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10" VENT
MGS PRESSURE SENSOR
VENT TO TOP OF DERRICK
8 FROM C & K MANIFOLD, 4" PIPE
36" DIAMETER MUD - GAS SEPERATOR
DOWNSTREAM CHOKE TEMP. SENSOR
DRILL FLOOR LEVEL
REMOTELY ACTUATED
6
TO MUD/GAS SEPARATOR
REMOTE CHOKE
TO SHALE SHAKER
MANUAL CHOKE MANUAL CHOKE
5
REMOTE CHOKE
DOWNSTREAM CHOKE TEMP. SENSOR
TO PORT FLARE LINE
MAIN DECK LEVEL 6 Meters
DIP TUBE PRESSURE SENSOR
TO STARBOARD FLARE LINE
7 UPSTREAM KILL LINE TEMP. SENSOR
4
DATA MONITORING SYSTEM AND BYPASS CONTROL UNIT MGS
STBD
PORT
DIP TUBE PRESSURE
MGS OPEN CLOSED
OPEN CLOSED
OPEN CLOSED
PRESSURE
TO SHALE SHAKER
BOP
7 8
TEMP.
TO CEMENT UNIT MUD PUMPS
1,2
UPSTREAM CHOKE LINE TEMP.
GLYCOL INJECTION POINT
CHOKE LINE
KILL LINE
UPSTREAM CHOKE TEMP. SENSOR
3
3
DECK LEVEL
UPSTREAM KILL LINE TEMP. ALARM
4
DOWNSTREAM CHOKE TEMP.
REMOTE CHOKE AREA
SEA LEVEL
5,6
SUBSEA TEMP. SENSOR
1
2 FLEX JOINT ANNULAR PREVENTEE
SUBSEA TEMP. SENSOR
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Aberdeen Drilling Schools &Well Control Training Centre
HIGH PRESSURE HIGH BOTTOM HOLE TEMPERATURE
HPHT This course has been prepared by Aberdeen Drilling Schools using industry standard HPHT operational guidelines. OBJECTIVES OF THE COURSE To introduce HPHT operations and highlight the concerns and hazards of drilling HPHT wells. To encourage operational personnel to offer suggestions and recommendations to improve the existing guidelines and 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) 582896 E-mail
[email protected] www.aberdeen-drilling.com
CONTENTS Section 1
COURSE INTRODUCTION
2
GAS BEHAVIOUR, KICKS AND CONTROL
3
GAS SOLUBILITY IN OBM'S - EFFECTS ON KICK BEHAVIOUR
4
RIG EQUIPMENT SUMMARY
5
SURFACE GAS HANDLING CAPACITIES AND PROCEDURES FOR HPHT WELLS
6
DRILLING AND WELL CONTROL PROCEDURES FOR HPHT WELL PROGRAMMES, TRAINING AND COMMUNICATION
7
SHUT-IN PROCEDURES AND DECISION TREES
8
BULLHEADING OVERVIEW
9
VOLUMETRIC METHOD OF WELL CONTROL
10
STRIPPING
11
THE EFFECTS OF TEMPERATURES AND PRESSURES ON MUDS
12
THE EFFECTS OF BOREHOLE BALLOONING ON DRILLING 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 WELLS
Appendix 2.
NPD GUIDELINES FOR HPHT WELLS
Appendix 3.
HPHT MUD PRESENTATION
Appendix 4.
HPHT CEMENT PRESENTATION
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CONTENTS
1.1
GENERAL OVERVIEW
1.2
LEARNING FROM THE PAST
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HPHT Course - Section 1
1.1 GENERAL OVERVIEW
HSE Definition for HPHT Wells: Where the undisturbed bottomhole temperature is greater then 150o C/300o F and where either the maximum anticipated pore pressure of any porous formation exceeds 0.8 psi/ft., or pressure control equipment with a rated working 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
1-2
HPHT Course - Section 1
➞
DRILL PIPE
ANNULUS
➞
DRILL PIPE PRESSURE
CASING PRESSURE
1220 psi / 84 bar
800 psi / 55 bar
MUD HYDROSTATIC PRESSURE IN THE DRILL PIPE
MUD HYDROSTATIC PRESSURE IN THE ANNULUS
8613 psi / 594 bar
9100 psi / 628 bar
67 psi / 5 bar
TOTAL PRESSURE ACTING DOWN (9100 + 800 = 9900 psi) (628 + 55 = 683 bar)
9900 psi / 683 bar
9900 psi / 683 bar
TOTAL PRESSURE ACTING DOWN (8613 + 1220 + 67 =9900 psi) (594 + 84 + 5 = 683 bar)
9900 psi / 683 bar
FORMATION PRESSURE
9900 psi / 683 bar
9900 psi 683 bar DRILL PIPE : SIDPP + HYDROSTATIC PRESSURE OF MUD = FORMATION PRESSURE ANNULUS : SICP + HYDROSTATIC PRESSURE OF MUD + HYDROSTATIC PRESSURE OF INFLUX = FORMATION PRESSURE 1-3
HPHT Course - Section 1
OPERATIONAL OVERVIEW
SUBJECT : DISPERSED / NON DISPERSED INTRUSIONS / KICKS W.B.M. O.B.M.
WHAT HAPPENS : ✺
BASIC PHYSICS ?
✺
THE WORD IS -
PREVENTION ! EARLY DETECTION ! YOU WORKING AS A TEAM IS THE
1-4
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HPHT Course - Section 1
OPERATION IN PROGRESS WHILE THE KICK OR BLOWOUT OCCURRED DRILLING COMPLETION WORKOVER (WELL KILLED)
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31
Bit on bottom Pulling out of hole (POOH) Going in hole (GIH) Circulating Fishing Logging Casing running Primary cementing (incl. Nipping down BOP) Drill stem testing Exchanging BOP Xmas tree (excl. cementing) Running tubing and packer Killing Perforation Squeeze cementing Stimulation Cleaning Gravel packing Pressure testing (Production well alive) Regular production Production testing Wireline work Maintenance (Xmas tree, wellhead) Freezing Production logging Testing of safety valves Stimulation (without killing) Gas lifting Misc. concentric tubing operations Water injection Gas injection Operation unknown
NUMBER OF BLOWOUTS
19 17 4 3 2 1 2 9 1 3 1 1 1 1 6 4 4 1 1 1 18 100
* Worldwide statistics based on case histories. 1-5
HPHT Course - Section 1
WELL CONTROL INCIDENT RATE for NORMAL PRESSURE WELLS
Incident in 20 to 25 Wells or
4% - 5% * Worldwide statistics based on verbal survey of oilfield personnel.
WELL CONTROL INCIDENT RATE FOR 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.
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HUMAN FACTORS REVIEW FOR 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
5
INADEQUATE TESTING
6
INADEQUATE DOCUMENTATION
7
IMPROPER METHOD PROCEDURE
11%
8
IMPROPER PLANNING
12%
9
NO DIRECT HUMAN ERROR INVOLVED
2% 2%
8%
* Worldwide statistics based on case histories. 1-7
HPHT Course - Section 1
CAUSES OF PROBLEMS AND LOST WELLS
1-8
✺
RIG AND SYSTEM PRESSURE CAPABILITIES
✺
LACK OF PORE PRESSURE KNOWLEDGE AND SIGNAL NEGLIGENCE
✺
WILDCAT TYPE GEO PROGNOSIS
✺
TOO SHALLOW SETTING OF INTERMEDIATE CASING
✺
LACK OF CASING PROGRAMME FLEXIBILITIES
✺
OPERATIONAL MISCONDUCT
HPHT Course - Section 1
COMMON DIFFICULTIES
✺
KICKS (AVERAGE KICK FREQUENCY : 2 PER HPHT-WELL)
✺
PROBLEMS GETTING THE WELL KILLED
✺
LOST CIRCULATION
✺
STUCK PIPE
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HPHT Course - Section 1
WELL CONTROL AND HOLE CONSIDERATIONS
4 to 7 PPG / .48 to .87 SG OPERATING MARGIN
1 2 3 4 FRACTURE PRESSURE PORE PRESSURE
NORMAL PRESSURE D E 13,000 ft ≈ 4000 mtr P T H
TRANSITION ZONE 1 to 2 PPG / .12 to .24 SG OPERATING MARGIN
0
PRESSURE 1) 2) 3) 4)
1 - 10
ABNORMAL PRESSURE
SAFE TRIP MARGIN ECD OVER BALANCE SWAB AND SURGE PRESSURE SAFETY FACTOR
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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
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HPHT Course - Section 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 means that a change of pressure will cause a “large” change of volume of a gas, but the same 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 of pressure 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 a vapour. When the pressure or temperature of a gas change then the volume also changes according 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:PxV=RxT Where P V T R
[Eqn 2.11]
= = = =
the pressure in the gas, in absolute units. the gas volume. the temperature of the gas, in absolute units. 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:PxV=nxRxT
[Eqn 2.11a]
TABLE 2.1 Pressure units abs.
Volume units
lbf/ft2 lbf/in2 N/m2 bar
cu.ft US gal cu.m cu.m
Temperature Value of units constant R abs. °R °R °K °K
1545 80.3 8314 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)
2-2
HPHT Course - Section 2
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 Where P V T mass NB:
= = = =
[Eqn 2.12]
pressure in psia. gas volume in US gallons. gas temperature in °R absolute. n lb-mol.
For all gases 1 lb-mol has a volume of 359 cu ft at a pressure of 1 atmosphere and a temperature of 32°F or 1 Kg-mol occupies 22.41 cu m at 1 atmosphere and 0°C. (Avogadro’s 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 psia and a temperature 100°F? 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.
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HPHT Course - Section 2
2.1.1 Units Systems and Units Conversions. In many cases drilling operations are planned using a system of units which is either the SI or Oilfield systems. Some conversion factors between the two systems are shown in TABLE 2.2. TABLE 2.2 Quantity Depths Volumes Density Pressure Press grad Pipe dias Capacities Other dimensions Weight, force Mass Temperature Flowrates
SI OR METRIC metres litres Kg/litre (or SG) bar bar/10m litres/m Kg cm 1 atmosphere °C
-> x x x x x x x x x x
Units used
Oilfield Units
metres litres or cu metres Kg/litre(ie SG) N/m2 or bar bar/10m mm litres/m or cu.m/m cm or m Kgf Kgm °C litres/min
feet US barrels or gallons lbm/US gallon (ie ppg) lbf/in2, ie psi psi/ft ins bbl/ft ins or ft lbf or tonf lbm or tonm °F bbl/min or gal/min
TO
->
3.281 0.2642 8.33 14.504 0.4415 0.0001917 2.2046 2.54 14.695 1.8 + 32
OILFIELD = = = = = = = = = =
ft US gallons ppg psi psi/ft bbl/ft lb ins psia °F
In some cases metric pressure in units of Kgf/cm2 may be used. In this case the added conversions are: Kgf/cm2 x 14.22 2 Kgf/cm /10m x 0.433 (ie ∫ SG) 1 atmosphere = 1.0332 Kgf/cm2
= =
psi psi/ft
In the above table, to convert from Oilfield units to SI, then divide the Oilfield unit value by the above listed conversion factors. 2-4
HPHT Course - Section 2
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 such variations the equation of state is modified to the form:PxV=nxZxRxT
[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. The value of Z is 1 at atmospheric conditions and it varies between 1, down to about 0.6 and then up to a value which may be greater than 2.4. The variation of Z for a gas with 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 to Solve Equation of State for Z-Factors” by L.Yarborough and K.R.Hall. SPE Reprint Series No 13 Vol 1 (1977) pp 233-235. FIG 2.1
2.2
200 OF
GAS COMPRESSIBILITY FACTOR Z
2.0
150 OF
250 OF
1.8
1.6
300 OF
1.4
1.2
Z = Value of Gas
300 OF
1.0
Mol. Wt = 23.5 SG = 0.8114 (Relative to air)
150 OF
0.8 0.6 0
2
4
6
8
10
12
14
16
18
20
22
GAS PRESSURE 1000'S (psia)
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HPHT Course - Section 2
2.2.1: The density and pressure gradient of a real gas, of molecular weight M, in oilfield units and in SI units is given by:Density P.M Oilfield : w = ––––––––––––– (ppg) 80.3 x Z x T
SI
.001 x P x M : w = –––––––––––––– (Kg/l) 8314 x Z x T
Pressure gradient
Gg = 0.052 x w (psi/ft)
Gg = 0.981 x w (bar/10m) = 0.433 x w (psi/ft)
The specific gravity of a gas is measured relative to the density of air rather than fresh 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 300°F. The molecular weight is 23.5. What will be its density and pressure gradient. Use FIG 2.1 for the Z value.
