CHOKE 250 350 15,000

KILL BOX SAVER SUB

4 - 4


FIG. 2MUD/GAS SEPARATOR

18"

3', 1

"24

' - 4

"

27' -

5"

MUDHEAD

6" TO TRIP TANK

10" CLEAROUT

10" PIPE Sch. 80INSIDE

20" PIPE X - STG

0

2

4

6

8

10

12

14

16

18

20

22

24

26

28

30

32

8.9

13.0

16.4

19.5

22.4

25.1

27.8

30.4

33.0

35.5

37.9

40.4

42.8

45.2

47.6

50.0

8 9 10 11 12 13 14 15 16 17 18 19 20

BY-PASSPRESSURE (psi)

GAS FLOW(mm scf/day)

THROUGHPUT PERFORMANCEAT 60 DEG F.

MUD GAS SEPARATORFLOW CAPACITY CURVE

FLUID DENSITY Lb/gal

UNLO

AD

UNLO

AD W

ITH 6

PSI M

ARGI

N

HOT MUD RECIRCULATING

LINE

FLOW LINE

10" VENT UP DERRICK6" VENT

28' - 8 1/2" ABOVE MAIN DECK

THERMO-COUPLE AND PRESSURE TRANSDUCER

FLANGE

10" Sch. 80 PIPE

10" DOWN TO SHAKER

HEADER BOX

4 - 5


SUBSEA BOP SYSTEMFIG. 3

DRILL FLOOR LEVEL

TO SHALE SHAKER

MAIN DECK LEVEL

36" DIAMETERMUD - GAS

SEPERATOR

VENT TO TOP OF DERRICK

10" VENT LINE

FROM C & K MANIFOLD, 4" PIPE

REMOTE CHOKE

TO SHALESHAKER TO CEMENT UNIT

MUD PUMPS

REMOTE CHOKE

TO STARBOARD FLARE LINE


SEA LEVEL

FLEX JOINT

ANNULAR PREVENTER

H - 4CONNECTOR

SHEAR RAMS

ANNULAR PREVENTER

5" RAMS

VARIABLERAMS

5" RAMS

H - 4CONNECTOR


B B1

A A1C C1

SEABED

6

TO PORT FLARE LINE

REMOTELY ACTUATED

VALVES

TO MUD/GAS SEPARATOR

MANUAL CHOKE

MANUAL CHOKE

6 Meters

GLYCOL INJECTION

POINT

5

4

3

21

8

7DIP TUBE

PRESSURE SENSOR

MGS PRESSURE

SENSOR

DOWNSTREAM CHOKE TEMP.

SENSOR

DOWNSTREAM CHOKE TEMP.

SENSOR

UPSTREAM CHOKE TEMP.

SENSOR

UPSTREAM KILL LINE TEMP.

SENSOR

REMOTE CHOKE AREA

CHOKE POSITION

INDICATOR

ANNULUSPRESSURE

DRILLPIPEPRESSURE

CHOKE CONTROL

REMOTE CHOKE CONTROL PANEL

SUBSEA TEMP. SENSOR

SUBSEA TEMP. SENSOR

UPSTREAMCHOKE LINE

PRESSURE TEMP.

DIP TUBE BOP

ALARM

PORTSTBDMGS

VALVE STATUS

DATA MONITORING SYSTEM AND BYPASS CONTROL UNIT

TEMP.

UPSTREAMKILL LINE

TEMP.

DOWNSTREAMCHOKE

TEMP.

PRESSURE

MGS

7

8

1,2

3

5,6

4


DECK LEVEL

4 - 6


FIG. 4SURFACE BOP SYSTEM

PRESSURE TEMPERATURE

TEMPERATURE

MGS BOP

ALARM

PORTSTBDMGS

VALVE STATUS


MUD GAS SEPARATORREMOTE CHOKE/MONITORINGAND BYPASS CONTROL UNIT

PRESSURE/TEMP. SENSOR

TO STARBOARD/PORT VALVES

TO MGS VALVE

TO BOP TEMP. SENSOR

MUD GAS SEPARATORRETURN TO

MUD SHAKERS

VENT LINE TO

DERRICK

STARBOARD PORT

OVERBOARD LINE

BUFFER CHAMBER

CHOKE/KILL MANIFOLD

MUD MANIFOLD

CHOKE LINE

CMT UNIT

KILL LINE

15 M BOP STACK

GLYCOL INJECTION

ANNULAR

RAM

RAM

RAM

RAM

REMOTE CHOKEREMOTE CHOKE

MANUAL CHOKE

BYPASS

HCR VALVE

HCR VALVE

CHOKE POSITION

INDICATOR

ANNULUSPRESSURE

DRILLPIPEPRESSURE

CHOKE CONTROL

REMOTE CHOKE CONTROL PANEL

4 - 7


TEMPERATURE MONITORING EQUIPMENT

A temperature monitoring system must be in place to ensure that thecontinuous temperature rating of the elastomer system is not exceededduring drilling, well control operations and well testing. Temperaturesshould be monitored at the mud return flowline, at the chokeline upstreamof the choke, and at the well test flowline upstream of all chokes.