SOLUTION From FIG 2.1 at 12000 psia and 300°F, the Z value is 1.59. Substituting this into the density formula (TABLE 2.2), gives: PxM 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
2-6
HPHT Course - Section 2
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 those at a new condition of P2, V2, T2 and Z2 (as shown in FIG 2.2) then, from Eqn 2.21 : PV/ZT = constant = R, then:P2 x V2 P1 x V1 ––––––– = ––––––– Z1 x T 1 Z2 x T2
[Eqn 2.31]
This assumes that the gas remains as a gas and that there is no change of mass by leakage or addition. FIG 2.2
State 1
P1 V1 Z1 T1
Expand Compress
State 2
P2 V2 Z2 T2
P1 V1 P V = R = 2 2 Z1 T1 Z2 T2 2.3.1 Boyle's Law Boyle’s Law (1662) is a simplification of the above statement in which the temperature and compressibility products are taken to be constant ie: P1 x V1 =
P2 x V2
[Eqn 2.32]
Boyle’s Law is commonly used in drilling practice to give an approximate answer. If the Z and T values are not constant, the use of Boyle’s Law will produce errors which may be interpreted as being on the safe side. However, in some shallow wells, Boyle’s Law may be quite accurately applied.
2-7
HPHT Course - Section 2
2.3.2 Gas Gradient The density of a gas is proportional to the gas pressure. The gas pressure gradient formula is given above in 2.2.1. As a gas bubble is expanded to the surface, its pressure and its pressure gradient must change (and reduce). However, it can be shown that, as the gas bubble expands and its gradient reduces, the length of the gas bubble increases so that the total pressure drop across the bubble is constant for constant T and Z conditions.
2.4 STANDARD CONDITIONS In oilfield practice, gas volumes are usually compared by reference to Standard Cubic Feet (SCF) or Standard Cubic Metres (SCM). The standard volume of a gas (Std cu m) is the equivalent volume which the gas would occupy at standard atmospheric conditions of 14.695 psia (usually quoted as 14.70) (1.0132 bar) and 60°F (15.6°C). The value of Zs is taken as 1. Thus a gas which has a volume of V (cu ft) at P, T and Z will occupy a standard free volume (cu ft) of:P x V x 520 x 1 Vs = –––––––––––––– = 14.70 x T x Z
35.37 x P x V –––––––––––– TxZ
[Eqn 2.41]
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 = ––– = –––––––––– V Zbh x Tbh
[Eqn 2.51]
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 Pbh For 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 a well with 18.2 ppg mud and BHT of 300°F is shown in FIG 2.3. 2-8
HPHT Course - Section 2
FIG 2.3
Assumed Conditions (Est) Temp °F
Specific Volume of Methane ft3 /lb
Depth ft
Volume of Gas ft 3.
85
23.0
0
354
564
130
0.7
600
10.7
940
135
0.4
1000
6.1
Pressure (18.1ppg) PSIG
SURFACE VOLUME 354 ft3 23 ft3 878 ft3
(5.1) 1880
150
0.195
2000
3.0 (2.91)
3760
180
0.115
4000
VOLUME OF GAS (INCREASING)
1.77 (1.58)
5640
210
0.08
6000
1.23
VOLUME OF GAS (INCREASING)
(1.32)
7520
235
0.073
8000
1.12 (1.16)
9400
260
0.068
10000
1.05 (1.08)
EXPANSION Real Gas Law 11280
280
0.064
12000
Boyle's Law
0.98 (1.03)
13160
300
0.065
14000
1
1 ft3 BOTTOMHOLE
Volume of 1 ft3 of Methane at BottomHole Condition
Figures in brackets are for 10.5ppg Mud and 260° bht
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HPHT Course - Section 2
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 about 16000 ft TVD (4900m) and with a mud density programme as specified, is shown in FIG 2.4.
FIG 2.4
1.56 SG
1.77 to 2.01 SG
1.66 SG
340 320 300 280
Estimated Gas Influx.
260
Expansion Ratio from Bottom Hole to Standard Surface Conditions.
240
Gas MW = 23.5
3
GAS EXPANSION RATIO 3 (m at surface per. m at formation)
360
220 2000
3000
4000
CURRENT TVD of Drilling (m)
2 - 10
5000
HPHT Course - Section 2
2.5.1 WORKED EXAMPLE: A 10 bbl (1590 litre) gas kick is taken at 15420 ft (4700m) TVD in a well with 1.95 SG mud and the SIDPP is 350 psi (24.13 bar). The downhole temperature is estimated to be 320°F (160°C) 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): Pbh = = = Tbh =
The bottom hole pressure of the gas influx is: SIDPP + mud hydro = SIDPP + Gm x TVD 350 + 1.95 x 0.433 x 15420 13370 psig = 13385 psia (935 bar) 320 + 460 = 780°R
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 of 2.5 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 - 11
HPHT Course - Section 2
2.6 GAS KICK AND EXPANSION WHILST CIRCULATING OUT Prediction of Maximum Pressures at the Casing Shoe and Choke. Refer to FIG 2.5. FIG 2.5
SIDPP
Lgas
TVD - D
Depth of Interest Di
SICP
Mud Gm
m bbl Linear Capacity
Ca =
Gm
Gas Gi Vg
Mud Gm
Pbh
=
Ppore
Initial assumptions (a) (b) (c) (d) (e)
The Driller’s Method is used initially. Temperature is constant. An ideal gas is used ie Z = 1 = const. The kick is not dispersed. Pressure drop across the gas is neglected.
The maximum pressure Pi at any depth of interest Di below the surface occurs when the top of the gas bubble is adjacent to the point at depth Di.
2 - 12
HPHT Course - Section 2
Then:Pi = Pbh - Gm x (D - Di - Lg) Where D Lg Gm Pbh
= = = =
[a]
TVD (ft or m) length of gas at Di (ft or m) current mud pressure gradient (psi/ft or N/m2/m) 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 Where b c Pdp Vg1 Ca
[Eqn 2.61]
= = = = =
SIDPP + Gm.Di Gm x Vg1 x Pbh/Ca SIDPP ( psia or N/m2abs) initial influx volume (bbl or cu m) 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/m2abs)
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 of Di. To calculate the maximum pressure at the choke, substitute 0 for Di. The above analysis is primarily for a surface BOP stack. For a sub-sea well head, the method can be adapted .
2 - 13
HPHT Course - Section 2
2.6.1 CORRECTIONS for Z, T and W & W Method The above anaylsis ignores changes in temperature, gas Z values and also the pressure drop across the gas influx. Corrections for those can be made and incorporated into the values of coefficients “b” and “c” as well as modifying the analysis 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 also include gas gradient.
b = Pdp + Gm x Di - d Pg d Pg = H1 x Gg
Pdp x Vds b = –––––––––– + Gk D1 - d Pg D x Ca
C = no change
C = Gk x Vg1 x Pbh/Ca
b, as in 1 above.
b, as in 1 above.
2. As in 1 above and include change g T and Z values.
C=
Gm x Vg1 x Pbh x Ti x Zi Ca Tbh x Zbh
Vg = Vg1 x Pbh x Ti x Zi Pi x Tbh x Zbh
Where :
C, as for driller's, but use Gk instead of Gm. Vg, as for Driller's.
Vds= Total volume of drillstring, litres or bbls. Gg = Gas gradient, Kgf/cm2/m or psi/ft. Gk = Kill mud gradient, Kgf/cm2/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 approximate estimates of changes in Z values between two circulation depths.
2 - 14
HPHT Course - Section 2
FIG 2.6
SURFACE PRESSURE Compressibility ratio vs depth for different kill weight muds. 2.0 18 17 16 15
1.9 1.8
14
1.7
13 12 11
1.5
KILL MUD WEIGHT, LB/GAL
Z=Z2 /Z1
1.6
1.4 1.3
Z
1.2 1.1 1.0 0.9
5000
7000
9000 11,000 TOTAL DEPTH
13,000 15,000 FT
17,000
2.6.2 WORKED EXAMPLE: The following data is for a well in which a gas kick occurred:TVD of the well TVD to casing shoe SIDPP SICP Influx volume DC/OH linear cap. DP/OH/Csg linear cap. Fracture grad at shoe Current mud grad.
= = = = = = = = =
14000 ft (4267 m) 10500 ft (3200 m) 520 psig (35.85 bar) 830 psig (57.23 bar) 12.6 bbl (2.0 cu m) 0.030 bbl/ft x 500ft. 0.046 bbl/ft. 0.930 psi/ft (2.104 bar/10m) 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 - 15
HPHT Course - Section 2
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 the shoe (810 psig). 2 - 16
HPHT Course - Section 2
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 the choke for the sub-sea wellhead condition. Refer to FIG 2.7. FIG 2.7 L is the vertical depth from the RKB to the sub-sea wellhead.
Pdp
The depth of interest Di is measured from the RKB as before.
Pck
RKB
For the condition when the influx is at the top of the annulus, Di = L and the value of the pressure at the top of the annulus and the choke pressure can be calculated from Eqns 2.6 and 2.63, as Pwhd and Pckwhd. Once this has been done, the maximum pressure at the choke, when the gas is at the choke will be approximately:
Cc ft/bbl
L Di
Mud Line
Gas Ca ft/bbl D Hm
Mud Wm ppg
Pbh
Pckmax = Pckwhd + L x (Gm - Gg)
[Eqn 2.64]
2 - 17
HPHT Course - Section 2
2.7 DISPERSED KICKS AND NON-DISPERSED KICKS In most simplified kick analyses it is assumed that the kick is non-dispersed among the mud. ie it is assumed that a gas influx is a single large gas bubble. Nondispersed kicks do occur in the cases where an influx is swabbed in or when the well flows with no mud circulation from the pumps. However, in cases of drilled kicks, when the well flows whilst the mud is being circulated, the influx will be mixed with and dispersed within the mud as the influx enters, as shown in FIG 2.8. As a consequence the following may be deduced: FIG 2.8
(a)
(b)
0.046 bbl/ft
(a) 5 bbl non-dispersed influx for same SICP-SIDPP = 86 psi
Mud
Gm = 0.75 psi/ft
Mud
Dispersed Kick Zone
Gi (by "standard" formula) = 0.235 psi/ft 0.03 bbl/ft
500 ft
(b) 5 bbl dispersed influx (b) in 5 minutes at mud rate (b) of 8 bbl/min
1152 ft
Mixed Zone = 45 bbl SICP-SIDPP = 86 psi 167 ft
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 from the simple calculation. This means that the influx will arrive at the choke sometime earlier than expected. (c) The influx gradient and density will in fact be lower than those calculated by the method : Gi = Gm - (SICP - SIDPP)/Hi (d) These will result in a slightly lower kick tolerance than may be expected from the usual calculations. 2 - 18
HPHT Course - Section 2
The main reason why the more accurate calculation of influx gradient is not made is that 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, on the rig. If it is necessary to make an estimate of what the influx gradient is, as calculated from a dispersed kick, then the formula given below can be used:
Vmz x (SICP - SIDPP) Gi = Gm - ––––––––––––––––––– Vi x Hmz Where : Vmz = = Vi = Qm = tk = Gm = Gi = SICP = SIDPP = Hmz =
[Eqn 2.71]
volume of mixed mud and influx, bbl Vi + Qm x tk measured influx volume (pit gain) bbl mud circulation rate, bbl/min time interval during entry of kick, min current mud pressure gradient, psi/ft influx gradient, psi/ft shut-in casing pressure, psig shut-in drillpipe pressure, psig height of mixed or dispersed zone, ft, as calculated normally for 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 and SIDPP values recorded were as 650 and 300 psig, with current mud of 12.0 ppg at 11500 ft TVD. The time interval of flow was estimated to be 5 minutes and the mud circulation was 8 bbl/min whilst the influx flowed. The annulus capacities were: DC/OH DP/OH
= 0.03 bbl/ft x 600 ft. = 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 - 19
HPHT Course - Section 2
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 a non-dispersed kick.
2 - 20
HPHT Course - Section 2
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 this body 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 surrounding fluid, then it will migrate upwards. The greater the density difference, the greater will be 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. (b) Fluid viscosity. (c) Fluid gelling. (d) Surface tension. (e) Size and shape of the immersed body.
FIG 2.9
Upward Velocity
Buoyancy Force > Wt
Gas
Weight Liquid
2 - 21
HPHT Course - Section 2
2.8.1 Gas Migration in a shut-in well The fundamental concept of pressure control is CONSTANT BOTTOM HOLE PRESSURE. This means that normally, in a circulation, gas MUST BE ALLOWED TO EXPAND IN A CONTROLLED WAY. If a gas bubble migrates in a static shut-in well and it is not allowed to expand, then the gas pressure will not change (except for temperature changes), and so it will bring formation pressure up with it. This means that all well-bore, bottom-hole and surface pressures will also rise, with consequent dangers to the well. See FIG 2.10 FIG 2.10 SICP 800
SIDPP 400
SICP 1200
SIDPP 800
Vg Pp
Pbh = Ppore + 400
Pp Vg Ppore
Ppore
The static rate of gas migration in ft/hr is: Rate of rise of SIDPP or SICP (psig/hr) Vel. = –––––––––––––––––––––––––––––––– Mud gradient ( psi/ft)
[Eqn 2.81]
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-in well, free gas migration rates ARE SIGNIFICANTLY HIGHER THAN THOSE VALUES. Experiments on real wells and computer studies have confirmed that gas cooling,
2 - 22
HPHT Course - Section 2
mud seepage to open hole sections and wellbore elasticity can give values of SICP and SIDPP which are much lower than they would be otherwise. If gas migration rates are calculated on surface-read changes in SICP and SIDPP, then they are likely 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 a controlled expansion of gas. This can be done by bleeding off surface pressure at the choke. CASE 1 : Bit at or near bottom In this case, pressure at the choke is bled off until the SIDPP has fallen to its original value by an amount dP. This allows the gas to expand by an amount dV1 and a similar volume of mud issues from the choke. It also allows the BH pressure to fall to its original value. This process is repeated periodically. Since the gas is allowed 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 similar to the first circulation of the Driller’s Method with the gas at the choke. FIG 2.11
Pressure
SICP
SIDPP Time
CASE 2 : Pipe out of the hole In this situation, no U-tube exists, and the SICP is used to monitor pressures. It is then necessary to allow gas to migrate to the surface and control surface (and bottom hole pressure) by the volumetric method.
2 - 23
HPHT Course - Section 2
2.8.2 Gas Migration in a Circulation Case Research carried out in the UK and Norway indicates that, when the pumps are started and circulation is established, the gas migration rate is likely to be much higher than the values quoted above. The shear-thinning effects on the mud and reduced gels allow larger gas bubbles to overtake smaller ones, when circulation is in progress. Data on this has been published in the paper “Gas Rise Velocities During Kicks” by A.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 as the kick is circulated. This has the effect of causing gas to arrive at the surface much earlier than anticipated, and higher gas flow-rates to be produced. NB: The above has been written with respect to gases. For liquid influxes, the laws of buoyancy still apply as they do with solids (eg wood) in liquids. The relative incompressibility of a liquid influx is likely to mask any significant changes in SIDPP or SICP. The fact that no such changes may be recorded should not be taken to imply that liquid or dense gas influxes do not migrate.
2 - 24
HPHT Course - Section 2
2.9 KICK TOLERANCE Gas influxes must be allowed to expand. The initial SICP should obviously be less than MAASP, but to circulate a gas kick safely, then it is also necessary that the choke pressure of the expanding gas at the casing shoe should not exceed MAASP. A definition for a gas Kick Tolerance is thus: Kick Tolerance is the maximum tolerable gas influx volume which can be taken and circulated 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 MAASP SICP E
PRESSURE
L
Mud
DEPTH (TVD)
0
di Gra ure
ss Pre
ent/ Line
Shoe
S
K
N
Fra
H max (gas)
re
ctu Lin
F
e
M A
D H1 (gas)
B
Phyd
Ppore
C
SIDPP NB. Well geometry assumed to be constant.
2 - 25
HPHT Course - Section 2
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 = –––––––––––––– Gm - Gi
[Eqn 2.91]
Where : Hmax = maximum length of influx, at BH or shoe, in ft or m. Gm and Gi are the current mud and assumed influx gradients 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 stripped back 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 for the bottom hole condition will determine the kick tolerance. HOWEVER in cases where there are long open hole sections, the value of Hmax at the 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 SG addition, from Eqn 2.91, as follows : MAASP - (Gm - Gi) x Hi Kick tolerance, SG = ––––––––––––––––––––– 0.433 x TVD
[Eqn 2.92]
An alternative way of showing Kick Tolerance is in a graphical method, as shown in FIG 2.13. The output from a computer program to calculate a range of kick tolerances for a well with data as given below in WORKED EXAMPLE 2.9.1 is also shown and has been used as the basis for the graph. Further work on this topic is contained in the paper “Understanding Kick Tolerance and its Significance in Drilling Planning and Execution”, by K.P Redman (SPE Drilling Engineering December 1991 pp 245-249).
2 - 26
HPHT Course - Section 2
Tolerable SIDPP
FIG 2.13
Circulate Kick Out Tolerable Influx Volume bbl
2.9.1 Worked Example The following data relates to a well: TVD of drilling TVD of shoe Frac gradient(shoe) Current mud DC/OH capacity DP/OH capacity
= = = = = =
16000 ft. 12000 ft. 0.950 psi/ft. 0.860 psi/ft. 0.0292 bbl/ft x 400 ft. 0.0459 bbl/ft.
Calculate the Kick Tolerance for a gas influx with gradient of .15 psi/ft for a SIDPP = 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 - 27
HPHT Course - Section 2
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 Boyle’s 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 on formation breakdown than the Driller’s method. The condition for this benefit is: open hole volume + influx volume > drillstring volume The W & W method, however, will usually always give a lower value of maximum
2 - 28
HPHT Course - Section 2
pressure at the choke than the Driller’s 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, Planning and 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.
2 - 29
• ABE
RD
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
C
OL S • CE
N TRE
C
ON
3. GAS SOLUBILITY IN OBM’S - EFFECTS ON KICK BEHAVIOUR.
D RI L LI N G S
HO
L & WEL
HPHT Course
EE N
TR O L T R AI NIN
G
HPHT Course- Section 3
3.1 PHASES OF HYDROCARBON FLUIDS Hydrocarbon reservoirs fall into 3 classes: Liquid reservoirs Here the reservoir fluid is a homogeneous liquid and the following points may be noted: a)
A liquid influx will remain as a liquid, but some gas may be produced downstream of the choke, if the liquid has dissolved gas within it. An average gas production rate in North Sea hydrocarbon liquid reservoirs is about 1,000 - 1,500 SCF/Res bbl of oil.
b)
The liquid will not mix with water based muds, although the kick may be dispersed in the mud. A liquid influx will mix readily with the oil phase of oil based muds.
c)
The pressure at the choke will change only a little as the influx is circulated to the choke. The measured pit gain will be a reasonably accurate measure of the influx volume.
Gas reservoirs Those are reservoirs in which the fluid is free gas and when this is produced to surface, there is free dry gas at the surface.
3-2
a)
Such a gas influx will not dissolve readily in water-based muds, the solubility being about 1% of the gas solubility in oils.
b)
The pit gain as measured will be a reasonably accurate measure of the influx 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 the closer the gas gets to the choke.
d)
An influx from a free gas reservoir in an oil based mud will dissolve readily in the oil phase of the OBM.
e)
A dissolved gas influx in OBM will behave as a liquid influx until its bubble point pressure is reached, after which large volumes of gas may be released in the annulus, with rapid rises in choke pressure.
f)
The measured pit gain will generally be somewhat smaller than the true free gas influx volume, the discrepancy becoming larger at low pressures.
HPHT Course - Section 3
Gas condensate reservoirs Such reservoirs are now being drilled and they are mainly in high pressure regions. 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 a temperature above its critical temperature.
b)
A gas influx from a gas condensate reservoir may start to condense in the annulus as its pressure and temperature are reduced. If the mud is water based, the effect will be largely that of a free gas. If the mud is oil-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
A = 10 bbl free gas in WBM. B = 10 bbl liquid influx. C = 10 bbl gas influx desolved in oil-based mud.
PRESSURE AT CHOKE
Q = Position of bubble point.
A&C A C
Q
B
PUMP STROKES
3-3
HPHT Course- Section 3
3.2 PHASE BEHAVIOUR A typical phase equilibrium diagram for a hydrocarbon system is shown in FIG 3.2. The following should be noted: a)
For pressures above the bubble point line and below the critical temperature, ie ZONE A: the material in the reservoir is a liquid.
b)
For pressures above the dew point line, ie ZONE B: the material in the reservoir is a gas.
c)
For material outside the dew point line ie ZONE C: the material is always a gas.
d)
For material within the phase envelope, ie ZONE D: the material is a 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, then when the pressure reaches the bubble point line, the liquid starts to evaporate (ie boil) and bubbles of gas appear within the liquid. As the expansion proceeds, more gas is produced at the expense of liquid.
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 of liquid start to appear in the gas (ie the gas condenses). As the expansion proceeds, more liquid is produced at the expense of gas
FIG. 3.2
Zone A 7000
Zone B
Liquid
Free Gas
1 De
6000
w
bb
Bu
40 %
25 %
le P
2 - Phase Zone D
10%
oint L
ine
e Lin int Po
CP
Critical Point
Pressure psig
Zone C
3
4
2
0 400
-200 Temperature °F
3-4
800
HPHT Course - Section 3
3.3 GAS SOLUBILITY Hydrocarbon gases are highly soluble in hydrocarbon liquids. Some work on this was published by Thomas, Lea and Turek in 1982 and by O’Bryan, Bourgoyne, Monger and Kopcso in 1986. Graphs of the solubility of (a) methane gas (CH4) in diesel and (b) the solubility of methane, carbon dioxide (CO2) and hydrogen sulphide (H2S) in diesel are shown in FIGS 3.3 and 3.4. FIG. 3.3
200°F
400°F
500°F
1000 scf CH4/std bbl Oil
8
600°F
H2S at 250°F
GAS SOLUBILITY IN DIESEL (Methane Gas)
6
4
Gas solubility to achieve saturation. Increase of temperature reduces pressure to get saturation. At constant pressure, increase of temperature increases saturation.
2
2000
4000
6000
8000
Pressure psia
FIG. 3.4
MISCIBILITY PRESSURE FOR VARIOUS GASES IN NO. 2 DIESEL OIL
Miscibility Pressure, 1000 psia
10
8
Meth ane
6
4
e oxid n Di o b r Ca
2 Ethane
lphide gen Su Hydro
0 100
200
300
400
Temperature, °F
3-5
HPHT Course- Section 3
From FIGS 3.3 and 3.4 it can be noted that: a)
The solubility of methane in diesel may be many 1,000’s of SCF/bbl of diesel.
b)
At each temperature he solubility graphs turn almost vertical at a particular pressure. This is the miscibility pressure for methane/diesel mixtures at those specific temperatures. At the miscibility pressure, the diesel appears to have an “infinite” capacity to dissolve methane and produce a homogeneous liquid.