KILL SYSTEM

Kill PumpA 15,000 psi kill pump capable of slow circulation rates +/- 0.5 bbls/minshould be available. There should be a good communications link betweenthe kill pump and rig floor. Consideration should be given to equipping thekill pump for remote operations from the rig floor. There should also be achoke on the bleed down line to reduce erosion of plug type valves whenbleeding off pressure.

High Pressure LineHigh pressure line from the kill pump to the rig floor with a circulating headand flexible hose or chicksans ready for quick make up should beavailable.

DRILLSTRING BACK PRESSURE VALVE

A means of avoiding back flow up the drill pipe should be incorporated byeither using a sub for a drop in back pressure valve or by using a floatvalve in the BHA before drilling through the transition zone from normal toabnormally high pressure, commonly reached below the 13-3/8" casingpoint.

Drillstring Circulating CapabilityA high pressure lubricator and drill pipe perforation system or drillstringcirculating sub should be available while drilling below deep intermediatecasing.

PIT LEVEL INDICATOR

Minimum pit level indicator requirements are 2 pit level indicators peractive tank for semi submersibles. All tanks should be monitored andinclude a pit volume totaliser.

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CONTENTS

5.1 INTRODUCTION: GAS EXPANSION

5.2 THE CHOKE MANIFOLD and CHOKE

5.3 MUD-GAS SEPARATORS: DESIGN, CAPACITIES and OPERATION

5.4 WELLHEAD and FLOWING TEMPERATURES

5.5 FORMATION and PREVENTION of HYDRATES

APPENDIX : SECTION 5 FORMULAS

5.6 STEADY FLOW ENERGY EQUATION

5.7 FLOW REGIMES

5.8 FLOW OF GASES THROUGH AN ORIFICE

5.9 FLOW THROUGH A CHOKE

5.10 FLOW OF GASES ALONG PIPES: THE WEYMOUTH FORMULA

5. SURFACE GAS HANDLING CAPACITIES and PROCEDURE FOR HPHT WELLS


5 - 2

5.1 INTRODUCTION : GAS EXPANSION

In any well control operation in which an influx is circulated out of the well viathe choke, the BASIC OBJECTIVE is to hold bottom hole pressure constant atall stages of the process.

This is usually achieved by controlling the drillpipe pressure at constant pumpspeed (ie at constant slow circulation rate), according to a predeterminedschedule of pressure and strokes (via the Drillers, W & W or Concurrentmethods). As long as the pump speed is held constant, the means of controllingthe drillpipe pressure is by adjusting the opening at the hydraulic choke at thedrillfloor choke manifold.

As indicated in Section 2, gas expansion ratios increase with increase inbottom hole pressure. A gas expansion factor is used to convert from a non-dimensional ratio to the units which are commonly used ie SCF/bbl,as shownbelow :

Vsc 198.4 x Pbh = SCF [ Eqn 5.1.1 ] Vbh Zbh x Tbh

Where Pbh = bottom hole pressure in psia.Vbh = free gas influx volume at bottom hole conditions in bbl.Tbh = gas bottom hole temperature in R.Zbh = gas compressibilty factor at BH conditions.Vsc = free gas volume at standard conditions, SCF.

Vsc/Vbh = 1/Bg, where Bg is the gas formation volume factor.

It should be noted that Vbh is the free gas influx volume at bottom hole conditions.In a water-based mud this will equal the measured pit-gain, but in an oil-basedmud with a dissolved gas kick, the pit gain correction factor should be introduced.

FIG 5.1a FIG 5.1b

0.90

psi/f

t :1.

35F

/100

ft

0.85

psi/f

t :1.

30F

/100

ft

0.80

psi/f

t :1.

25F

/100

ft

2200

2100

200014 15 16 17 18 19 20

Well TVD - 10005 ft

Gas

Exp

ansi

on F

acto

r S

CF

/bbl

(1/

BG

)

Gas SG = 0.70 (rel to air)Surface Temp = 100F

Vs 198.6 Pbh 1 = = Vbh Zbh.Tbh Bg

350

F

2200

2100

200011 12 13 14 15 16 17

Bottom Hole pressure - 10005 psia

Gas

Exp

ansi

on F

acto

r S

CF

/bbl

(1/

BG

)

Gas SG = 0.70 (rel to air)

Vs 198.6.Pbh 1 = = Vbh Zbh.Tbh Bg

18

320

F

300

F

280

F

250

F


5 - 3

The graphs in FIGS 5.1(a) and (b) indicate the relative values of suchexpansion factors at constant mud weights against depth (FIG 5.1a) and atconstant bottom hole temperatures against bottom hole pressures (FIG 5.1b)for a gas with SG = 0.7 relative to air (MWt = 20.3).