It should be further noted that the solubility of hydrocarbon gases in water is about 1% of the solubility in hydrocarbon liquids. 3.3.1 Gas Kick Solubility in Oil-based Mud Effects on Kick Detection A gas kick from a gas reservoir will behave according to the gas law and to the phase 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 gas dissolves in the oil phase of the OBM, producing a new fluid mixture, which will have an entirely unique phase equilibrium diagram, with the new mixture being in the liquid phase of the phase relationship. This liquid will have its own distinctive bubble point pressure, depending upon the gas/liquid concentration and temperature. Thomas, Lea and Turek in their paper “Gas Solubility in Oil-Based Drilling Fluids-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 be detectable.
b)
Short flow-checks are not reliable in OBM’s. 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 gas entering from the reservoir.
d)
As a gas influx dissolves in the oil phase of the OBM, this masks the surface responses of pit gain and flow, which are less pronounced than in WBM.
It can also be concluded that ANY SMALL UNDETECTED DISSOLVED GAS INFLUX which is circulated in an OPEN WELL, will reach a bubble point pressure which is likely to occur in the annulus (or marine riser) near to the surface. The gas expansion ratio at this point may be in excess of 300, as demonstrated in Section 2 of the manual!
3-6
HPHT Course - Section 3
The consequence of this is that a small, undetected, dissolved swab of 1/4 bbl may not be detected until it reaches its bubble point and becomes 75 bbl of free gas in the annulus just below the slip joint. 3.3.2 WORKED EXAMPLE A gas influx of 10 bbl flowed into a well in a period of 10 minutes, when the mud circulation rate was 8 bbl/min. The bottom hole pressure was 12,000 psia, the gas Z value was 1.7 and the temperature was 260°F. Calculate : a)
The gas/mud and the gas/oil concentrations, if the oil volume factor in the oil-based mud was 0.55.
b)
The bubble point pressure when the temperature was 140°F and the gas SG relative to air was 0.75. Use the formula given in Equation 3.32 in the REFERENCE to Section 3.
SOLUTION Part (a) The gas equivalent volume of gas at standard conditions is: 35.37 x Pbh Vs = –––––––––––– x Vbh x 5.615 = Zbh . Tbh
35.37 x 12,000 –––––––––––––––– x 56.15 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.
3-7
HPHT Course- Section 3
Part (b) The bubble point pressure will be the saturation pressure at which the above is the gas/oil concentration at 140°F. Using the values for “a” and “b” as quoted in Equation 3.3.1 and calculating “n” from: 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 point pressure 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. 3.4 DRILLED GAS AND KICK GAS The rate at which drilled gas is released into the mud in the annulus is related to the volumetric rate at which the rock is being drilled and to the gas content of the pore spaces: The rate of release of drilled gas into the annulus is likely to be small in relation to the rate of inflow in a kick situation. This produces very low gas/oil concentrations in the mud, if the gas dissolves, and those would produce low bubble point pressures.
3-8
HPHT Course - Section 3
Some typical drilled gas/oil concentrations are shown in FIG 3.5 below. Some extreme values for a drilled gas example may be: TVD ROP Mud Gas/oil Bubble pt Depth
= = = = = =
15,000 ft 100 ft/hr 15 ppg 10 SCF/bbl oil in mud 67 psig 86 ft to bubble point
Drilled Gas Concentration SCF/bbl Oil in Mud
FIG 3.5
15 15 ppg 4,000 ft 15 ppg 8,000 ft
10
15 ppg 15,000 ft
5
20
40
60
80
100
Penetration Rate ft/hr
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 the rate at which a reservoir flows, in a drilling situation, but some estimates can be made using a radial transient flow model and some typical values are shown on the graphs in FIG 3.6.
3-9
HPHT Course- Section 3
FIG 3.6
4000 Data: TVD = 16,000 ft K = 40 MD Ø = 25% Mud = 0.8 psi/ft BHT = 240°F Dia = 8.5 in ROP = 7.5 ft/hr
Gas Kick Inflow Rate SCF/min
3000
Gas SG = 0.60 2000 Gas SG = 0.65
Gas SG = 0.70
1000 Gas inflow rate at any other ROB, Rp is :Qgk = Graph Value x Rp Qgk = Graph Value x ––– SCF/min Qgk = Graph Value x 7.5
500
1000
1500
SIDPP - psia
If there is drilled gas plus influx flowing gas then the total gas production flow-rate will be Qdg + Qkg = Qg. However, as indicated above, the drilled gas rate is so small in relation to the influx flow-rate that it is reasonable to neglect it.
3 - 10
HPHT Course - Section 3
3.5 INFLUX TO PIT GAIN RATIO It is normal to assume, with water based muds, that the pit gain as measured for a 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 a simulated TVD of 20000 ft, 16840 psi and 350°F 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 the ratio: Influx volume/pit gain = 3.0/2.72 = 1.10 O’Bryan and Borgoyne in their paper “Swelling of Oil-Base Drilling Fluids Due to Dissolved Gas” (SPE Paper No 16676 Dallas Sept 1987) base a simple method (and approximate) for predicting this “expansion ratio” upon the behaviour of methane/diesel solutions. Typical graphs of the swelling of such solutions from 20,000 psia to bubble points at 100, 200, 300 and 400°F are given in the paper, and shown below in FIGS 3.7(a) and 3.7(b). FIG 3.7(a) T = 200 °F Oil = No.2 Diesel Gas = Methane
Po in tP re ss ur e
1.3
1.2
800 SCF /STB
Bu bb le
Volume Factor Bo, BBL/STB
1.4
600
1.1 400 200
1.0 0
Miscibility Pressure
0.9
0
2
4
6
8
10
12
14
16
18
20
Pressure (1000's psia)
3 - 11
HPHT Course- Section 3
FIG 3.7(b) T = 300 °F Oil = No.2 Diesel Gas = Methane Po in tP re ss ur e
1.3
1.2
Bu bb le
Volume Factor Bo, BBL/STB
1.4
600 SCF /STB
1.1
400 200
1.0
0
Miscibility Pressure
0.9
0
2
4
6
8
10
12
14
16
18
20
Pressure (1000's psia)
3.5.1 Worked Example The method for determining the influx multiplier, for a dissolved gas kick is shown below by means of worked example: A gas influx has entered a well while drilling ahead and the gas is believed to have dissolved in the oil-based mud. The following is the relevant data: TVD SIDPP Gas SG Gas Zbh SICP Pump o/p
= 15,000 ft = 700 psi = 0.65 (rel to air) = 1.740 = 810 psi = 7.8 bbl/min
Mud density = 16.3 ppg Pit gain = 7.5 bbl BHT = 200°F APL = 250 psi Oil vol fraction= 0.460
What would be an estimate for:
3 - 12
a)
The influx: pit gain multiplier.
b)
The bubble point pressure if the gas is released when the temperature is about 150°F.
c)
The depth at which the gas is released.
HPHT Course - Section 3
SOLUTION: PART (a) (i)
From the graph on FIG 3.6 the rate of gas inflow for the above conditions is 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
(iii)
= 2154/7.8 = 276 SCF/bbl mud.
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 200°F, as in FIG 3.8. FIG 3.8 1.4
T = 200 °F Oil = No.2 Diesel Gas = Methane
c = Bo = 0.9836
Po in tP re ss ur e
1.3
Bu bb le
1.2 d 1.1
Miscibility Pressure
Volume Factor Bo, BBL/STB
d = Bog = 1.123
800 SCF /STB
b 600 400 200
1.0 c
a
0
Pbp = 4444 psia 0.9
0
2
4
6
8
10
12
14
16
18
20
Pressure (1000's psia)
(v)
Enter the graph at a pressure of 13,679 psia and draw a line vertically up from this to cut the 600 SCF/bbl gas/oil line at point “b” and the zero concentration line at “a”. Draw horizontal lines from “b” and “a” to cut the end vertical axis (volume factors)
. (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 - 13
HPHT Course- Section 3
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 of undissolved gas (ie as if in a water based mud) from: 1,000 x 14.7 x Tbh x Zbh Vgf = ––––––––––––––––––––––––– 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 represented 1.75 x 7.5 = 13.1 bbl of free gas influx. PART (b) To estimate the bubble point pressure at 150°F, use the graphs in FIG 3.7 for 100 and 200°F at 600 SCF/bbl and interpolate between to get the Pbp value at 150°F, as follows: On the 200°F graph, Pbp at 600 SCF/bbl = 4444 psia On the 100°F graph, Pbp at 600 SCF/bbl = 3651 psia By interpolation at 150°F and 600 SCF/bbl, Pbp = 4048 psia = 4033 psig
3 - 14
HPHT Course - Section 3
Part (c). The pressure at the choke will stay almost constant while the gas remains in solution. 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, is less 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 case of a swabbed kick, with the pumps off, there will be only a small amount of mixing and the influx gas will not dissolve fully, at least until gas streaming causes sufficient mixing for this to occur. In the case of no mixing, the recorded trip tank gain will be approximately equal to the influx volume. The graphs shown in FIG 3.7 also show that the bubble point pressure reduces as the gas/oil concentration is reduced. This means that a small dissolved influx may not reach its bubble point pressure until it has passed through the choke. In a recent publication by Lindsay & White, the "influx volume/pit gain" ratio described above has been drawn in graphical form for an 88:12 OWR oil-based mud between 2,000 and 9,000 ft TVD. This is shown below in FIG 3.9. FIG 3.9
INFLUX : PIT GAIN VOLUME RATIO
EXTRA GAS HELD IN SOLUTION OBM COMPARED TO WBM FOR THE SAME PIT GAIN 4.0
3.5
3.0
2.5
2.0
1.5
1.0 1000
2000
3000
4000
5000
6000
7000
8000
9000
10000
BOTTOM HOLE PRESSURE (PSI)
3 - 15
HPHT Course- Section 3
3.6 REFERENCES FOR SECTION 3 1.
“Gas solubility in oil-based drilling fluids : Effects on kick detection.” By Thomas, Lea and Turek SPE Paper 11115 New Orleans Sept 1982
2.
“An experimental study of gas solubility in oil-based drilling fluids.” By O’Bryan, Burgoyne, Monger and Kopcso SPE Paper No 15414 : New Orleans Oct 1986.
3.
“The swelling of oil-based drilling fluids due to dissolved gas.” By O’Bryan and Burgoyne SPE Paper 16676 : Dallas Sept 1987.
4.
“The use of a gas kick simulator to produce an oil-based mud training package.” By Lyndsay and White 1993 IADC European Well Control Forum : Paris June 1993..
3 - 16
HPHT Course - Section 3
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 between the saturation concentration, the temperature and the bubble point pressure, as given by:
Rso =
[ ] P ––––– a.Tb
n [Eqn 3.31]
Where: Rso P T a b n
= = = = = =
saturation gas/liquid concentration, SCF/bbl saturation, or bubble point pressure, psia mixture temperature °R a constant = 1.922 for hydrocarbon gas in base oil a constant = 0.2552 for hydrocarbon gas in base oil an index = 1.24 - 1.08 x SGg + 1.16 x SGg2, for hydrocarbon gas in base oil SGg = gas specific gravity, relative to air. From this it can thus be shown that the bubble point pressure for a specific gas/liquid concentration of Rgo is: Pb
= a.Tb . Rgo (1/n)
[Eqn 3.32]
3.4 DRILLED GAS AND KICK GAS The rate at which drilled gas is released into the mud in the annulus is related to the volumetric rate at which the rock is being drilled and to the gas content of the pore spaces: P b x d 2 x f x Sg x Rp Qgd = –––––––––––––––––––– 310.97 x Zb x Tb Where: Pb d f Sg Rp Zb Tb
= = = = = = =
SCF/min
[Eqn 3.41]
bottom hole pressure, psia. bit diameter, in. rock porosity, decimal. gas saturation fraction of the pores, decimal. rate of drilling penetration, ft/hr. gas Z value at bottom hole conditions. bottom hole temperature, °R.
3 - 17
HPHT Course- Section 3
The radial flow rate of kick for a uniform thickness transient gas reservoir is given by: k x h x (Pf2 - Pb2) Qgk = –––––––––––––––––––––––– MSCF/day 1424 x Pd x Zb x Tb x µ
[Eqn 3.42]
Where: Pb = the dynamic value of the bottom hole pressure, psia. k = formation permeability, milli d’Arcy units. h = thickness of permeable rock exposed or drilled in a known or assumed time interval, ft. µ = 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 µ 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: y µ = 0.0001 x K1 x e (XÏg )
[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 Ïg = gas SG (Relative to water) = 0.0014926.Pf.M/(Zb.Tb)
3 - 18
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4. RIG EQUIPMENT SUMMARY
D RI L LI N G S
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HPHT Course - Section 4 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 safe valves on a subsea stack, with the outer valve closing first, should be used to limit the effects of cutting out of the gates. Also consideration should be given to the closure mechanism and whether additional hydraulic assist should be incorporated in order to increase closing force. Flexible Hoses Strict attention must be given to the flexible hoses to ensure that they are designed for appropriate temperatures, pressures and well fluids. The hose should be checked to ensure that it is the correct length for the given stack. BOP Stack Outlets There should be a minimum of two outlets to the choke manifold below the upper set of pipe rams on a subsea stack. Hang Off Rams The upper pipe rams should be positioned in the stack so that they can be used to hang off the drillstring with the blind/shear rams closing above. Chokes The choke manifold should be equipped with two remote hydraulic chokes and 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 capacity of gas and mud. Design will include vessel working pressure, sizing of vent lines, length of mud seal, retention time, and control system. The degasser should be designed, constructed, inspected, tested and stamped in accordance with ASTM VIII Division 2 - Boiler and pressure vessel code or similar pressure vessel code. MGS Instrumentation The MGS should be instrumented and controlled so that the working pressure is not exceeded. MGS Bypass An alternative method to dispose of produced fluids must be provided in the event the capacity of the MGS is exceeded. Glycol Injection System A system for injection of glycol upstream of the choke to prevent hydrate formation should be available. 4-1
HPHT Course - Section 4
General Layout 13 5/8" - 15,000 psi BOP Stack FIG. 1
4-2
HPHT Course - Section 4
WELL CONTROL AND SURFACE EQUIPMENT Temperature Limitations and Pressure Ratings The following limitations apply to this equipment:
Equipment
Continuous Service Rating(1 Month)
Emergency Service 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 KILL VALVES
250
350
15,000
SHEAR RAMS
190
N/A
15,000
RAM DOOR SEALS & RAM SHAFT SEALS
250
350
15,000
ANNULARS
170
225
5,000/ 10,000
FLEXIBLE HOSE
212
320
15,000
CHOKE AND KILL LINE STAB SEALS
250
350
15,000
CHOKE MANIFOLD VALVES, UPSTREAM OF THE BUFFER TANK
250
350
15,000
CHOKE MANIFOLD VALVES, DOWNSTREAM OF THE BUFFER TANK
250
350
5,000
CHOKE MANIFOLD OVERBOARD PIPEWORK
250
350
5,000
SLIP JOINT - CHOKE
250
350
15,000
KILL BOX SAVER SUB
4-3
HPHT Course - Section 4 MUD/GAS SEPARATOR
FIG. 2
10" VENT UP DERRICK
HOT MUD RECIRCULATING LINE
6" VENT
28' - 8 1/2" ABOVE MAIN DECK 10" DOWN TO SHAKER HEADER BOX
THERMO-COUPLE AND PRESSURE TRANSDUCER FLANGE
FLOW LINE
18"
BY-PASS PRESSURE (psi)
THROUGHPUT PERFORMANCE AT 60 DEG F.
50.0
30
47.6
28
45.2
26
42.8
24
40.4
22
37.9 35.5
AD
O NL
18
N
GI
U
16
I
14
H
IT
12
AD
S 6P
R MA
W
O NL
10
U
33.0 30.4 27.8
22.4 19.5
6
16.4
4
13.0
2
8.9 8
20" PIPE X - STG
25.1
8
0
10" PIPE Sch. 80 INSIDE
6" TO TRIP TANK
9 10 11 12 13 14 15 16 17 18 19 20 FLUID DENSITY Lb/gal
MUD GAS SEPARATOR FLOW CAPACITY CURVE
4-4
GAS FLOW (mm scf/day)
32
20
10" CLEAROUT
27' - 5"
24' - 4"
3', 1"
10" Sch. 80 PIPE
MUD HEAD
HPHT Course - Section 4
SUBSEA BOP SYSTEM
FIG. 3
VENT TO TOP OF DERRICK 10" VENT LINE
MGS PRESSURE SENSOR
8 FROM C & K MANIFOLD, 4" PIPE
36" DIAMETER MUD - GAS SEPERATOR
DOWNSTREAM CHOKE TEMP. SENSOR
DRILL FLOOR LEVEL
REMOTELY ACTUATED VALVES
6
TO MUD/GAS SEPARATOR
TO SHALE SHAKER
MANUAL CHOKE
REMOTE CHOKE
MANUAL CHOKE
5
REMOTE CHOKE TO PORT FLARE LINE
MAIN DECK LEVEL
DIP TUBE PRESSURE SENSOR
6 Meters TO STARBOARD FLARE LINE
7 UPSTREAM KILL LINE TEMP. SENSOR
4
DATA MONITORING SYSTEM AND BYPASS CONTROL UNIT STBD
MGS
PORT
DIP TUBE PRESSURE
7
OPEN CLOSED
OPEN CLOSED
PRESSURE
8
TEMP.
GLYCOL INJECTION POINT
TO SHALE SHAKER
BOP
MGS OPEN CLOSED
DOWNSTREAM CHOKE TEMP. SENSOR
TO CEMENT UNIT MUD PUMPS
1,2
UPSTREAM CHOKE LINE
KILL LINE
CHOKE LINE
3
TEMP.
UPSTREAM CHOKE TEMP. SENSOR
3
DECK LEVEL
UPSTREAM KILL LINE TEMP.
VALVE STATUS ALARM
4
DOWNSTREAM CHOKE TEMP.
REMOTE CHOKE AREA
5,6
SEA LEVEL
SUBSEA TEMP. SENSOR
1
2 FLEX JOINT ANNULAR PREVENTER
REMOTE CHOKE CONTROL PANEL
DRILLPIPE PRESSURE
ANNULUS PRESSURE
SUBSEA TEMP. SENSOR
CHOKE POSITION INDICATOR
H-4 CONNECTOR KILL LINE
CHOKE LINE
ANNULAR PREVENTER
CHOKE CONTROL
SHEAR RAMS 5" RAMS
B
B1
A
A1
VARIABLE RAMS
C
SEABED
C1
5" RAMS
H-4 CONNECTOR
4-5
HPHT Course - Section 4
SURFACE BOP SYSTEM
FIG. 4
STARBOARD
PORT
REMOTE CHOKE CONTROL PANEL VENT LINE TO DERRICK DRILLPIPE PRESSURE
ANNULUS PRESSURE
CHOKE POSITION INDICATOR
MUD GAS SEPARATOR CHOKE CONTROL
MGS
OPEN CLOSED
STBD
OPEN CLOSED
PORT
OPEN CLOSED
RETURN TO MUD SHAKERS
MGS
BOP
PRESSURE
TEMPERATURE
OVERBOARD LINE
PRESSURE/TEMP. SENSOR
TO STARBOARD/PORT VALVES
TEMPERATURE
TO MGS VALVE ALARM
TO BOP TEMP. SENSOR
VALVE STATUS
MUD GAS SEPARATOR BUFFER CHAMBER
REMOTE CHOKE/MONITORING AND BYPASS CONTROL UNIT
MANUAL CHOKE REMOTE CHOKE
REMOTE CHOKE
CHOKE/KILL MANIFOLD
MUD MANIFOLD
BYPASS
CMT UNIT CHOKE LINE ANNULAR
RAM HCR VALVE
KILL LINE
RAM RAM RAM
15 M BOP STACK
4-6
HCR VALVE
GLYCOL INJECTION
HPHT Course - Section 4
TEMPERATURE MONITORING EQUIPMENT A temperature monitoring system must be in place to ensure that the continuous temperature rating of the elastomer system is not exceeded during drilling, well control operations and well testing. Temperatures should be monitored at the mud return flowline, at the chokeline upstream of the choke, and at the well test flowline upstream of all chokes.
KILL SYSTEM Kill Pump A 15,000 psi kill pump capable of slow circulation rates +/- 0.5 bbls/min should be available. There should be a good communications link between the kill pump and rig floor. Consideration should be given to equipping the kill pump for remote operations from the rig floor. There should also be a choke on the bleed down line to reduce erosion of plug type valves when bleeding off pressure. High Pressure Line High pressure line from the kill pump to the rig floor with a circulating head and flexible hose or chicksans ready for quick make up should be available.
DRILLSTRING BACK PRESSURE VALVE A means of avoiding back flow up the drill pipe should be incorporated by either using a sub for a drop in back pressure valve or by using a float valve in the BHA before drilling through the transition zone from normal to abnormally high pressure, commonly reached below the 13-3/8" casing point. Drillstring Circulating Capability A high pressure lubricator and drill pipe perforation system or drillstring circulating sub should be available while drilling below deep intermediate casing.
PIT LEVEL INDICATOR Minimum pit level indicator requirements are 2 pit level indicators per active tank for semi submersibles. All tanks should be monitored and include a pit volume totaliser.
4-7
• ABE
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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
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5. SURFACE GAS HANDLING CAPACITIES and PROCEDURE FOR HPHT WELLS
D RI L LI N G S
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HPHT Course - Section 5
5.1 INTRODUCTION : GAS EXPANSION In any well control operation in which an influx is circulated out of the well via the choke, the BASIC OBJECTIVE is to hold bottom hole pressure constant at all stages of the process. This is usually achieved by controlling the drillpipe pressure at constant pump speed (ie at constant slow circulation rate), according to a predetermined schedule of pressure and strokes (via the Driller’s, W & W or Concurrent methods). As long as the pump speed is held constant, the means of controlling the drillpipe pressure is by adjusting the opening at the hydraulic choke at the drillfloor choke manifold. As indicated in Section 2, gas expansion ratios increase with increase in bottom hole pressure. A gas expansion factor is used to convert from a nondimensional ratio to the units which are commonly used ie SCF/bbl,as shown below : Vsc 198.4 x Pbh ––– = –––––––––– Vbh Zbh x Tbh Where Pbh Vbh Tbh Zbh Vsc Vsc/Vbh
= = = = = =
SCF
[ Eqn 5.1.1 ]
bottom hole pressure in psia. free gas influx volume at bottom hole conditions in bbl. gas bottom hole temperature in °R. gas compressibilty factor at BH conditions. free gas volume at standard conditions, SCF. 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-based mud with a dissolved gas kick, the pit gain correction factor should be introduced. FIG 5.1b
5°
F/
10
0f t
FIG 5.1a
ft 00 00 ft .2 5° F/ 1
:1 Vs 198.6 Pbh 1 ––– = ––––––––– = ––– Vbh Zbh.Tbh Bg 2000
2100
Gas SG = 0.70 (rel to air) Vs 198.6.Pbh 1 ––– = ––––––––– = ––– Vbh Zbh.Tbh Bg 2000
14
5-2
280 °F 300 °F 32 0 °F 350 °F
Gas Expansion Factor SCF/bbl (1/BG)
.3 0 :1 i/ft ps
i/ft ps Gas SG = 0.70 (rel to air) Surface Temp = 100°F
250° F
°F /1
ft : s i/ 0.9 0p
0.8 5 2100
0.8 0
Gas Expansion Factor SCF/bbl (1/BG)
2200
1 .3
2200
15
16
17
18
19
Well TVD - 10005 ft
20
11
12
13
14
15
16
17
Bottom Hole pressure - 10005 psia
18
HPHT Course - Section 5
The graphs in FIGS 5.1(a) and (b) indicate the relative values of such expansion factors at constant mud weights against depth (FIG 5.1a) and at constant 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 and a temperature gradient of 1.35°F/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 1.35°F/100 ft temperature gradient, 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 that the gas production rate calculated as above does not exceed the handling capacity 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 that the choke manifold should be designed to provide the following principal features: (a)
adequate pressure integrity for the highest anticipated pressures. This will be at least 15000 psi with test pressures of 22500 psi for HP wells.