5.1.1 Worked Example: Gas expansion and gas flowrate at MGS

A 10 bbbl gas kick is taken at a TVD of 16500 ft in a well with 0.9 psi/ft mud anda temperature gradient of 1.35F/100 ft. The slow pump rate is to be 2.5 bbl/min.The gas SG relative to air is estimated to be 0.65.

Calculate: (a) The gas volume SCF/bbl at standard conditions.

(b) The gas flowrate at the outlet from the MGS,in MMSCF/Day.

SOLUTION:

(a) From the graph for 0.9 psi/ft mud and 1.35F/100 ft temperaturegradient, the gas expansion ratio is measured as 2194 SCF/bbl.

(b) The gas flowrate at the MGS outlet, for a pump rate of 2.5 bbl/min is:

Flowrate = SCF/bbl x bbl/min x minutes/day/1000000

= 2194 x 2.5 x 1440/1000000

= 7.898 million SCF/Day (MMSCF/D)

It is obviously necessary, when choosing the slow pump speed, to ensure thatthe gas production rate calculated as above does not exceed the handlingcapacity of the MGS.

5.2 THE CHOKE MANIFOLD AND THE CHOKE

A typical HPHT choke manifold is shown in FIG 5.2 It is essential thatthe choke manifold should be designed to provide the following principalfeatures:

(a) adequate pressure integrity for the highest anticipated pressures. This willbe at least 15000 psi with test pressures of 22500 psi for HP wells.

(b) adequate temperature range capability without loss of the main physicalproperties. This will be at least 250F for continuous operation and 320Ffor 1 hour. Sub-zero temperatures on the downstream side of the chokeswill also be likely.

(c) A range of flow-path options with at least 2 variable power (remote)chokes and 1 manual adjustable choke.

(d) A point upstream of the chokes at which HP antifreeze (glycol) can beinjected to suppress hydrate formation.


5 - 4

POORBOYDEGASSER

TRIPTANK

SENSORS INMUD PITROOM

TOKILL LINE

(CHOKE & KILLMANIFOLD)

BUFFERTANK

KILL LINECHOKE LINE

KILLLINE

CHOKELINE

TO KILLSTANDPIPE IN

DERRICK

FROM MUDMANIFOLD

TO 4:1DEBOOSTER

ANDCHICKSAN

CONNECTION

TO MANUALCHOKE

STRIPPINGTANK

FROMCEMENT

PUMP

CHICKSANCONNECTION

CHICKSANCONNECTION

TO STARBOARDFLAREBOOM

TO PORTFLAREBOOM

TOCHOKE LINE(CHOKE & KILL

MANIFOLD)

KILL PUMP

TO 3" DSTSTANDPIPEIN DERRICK

GlycolInjection

Point

18 - 21ftSEAL

REMOTECHOKE

MANUALCHOKE

REMOTECHOKE

MANUALCHOKE

(e) An adequate buffer chamber between the downstream side of the chokesand the mud gas separator, to dampen out pressure surges andaccommodate slugs of mud/gas.

(f) A means of by-passing the mud gas separator, rapidly, in the event of theblow-down pressure rating of the MGS being approached, so that thepressure in the MGS can be reduced and the well can be shut in safely.

FIG 5.2


5 - 5

In the manifold indicated, all equipment from the 3" choke line and HCR valvesthrough the various choke valves to the entry to the buffer chamber is rated at15000 psi working pressure. All valve stem seals using elastomers should havethose rated as for any elastomers connected to the BOP stack. The bufferchamber and the lines and valves leading into it are rated at 10000 psi, whilstthe lines downstream of the buffer chamber leading to the mud gas separatorare rated at 5000 psi.

5.2.1 Flow through a choke orifice

The remote, hydraulic chokes may be either bean type or plate type and theflow through those is either like flow through a nozzle or flow through asharp-edged orifice, as shown in FIG 5.3.

FIG 5.3

The rate of flow of fluids through an orifice depends upon:

(a) the size of the orifice,

(b) the fluid density,

(c) the pressure drop across the orifice.