(b)
adequate temperature range capability without loss of the main physical properties. This will be at least 250°F for continuous operation and 320°F for 1 hour. Sub-zero temperatures on the downstream side of the chokes will 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 be injected to suppress hydrate formation.
5-3
HPHT Course - Section 5
(e)
An adequate buffer chamber between the downstream side of the chokes and the mud gas separator, to dampen out pressure surges and accommodate slugs of mud/gas.
(f)
A means of by-passing the mud gas separator, rapidly, in the event of the blow-down pressure rating of the MGS being approached, so that the pressure in the MGS can be reduced and the well can be shut in safely.
FIG 5.2
Glycol Injection Point CHICKSAN CONNECTION
TO KILL STANDPIPE IN DERRICK TO 3" DST STANDPIPE IN DERRICK
CHOKE LINE
FROM MUD MANIFOLD
REMOTE CHOKE MANUAL CHOKE CHICKSAN CONNECTION
MANUAL CHOKE
TO MANUAL CHOKE STRIPPING TANK REMOTE CHOKE
FROM CEMENT PUMP
TO 4:1 DEBOOSTER AND CHICKSAN CONNECTION
KILL LINE
BUFFE
RTANK
TO PORT FLAREBOOM TO STARBOARD FLAREBOOM
KILL PUMP TO KILL LINE (CHOKE & KILL MANIFOLD)
TO CHOKE LINE (CHOKE & KILL MANIFOLD)
POORBOY DEGASSER
CHOKE LINE
18 - 21ft SEAL
5-4
TRIP TANK
SENSORS IN MUD PITROOM
KILL LINE
HPHT Course - Section 5
In the manifold indicated, all equipment from the 3" choke line and HCR valves through the various choke valves to the entry to the buffer chamber is rated at 15000 psi working pressure. All valve stem seals using elastomers should have those rated as for any elastomers connected to the BOP stack. The buffer chamber and the lines and valves leading into it are rated at 10000 psi, whilst the lines downstream of the buffer chamber leading to the mud gas separator are 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 the flow through those is either like flow through a nozzle or flow through a sharp-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 gases through an orifice or nozzle is more complex than that of a liquid. There is also a "critical pressure ratio" for the flow of gases through a nozzle or orifice and this means that if the downstream pressure is less than that specified by the critical pressure ratio, then the nozzle or orifice flow is said to be “choked”, ie it is not capable of flowing more fluid regardless of how low the downstream pressure is, unless the upstream pressure is raised or the orifice size is increased. For natural gases the critical pressure ratio is about 0.544. In such cases of choked flow, the flow through the orifice is directly dependent on the upstream pressure.
5-5
HPHT Course - Section 5
The gas flowrate through an orifice in such a case can be calculated by a formula suggested by the US Bureau of Mines for “Prover Orifices”. This is detailed in the appendix to this section as:Qg = 399.75 x P1 x d2 x E x √(1/T1/Zav/SGg) Where
d P1 T1 SGg Zav Qg
= = = = = =
[Eqn 5.2.1]
effective diameter of the choke orifice, in. upstream pressure at the choke, psia. upstream temperature °R. gas specific gravity, relative to air. a weighted average Z value for the gas. gas flow through the orifice, MSCF/D.
For a gas of SG 0.65 and upstream temperature of 120°F and for an orifice with a 1" diameter in a 3" diameter choke line, the gas flowrates are: Pressure psi
Flowrate SCF/min
Flowrate MMSCF/Day
500 1000 1500 2000 4000
7424 14969 22816 30910 63222
10.691 21.555 32.855 44.509 91.039
Because gases have very low densities and viscosities, compared to liquids, a given pressure drop across a choke valve will flow much larger volumes of gas than mud or hydrocarbon liquids. However, if the choke orifice or nozzle is “Flow Choked” as described above, the upstream pressure will be self adjusting to allow the appropriate gas flowrate for the actual choke aperture. This means that when gas starts to flow through the choke, large and rapid changes in choke pressure can occur, causing difficulty in maintaining constant bottom hole pressure.
5-6
HPHT Course - Section 5
5.3 MUD GAS SEPARATORS Experiences in the early 1980’s with influxes of high pressure gas in deep wells indicated that in some cases the capacity ratings of the surface handling equipment, 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 the well, at the “normal” slow circulating rates, although influx volumes and shut-in pressures indicated that anticipated maximum well-head pressures could be safely accommodated. Typical mud gas separators in use at that time are shown overleaf in FIG 5.4 and are vertical in design. The liquid seal was achieved by either a U-tube or a dip-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" Derrick Vent
6" Derrick Vent
6" Derrick Vent 2" Siphon Breaker
Siphon Breaker Usually Fitted
Inlet
Inlet
Inlet
Dip Tube Height
Drain
Shaker Trough
TRIP-TANK MOUNTED
API
U-TUBE DESIGN
At present there is no standard which is specifically derived for mud gas separators. The current standard in use is that of API 12J “Specification of Oil and 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 and even hydrocarbon liquid or condensate.
(c)
The fluid properties of gas-cut mud. 5-7
HPHT Course - Section 5
(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 in transient 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
➝
➝
PRESSURE SENSOR/GAUGE "GAS"
➝ FROM BUFFER TANK
➝
8" TO 12" DIA VENT PIPE TO DERRICK
➝
MGS CHAMBER 30" TO 48" DIA
BAFFLE PLATES
➝
PRESSURE SENSOR
5-8
➝
DIP OR SEAL TUBE
➝
"LIQUID" POOL GAS/CUT
➝
h
SHAKER PIT
HPHT Course - Section 5
Generally there are 2 separate criteria of MGS performance ie:(a) (b)
Separation Capacity. Blowdown Capacity.
If the MGS is correctly proportioned and designed, it is probable that the blowdown 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 governed mainly by an application of STOKE’S LAW. This is used to determine the maximum superficial upward gas velocity to allow separation of gas and liquid droplets. This is then used to calculate the volumetric rate of gas flow through the MGS vessel, as indicated in the equation below: Sc = 0.7854 x D2 x A x K x √[(Dl - Dg)/Dg] Where Sc D A Dl Dg K
= = = = = =
[Eqn 5.3.1]
separation capacity of the MGS in SCFD. MGF vessel internal diameter, in ft. a constant of conversion = 86400. density of the liquid phase. density of the gas phase (in the same units as Dl). a constant, 0.12 to 0.24 for vertical vessels up to 5 ft deep, or 0.18 to 0.35 for vessels up to 10 ft deep.
The separation capacity is defined as the volumetric gas flowrate through a MGS which will permit venting of gas with a limiting liquid droplet size at the exhaust. It is likely that the actual separation capacity of a MGS will be less than that predicted by the above formula due to: -
Viscosity and gel characteristics of the liquid. Retention time within the MGS. Liquid droplet particle size. Volumetric throughput rate.
Typical retention times for vertical MGS vessels are 1 to 4 minutes. The separation capacities for a range of vertical separators for different densities of liquid and for a gas of 0.7 SG (relative to air) at 60°F are shown in FIG 5.6 (a) and (b) at pressures of 5 psig and 9 psig within the MGS vessels. Those are based upon Eqn 5.3.1.
5-9
HPHT Course - Section 5
FIG 5.6a 4.0 ft dia
Separation Capacity MMSCF/Day
12
10
3.5 ft dia
8
3.0 ft dia 6
2.5 ft dia 4
Gas SG = 0.70 Pressure inside MGS = 5.0 psig MGS Temp = 60°F
2
4
6
8
10
12
14
16
18
20
Liquid Density in MGS (ppg)
FIG 5.6b 12
Separation Capacity MMSCF/Day
4.0 ft dia 10
3.5 ft dia 8
3.0 ft dia 6
2.5 ft dia 4
Gas SG = 0.70 Pressure inside MGS = 9.0 psig MGS Temp = 60°F
2
4
6
8
10
12
14
16
Liquid Density in MGS (ppg)
5 - 10
18
20
HPHT Course - Section 5
5.3.2 Blowdown Capacity The blowdown capacity of a MGS is that flowrate which is sufficient to cause enough internal pressure to blow out the liquid seal at the base of the MGS. It can be shown that the pressure within the MGS, due to vent line friction is related to the vent line diameter by: (Pi2 - 14.72) a √Dv5 Where :
Pi Dv
= =
[Eqn 5.3.21]
internal pressure, psia, in the MGS. internal diameter of the vent line, inches.
The flowrate into the MGS governs the velocity in the vent line and thus the friction pressure loss of the vent line. The Weymouth formula (Given in the appendix to this section) is commonly used to calculate the pressure loss along the vent line for a range of gas gravities. Generally the heavier the gas, the greater will be the pressure loss and the blowdown pressure for a particular gas flowrate. For an 8" vent line with an equivalent length of 250 ft, the blowdown pressures for a range of flowrates are shown in FIG 5.7. FIG 5.7 250 ft long
220 ft
180 ft
Pressure Inside MGS (psig)
9
8
7
6
Gas SG = 0.70 ID = 7.625" (8" nominal) Temp = 60°F
5
8
10
12
14
16
18
Gas Flowrate MMSCF/Day
The blowdown pressure inside the MGS is also related to the hydrostatic pressure at the base of the liquid seal dip tube or U-tube by the formula below: Pb = Sf x Ldt x Gl psi Where
Sf Gl Ldt Pb
= = = =
[Eqn 5.3.22]
a safety factor ( usually about 0.8). liquid gradient in dip tube, psi/ft. length of dip-tube column, ft. blowdown pressure inside the MGS vessel, psig 5 - 11
HPHT Course - Section 5
It cannot be assumed that the liquid gradient in the dip tube is that of the mud. At best, the mud gradient is likely to be heavily gas-cut. At worst it is likely to be gas-cut condensate liquid, with a gradient of 0.3 psi/ft. This is used in worstcase scenario estimates. For a dip-tube of 18 ft and 0.3 psi/ft liquid gradient, the maximum tolerable blowdown pressure inside the MGS would then be 4.8 psig. If the blowdown capacity exceeds the separation capacity, then this means that liquid droplets will be carried over into the vent line. 5.3.3 Optimum slow circulation rate In normal pressure control operations, it is common to operate the mud pumps at a slow circulation rate which is between 38 and 50% of the normal circulation rate for drilling. This is regarded, from bitter experience, as being much too arbitrary for the correct operation of the MGS in HPHT wells with gas kicks. From the gas expansion factor, Eqn 5.1.1, the gas formation volume factor can be calculated from: Bg = 1/Vsc
bbl/SCF
It can then be shown that the correct slow circulating mud rate, Scr, for a MGS with a specific 10 MMSCF/Day separating capacity is given by: Scr = 6944 x Bg bbl/min.
[Eqn 5.3.3.1]
Or, for a MGS in which the separation capacity is Cmgs MMSCF/Day, then the optimum slow circulation rate will be: Scr = 694.4 x Cmgs x Bg bbl/min Where
Cmgs = Scr =
[Eqn 5.3.3.2]
separator capacity (separation criteria) in MMSCF/D. optimum mud pumping rate, bbl/min.
This is shown in graphical form for a 10 MMSCF/Day separating capacity in FIG 5.8 overleaf.
5 - 12
HPHT Course - Section 5
FIG 5.8 4.0
Maximum Pump Rates for MGS Separator Capacity : 10 MMSCFD Gas SG = 0.60
Slow Circulation Rate bbl/min
3.5
BHT = 350°F 3.0
BHT = 250°F
2.5
Pump Rate to use = Graph value x MGS Capacity (106 SCFD) Pump Rate to use = ––––––––––––––––––––––––––––––––– bbl/min Pump (Maxm)to use = Graph value x MG10 2.0 10000
12000
14000
16000
18000
20000
Bottom Hole Pressure (psig)
This may produce Scr values which are significantly lower than those which may sustainable by a normal triplex mud pump. In such a case a special kill pump or a cement pump may be used. For such a case, the correct slow circulating pressure (assuming FCP has been reached) will be: FCP(opt) = FCP x (Q2/Q1)2 Where
Q2 Q1
= =
FCP(opt) =
[Eqn 5.3.33]
Optimum slow circulating flowrate for MGS, bbl/min. Normal slow circulating flowrate, bbl/min, at which the FCP is calculated. the FCP at the optimum slow circulating rate Q2
5.3.4 Worked Example The following data applies to a gas influx taken while drilling a gas condensate zone in a HPHT well with a water based mud. Influx volume Mud gradient BH temperature Gas Z value at BHT Vent line length Liquid seal depth
= = = = = =
12 bbl 0.85 psi/ft 308°F 1.717 180 ft 18 ft.
TVD SIDPP Gas SG MGS dia Vent dia
= = = = =
16000 ft. 650 psi. 0.7 3.5 ft. 8" (Nominal)
5 - 13
HPHT Course - Section 5
Slow circulating pressure loss at 30 SPM (3.51bbl/min) is 680 psi. It is estimated that the gradient of the liquid in the MGS seal will be 0.5 psi/ft when the gas is flowing through the MGS. Determine the following: (a)
The overall gas expansion factor from bottom hole to standard surface conditions.
(b)
The estimated pressure inside the MGS.
(c)
The estimated separating capacity of the MGS.
(d)
The optimum slow circulating rate for adequate separation.
(e)
The estimated blowdown capacity of the vent line.
(f)
The safety margin between blowdown and separation at the optimum SC rate.
(g)
The slow circulation pressure at the optimum slow circulating rate.
SOLUTION (a)
The overall gas expansion factor is calculated from Eqn 5.1.1: Vsc ––– = Vbh
198.4 x Pbh –––––––––– Zbh x Tbh
The bottom hole pressure at shut-in is Pbh: Pbh = Gm x TVD + SIDPP + 15 = 0.85 x 16000 + 650 +15 = 14265 psia. The bottom hole temperature at shut-in is Tbh: Tbh = 300 + 460 = 760 °R ( or °F absolute), hence: 198.4 x 14265 Vsc ––– = –––––––––––––– = 2168.9 SCF/bbl = 1/Bg Vbh 1.717 x 760
5 - 14
HPHT Course - Section 5
(b)
The pressure inside the MGS = G(liq) x Depth of seal Hence Pmgs = 0.5 x 18 = 9.0 psig. (Estimated)
(c)
The separating capacity for a 3.5 ft ID MGS at 9 psig can be obtained from the graphs in FIG 5.6(b). The estimated liquid seal density is 0.5/0.052 = 9.62 ppg. At this density the separating capacity is = 5.75 MMSCF/Day.
(d)
The optimum slow circulating speed is calculated from Equation 5.3.3.2 or from the graph FIG 5.8. By calculation: Scr (opt) = 694.4 x 5.75 / 2168.9 = 1.84 bbl/min.
(e)
The blowdown capacity of the 8" vent line at a pressure of 9 psig in the MGS is taken from the graph on FIG 5.7: At 9 psig, blowdown for 0.7 SG gas in an 8" x 180 ft vent line is about 18.25 MMSCF/day.
(f)
Hence the safety margin between separation and blowdown is about 18.25 - 5.75 = 12.5 MMSCF/day.
(g)
The slow circulating pressure at this reduced rate will be: Pscr = 680 x(1.84/3.51)2 = 188 psi
It should be noted that the selected optimum slow circulation rate for the operation of the MGS need not be used from the start of the circulation process. Low and Jansen suggest that the circulation process should initially be started as quickly as possible with as high a circulation rate as is feasible for the safe circulation past the casing shoe. They then indicate that this circulation should be stopped when it is estimated that the influx (or dispersed kick) is about 4000 ft below the surface and the well then shut in. Thereafter circulation should be re-established, possibly with a kill pump, at the optimum slow circulation rate and appropriate DP circulating pressure until the influx is evacuated from the well. In using this procedure, it must be stressed that appropriate allowances should be made for rapid migration rates of free gas or dissolved kicks so that an accurate estimate of time or strokes to get the influx to a position about 4000 ft below the surface can be made.
5 - 15
HPHT Course - Section 5
5.4 BOP AND CHOKE LINE FLOWING TEMPERATURES The temperatures at the BOP and choke line are likely to be of importance in a well control operation from 2 aspects: (a)
If the well is flowing rapidly, the temperature at sub-sea flexible elements may be near to their operational limit.
(b)
In a sub-sea BOP stack system, there will be a cooling effect between the BOP and the surface choke manifold. The expansion of gas across the choke may then lead to downstream temperatures which are low enough to cause hydrates to form.
Computer model predictions of both the sub-sea BOP temperature and surface choke temperatures (produced by TEMPEST program) for a deep HPHT well for various uncontrolled flowrates through the choke are shown in FIG 5.9. In a normal well control kill operation it is estimated that the SS BOP temperature would be about 250°F. FIG 5.9 300
250
Temperature at Sub-Sea BOP °F
Predicted BOP Temp °F 200
150
Predicted Surface Choke Temp °F 100
B.H. Temp = 350°F Water Depth = 300 ft B.H. Press = 14000 psi 50
20
40
60
80
100
120
Gas Flowrate MMSCF/Day
5 - 16
140
160
HPHT Course - Section 5
At special slow circulation rates, other computer simulations indicate that there is a cooling effect from the SS BOP up to the choke of between 12°F and 48°F, as shown in FIG 5.10, for 8.375 - 8.5" open hole sections. FIG 5.10
8 3/8" Hole Section 140
130
TEMPERATURE (°F)
120
110
100
90
80
70 0
0.5
1.0
1.5
2.0
2.5
MUD FLOW RATE (bpm)
110
120
130
140
147
Mud Temperature at BOP (°F)
5 - 17
HPHT Course - Section 5
5.5 FORMATION AND PREVENTION OF HYDRATES Hydrates are ice-like solids which are formed when gases are flowing in the presence of small quantities of water vapour. The temperatures at which hydrates can form may be well above the temperature at which pure ice would normally be formed, particularly at pressures above atmospheric. A typical set of graphs showing the temperatures and pressures at which hydrates can form in hydrocarbon gas-flow situations is shown in FIG 5.11. If a pressure/temperature plot for a particular gas is below the line for that gas, then hydrates will form. FIG 5.11 Hydrate-forming conditions for natural gases with various gravities. 6000
4000 3000
2000
Pressure for hydrate formation (psia)
1500
1000 800
e
600
an
h et
M
400
s
300
ty
ga
vi
200
6
0.
150
a gr
7 0. 8 0. 9 0.
100 80 60
0
1. 40
30
40
50
60
Temperature (°F)
5 - 18
70
80
90
HPHT Course - Section 5
Hydrates form as small lattices of water with interstices which contain gases. The water forms an ice with molecules of gas locked into the frozen solid lattice. Those can build up into large pieces of solid hydrate at bends or restrictions, such as chokes or other valves. See FIG 5.12. FIG 5.12
Solid Hydrate Build-up
Gas + Water (Vapour)
When hydrates form, the gas becomes “locked” into the solid at the local pressure. It is estimated that 1 cu ft of hydrate may hold the equivalent of 170 SCF compressed gas. This can be released when the hydrate is melted by the application of heat. 5.5.1 Expansion and Cooling Effect Generally any source of sudden expansion of a gas can cause a reduction of temperature. This is the Joule-Thomson effect, as shown in FIG 5.13. It is estimated that for a hydrocarbon gas the Joule-Thomson cooling effect is about 30°F per 1000 psi drop across an orifice or choke. This agrees with the pressure/temperature modelling graph in FIG 5.14.
h - Total Heat of enthalpy
FIG 5.13
Lines of Constant Temp.
T2 2
Expansion
1
T1 > T2
Pressure
5 - 19
HPHT Course - Section 5
FIG 5.14
UPSTREAM PRESSURE (psia)
4000
3000
2000
1000
-72
0 -80
-60
-40
-20
0
DOWNSTREAM TEMPERATURE (Deg F) Upstream Temperature = 46 deg F Downstream Pressure = 24.7 psia
Once hydrates have formed they may lead to complete plugging of chokes, fail-safe valves, choke lines and expansion points at entry to the MGS. It is normal to try to prevent hydrates from forming by the injection of a suppressant at the upstream side of the choke or at the BOP, on the occasions when hydrate formation is likely. To predict whether or not hydrates are likely to form, a graph such as that shown in FIG 5.11, may be used, for gas with the appropriate SG.
5 - 20
HPHT Course - Section 5
5.5.2 Worked Example: Prediction of hydrate formation possibility Mud/gas temperature at BOP Slow circulation rate Upstream choke pressure Hole diameter
= = = =
130°F 2 bbl/min. 2500 psia. 8.375".
Question Estimate whether or not hydrates are likely to form downstream of the choke, without glycol injection. Solution (a)
From FIG 5.10, at a BOP temperature of 130°F and a slow circulation rate of 2 bbl/min, the estimated upstream choke temperature will be about 115°F.
(b)
Refer to graph FIG 5.13. This graph is based on an upstream temperature of 43°F, but it is assumed that the same degree of colling due to expansion across the choke takes place, even it the choke upstream temperature is higher. From the graph, for an expansion from 2500 psia, the estimated down stream temperature would be -67°F. Thus the cooling or drop in temperature through the choke would be : δT = 46 - (-67) = 113°F. Thus, for an upstream temperature of 115°F at 2500 psi, the downstream temperature would be about 115 - 113 = 2°F at a pressure of about 35 to 40 psia. This is well into the potential hydrate-forming zone.
5 - 21
HPHT Course - Section 5
5.5.3 Suppression and Removal of Hydrates Prevention of hydrate formation is always regarded as the preferential action. Monoethylene glycol is the most common suppressant and it has a freezing point of 8.6°F (-13°C). Some information about other suppressants is given in TABLE 5.14. It should be noted that it is the water-vapour associated with the gas which has to be inhibited, rather than the whole volume of water in the mud. It is common in HPHT wells to make provision for the injection of glycol hydrate suppressant at a point into the BOP upstream of the inner choke line valves and upstream of the choke at the choke manifold. This is done by a glycol injection pump which can deliver at a pressure up to the rated pressure of the choke magnifold. The injection is started at a point when the gas influx is some depth below the BOP, such as 1500 to 2000 ft. The minimum injection rate is about .05 gpm but should be increased as necessary. TABLE 5.14 Property
Ethylene Glycol
Diethylene Triethylene Glycol Glycol
Methanol
Molecular wt.
62.1
106.1
150.2
32.04
SG at 77°F
1.11
1.113
1.119
0.77
Boiling pt. at 14.7psia °F
387
473
546
148
Freezing pt.°F
8.6
17.6
19.4
-143
Flash pt. °F
241
280
320
54
LEL %
3.2
N/A
0.9
6.0
Toxic
Yes
Yes
No
Yes
If hydrates have formed and plugged the lines, the well must be properly shut in and steps taken to melt the hydrate plug. Such steps may be:
5 - 22
(a)
Steam or hot liquid jets directed onto the external surfaces of the affected areas.
(b)
Circulation of heated mud into the MGS, if hydrates are forming there.
(c)
The injection of small quantities of methanol into the area upstream and downstream of the hydrate plug. Methanol has a freezing temperature of -143°F.
HPHT Course - Section 5
References for Section 5 1.
“Well Control When Drilling with Oil-Based Muds - Recent British Experiences in Deep Offshore Wells.” by E.B.Turner: Offshore Technology Report OTH 86 260 HM Stationery Office, London 1986.