Unfortunately the compressibility effects of gases mean that the flow of gasesthrough an orifice or nozzle is more complex than that of a liquid. There is alsoa "critical pressure ratio" for the flow of gases through a nozzle or orifice andthis means that if the downstream pressure is less than that specified by thecritical pressure ratio, then the nozzle or orifice flow is said to be choked, ie itis not capable of flowing more fluid regardless of how low the downstreampressure is, unless the upstream pressure is raised or the orifice size isincreased. For natural gases the critical pressure ratio is about 0.544. In suchcases of choked flow, the flow through the orifice is directly dependent on theupstream pressure.


5 - 6

The gas flowrate through an orifice in such a case can be calculated by aformula suggested by the US Bureau of Mines for Prover Orifices. This isdetailed in the appendix to this section as:-

Qg = 399.75 x P1 x d2 x E x (1/T1/Zav/SGg) [Eqn 5.2.1]

Where d = effective diameter of the choke orifice, in.P1 = upstream pressure at the choke, psia.T1 = upstream temperature R.

SGg = gas specific gravity, relative to air.Zav = a weighted average Z value for the gas.Qg = gas flow through the orifice, MSCF/D.

For a gas of SG 0.65 and upstream temperature of 120F and for an orifice witha 1" diameter in a 3" diameter choke line, the gas flowrates are:

Pressure Flowrate Flowratepsi SCF/min MMSCF/Day

500 7424 10.6911000 14969 21.5551500 22816 32.8552000 30910 44.5094000 63222 91.039

Because gases have very low densities and viscosities, compared to liquids, agiven pressure drop across a choke valve will flow much larger volumes of gasthan mud or hydrocarbon liquids. However, if the choke orifice or nozzle isFlow Choked as described above, the upstream pressure will be self adjustingto allow the appropriate gas flowrate for the actual choke aperture. This meansthat when gas starts to flow through the choke, large and rapid changes inchoke pressure can occur, causing difficulty in maintaining constant bottom holepressure.


5 - 7

5.3 MUD GAS SEPARATORS

Experiences in the early 1980s with influxes of high pressure gas in deep wellsindicated that in some cases the capacity ratings of the surface handlingequipment, in particular the liquid seal tubes, vent lines and mud gas separators(Poor Boy Degassers), were not adequate to circulate the influx safely out of thewell, at the normal slow circulating rates, although influx volumes and shut-inpressures indicated that anticipated maximum well-head pressures could besafely accommodated.

Typical mud gas separators in use at that time are shown overleaf in FIG 5.4and are vertical in design. The liquid seal was achieved by either a U-tube or adip-tube with a liquid seal height of about 10 ft and a vent tube of about 6"diameter. In addition separator capacity was usually less than 10 MMSCFD.

FIG 5.4

6" DerrickVent

Inlet

TRIP-TANKMOUNTED

6" DerrickVent

Inlet

Dip TubeHeight

Drain

SiphonBreaker

Usually Fitted

ShakerTrough

API

6" DerrickVent

Inlet

U-TUBEDESIGN

2" SiphonBreaker

At present there is no standard which is specifically derived for mud gasseparators. The current standard in use is that of API 12J Specification of Oiland Gas Separators, which is widely used in production separation technology.The basic concepts in separator design require to include consideration of:-

(a) The ability to achieve multi-phase separation.

(b) The range of fluid rheologies likely, from heavy mud to gas andeven hydrocarbon liquid or condensate.

(c) The fluid properties of gas-cut mud.


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(d) The likelihood of 2-phase slugs and surge flow.

(e) Venting of free gas and removal of liquid.

(f) Response and retention time to allow effective separation.

(g) Adequate instrumentation for temperature and pressure recording intransient situations.

The design philosophy should also address itself to:-

- High capacity to allow for the large gas expansion ratios.- The special problems associated with horizontal wells.- The need for compact design, particularly for offshore rigs.- Compatibility with established well control practices and the

Kick tolerances specified at various depths.- Reliability in operation.

Generally there are 2 common types of design ie the vertical and the horizontal.An example of a recent vertical MGS design is shown in FIG 5.5.

FIG 5.5

FROMBUFFER

TANK

PRESSURESENSOR/GAUGE

"GAS"

MGS CHAMBER30" TO 48" DIA

BAFFLEPLATES

8" TO 12" DIAVENT PIPE TO

DERRICK

PRESSURESENSOR

SHAKERPIThDIP OR SEAL TUBE

"LIQUID" POOLGAS/CUT


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Generally there are 2 separate criteria of MGS performance ie:-

(a) Separation Capacity.(b) Blowdown Capacity.

If the MGS is correctly proportioned and designed, it is probable that theblowdown capacity will be 50 to 100% greater than the separation capacity.Those are detailed below.

5.3.1 Separation Capacity

The separation process in an atmospheric mud gas separator is governedmainly by an application of STOKES LAW. This is used to dete

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