2.
“Drilling and Control Aspects of High Pressure Deep Wells.” by J.M Prieur: SPE Paper 19245 :1989 SPE Offshore Europe Conference, Aberdeen.
3.
“A Method for Handling Gas Kicks Safely in High Pressure Wells.” by E.Low and C. Jansen: JPT June 1993 pp 570 - 575.
4.
“Practical Natural Gas Engineering” by R.V.Smith. PennWell Books.
5.
“Orifice Metering of Natural Gas” American Gas Association, Report No.3 1955.
6.
“Applied Drilling Engineering - Chapter 4” by Bourgoyne, Chenevert, Millheim and Young: SPE Textbook Series Vol 2. 1986
5 - 23
HPHT Course - Section 5
APPENDIX TO SECTION 3 : FORMULAS. 5.6 STEADY FLOW ENERGY EQUATION By “steady flow” it is intended that the mass flowrate between stations 1 and 2 in a “duct system” does not change, although the other properties and geometry may change. Then SFEE states:- The total energy at point 1 = total energy at point 2. This is usually written as:Qh + h1 + v12/2gJ + z1.g/J = Wd + h2 + v22/2gJ + z2.g/J
[Eqn 5.6.1]
Where Qh
=
heat supplied to the system .
h1,h2
=
the enthalpy or thermal energy of the system at 1 or 2.
z1,z2
=
the potential energy or height levels at points 1 or 2.
v12/2gJ
=
the kinetic energy of the system at point 1, etc.
J
=
the mechanical equivalent of thermal energy.
Wd
=
the work done in the transfer.
In Equation 5.6.1 the enthalpy h is sometimes known as the total thermal energy capacity of the fluid and h = U + P x V/J where U is the internal energy of a gas, P is its pressure and V is its volume. Thus if the pressure, temperature and volume of a gas change it is probable that its thermal energy will also change. The SFEE is most important in analysing the nature of gas flow through pipes, ducts, nozzles and orifices.
5 - 24
HPHT Course - Section 5
5.7 FLOW REGIMES Laminar and turbulent flow regimes exist for the flow of gases as for liquids and the criteria is the same i.e. at Reynolds numbers less than 2000 the flow is laminar and at Reynolds numbers greater than 4000 then the flow is turbulent. Between those 2 values the flow is transitional. The Reynolds Number for a fluid flow in a pipe is given by:NRe = v x d x w /µ Where
[Eqn 5.7.1]
v
=
flow velocity in either m/s or ft/s.
d
=
pipe internal diameter in m or ft.
w
=
gas density in kg/cu m or in lbm/cuft.
µ
=
absolute viscosity of the gas either in cP x .001 units (ie in Ns/m2) or in lbs/ft2 units. To convert cP to lbs/ft2 units multiply cP by 0.0000208854
The viscosity of a gas is usually much lower than that of liquids and so for gases the flow regime is often turbulent even at relatively low velocities. For example, air at 14.7 psia and 520°F abs has a viscosity of 0.00948 cP and a density of .0765 lbm/cuft. For a flow of only 5 ft/s in a pipe which is 2" ID the Reynolds Number is then NRe = 10000, which is clearly in the turbulent region.
5 - 25
HPHT Course - Section 5
5.8 FLOW OF GASES THROUGH AN ORIFICE Normally when it is necessary to measure the volumetric or alternatively the mass flowrate of a fluid in a pipe, this is done by means of a differential pressure meter using either a profiled bozzle or alternatively using a sharpedged orifice plate which is made to standard proportions such as those specified in BS 1042 or by the US Bureau of Mines. Such an orifice plate is shown in FIG 5.3 above, and it is specifically intended that the pressure drop from the upstream side to the downstream side should be very small, as measured in terms of inches head of water on a manometer tube. The equation for the volumetric flowrate is derived directly from the steady flow energy equation above and takes the form of:Qgh = 218.44 d2 x K x (Tb/Pb) x √(1/Tf/SGg) x √ hw x Pf
[Eqn 5.8.1]
Where Qgh = gas flowrate in cu ft/hr at the base conditions. d = orifice diameter in inches. K = the coefficient of discharge of the orifice plate. (This should be measured experimentally at a calibration facility. For most sharp-edged orifices the Cd = 0.65) Tb = temperature at base conditions, °F abs. Pb = pressure at base conditions, psia. Tf = temperature at flowing upstream conditions, °F abs. Pf = static pressure at upstream side, psia. (This is really the pressure which would be measured by a pitot-static device. It is really the flowing pressure + a pressure correction for the kinetic energy of the flow stream. SGg = the specific gravity of the gas. hw = the differential pressure across the orifice meter in inches of water on a manometer tube. It is usual to adopt base temperature and pressure as 60°F and 14.7 psia so that when those are inserted in Equation 5.8.1 the constant becomes 7727.13 which gives the flow in SCF/hour.
5 - 26
HPHT Course - Section 5
5.9 FLOW THROUGH A CHOKE Choke valves are usually plte chokes, which behave as sharp-edged orifices, or bean type chokes, which behave as nozzles. A choke orifice is similar to those used for metering gas flows, except that the pressure drop across the choke is likely to be very much higher than that used for flow metering. Under those circumstances it is necessary to take into account the compressibilty effects of the gas. The most appropriate comparison to this condition is the flow through a prover orifice which is used to assess the flow from a gas producing well which cannot be readily piped into an existing system for measurement. In this case the appropriate flowrate formula is that suggested by the US Bureau of Mines, which can be modified to include the “velocity of approach factor E : ie:Qg = 399.75 x P1 x d2 x E x √(1/T1/Zav/SGg) Where
[Eqn 5.9.1]
d = orifice diameter, inches. D = pipe ID inches. P1 = the upstream pressure in psia. T1 = the upstream temperature in °F abs. Zav = the average value of the gas compressibility in the expansion. SGg = the gas specific gravity. E
=
1 ––––––––––––– √[ 1 - (d/D)4]
The average value of Z may be calculated at a weighted-average value of the pressure as follows:Pav = (2/3) x [Pu + Pd - Pu x Pd/(Pu + Pd)] Where
Pu Pd
= =
[Eqn 5.9.2]
upstream pressure psia. downstream pressure psia.
At low pressures Zav will tend to 1 and the flow will agree with that predicted by the normal orifice flow equation. However, at high pressures and temperatures the effect may be to reduce the flow.
5 - 27
HPHT Course - Section 5
5.10 FLOW OF GASES ALONG PIPES: THE WEYMOUTH FORMULA From the above theory and observations, the flow in the surface lines is likely to be in the turbulent regime. The Weymouth formula is one which is used most frequently in calculating the flow capacity of pipes or alternatively, if the flow is known, to calculate the friction pressure drop in the pipe line. The Weymouth formula is primarily intended for use with pipes from 10 to 30 inches internal diameter, but it is used, to acceptable standards of accuracy, for pipes of 6 and 8 inches diameter. The flowrate capability of a pipe is given by:-
Q = .0013716 x
Where: Sg
[
(P12 - P22) x D5 –––––––––––––– ƒ x Sg x L x Z x T
]
1/2
[Eqn 5.10.1]
= The specific gravity of the gas.
Z = the gas compressibility factor. This will be 1 at or near atmospheric pressure. Tsc = standard reference temperature = 520°F abs. Psc = standard reference pressure = 14.7 psia. T = flowing temperature in °F abs. If hydrates are forming this could be well below atmospheric temperature. P1 = upstream pressure at inlet end of pipe, psia. P2 = downstream pressure at outlet end of pipe, psia. L = the equivalent length of the pipe, in miles. This should include the length equivalent of all bends, valves and fittings in the pipe, those values being obtained from tables. Q = pipe flow capacity in MMSCFD.
f = the pipe friction factor. For smooth pipes the friction factor, between Reynold’s numbers of about 2500 and 100000, is given to a good approximation, by Blasius’ solution of Colebrook’s function, as:
0.0791 ƒ = –––––– Nre0.25
5 - 28
[Eqn 5.10.2]
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CONTENTS
6.1
DRILLING AND WELL CONTROL PROCEDURES
6.2
H2S PROCEDURES
6.3
PRESSURE CONTROL SYSTEM EQUIPMENT INSPECTION/REPAIR PROCEDURES
6.4
TRAINING
6.5
MANAGEMENT AND CONTROL OF OPERATIONS
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6. DRILLING AND WELL CONTROL PROCEDURES FOR HPHT WELL PROGRAMMES, TRAINING & COMMUNICATIONS
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HPHT Course - Section 6
6.1 DRILLING AND WELL CONTROL PROCEDURES. The Operator should submit written procedures which pay particular attention to the downhole environment and specific precautions to be taken when operations are in progress in those sections of the well where formations with known or potential high overpressures are present. Special reference is to be made to the following:A. Drilling Procedures
6-2
-
Serviceability and consistency or instrumentation for monitoring pressure, temperature, and flowrates of fluids entering and leaving the well bore at surface and recording of such information and relevant information pertaining to incidents and events.
-
Status of automatic MAASP control in 12 inch and smaller hole sizes.
-
Specific instructions regarding equipment to be installed, or not, in the bottom hole assembly.
-
Penetration rate limitations.
-
Action to be taken on encountering a drilling break.
-
Procedure/action to be taken if rate of increase of temperature of the fluid returns increases above the previously observed trend when circulating at the rate used in drilling to the existing depth in the present hole size.
-
Procedures prior to, during, and after trips including acquisition of borehole survey data.
-
Procedure for monitoring wellbore fluid losses or gains when open hole is exposed and there is no pipe in the hole, or through the BOPs, particularly when the annular preventer and/or blind rams are closed.
-
Precautions to be taken when coring in overpressured reservoirs.
-
Procedure when gas content of mud increases.
-
Casing wear monitoring and procedures/practices to minimise casing wear.
-
Frequency of BOP and ancillary pressure control equipment tests.
-
Frequency of kick drills.
-
Operational status of overboard vent lines.
HPHT Course - Section 6
B. Well Control Procedures -
Shut-in procedures including sequence of operation of BOPs and valves in the pressure control system.
-
Procedures in case of doubt whether an influx has occurred.
-
Procedure for determining kick size and classification.
-
Guide-lines on choice of kick handling method and procedures for handling various types of kick .
-
Pressure limits for bullheading.
-
Stripping-in procedures.
-
Procedure/precautions to ensure mud-gas separator does not become overloaded when circulating out a kick.
-
Procedures/precautions to prevent hydrate formation and/or if hydrate formation is suspected/occurs whilst circulating out a kick.
-
Procedure when circulating out a kick if the temperature and pressure measured upstream of the surface choke exhibit anomalous trends or reach levels inconsistent with the circulation rate, especially during the later stages of removal of the influx from the wellbore.
-
Precautions to guard against explosive decompression of elastomeric components in the pressure control system when depressurising the system if such components have been exposed to hydrocarbon gases at high pressure for a prolonged period for any reason.
-
Procedures in the event of loss of control.
C. High Temperature Situations Monitoring procedures, precautions, and actions to be taken to insure that the rated working temperatures of elastomers in the equipment below are not exceeded: -
Flexible hose linings.
-
BOP Pipe ram face seals.
-
Any other seals in the pressure control equipment which could be exposed to extremes of temperatures.
6-3
HPHT Course - Section 6
6.2 H2S PROCEDURES. Unless there is conclusive evidence that H2S monitoring will not be required whilst drilling the well, the Operator should submit a copy of his H2S Procedures Manual, or that part of his Emergency Procedures Manual addressing H2S Procedures. 6.3 PRESSURE CONTROL SYSTEM EQUIPMENT INSPECTION/REPAIR PROCEDURES -
Policy in respect of testing and inspection of annular BOP’s after stripping-in operations.
-
Procedures to maintain total well control if the BOP stack has to be pulled/removed to repair faulty or failed components.
-
Flexible choke and kill hose pressure testing and inspection frequency and procedures.
-
Frequency and procedures for inspection and testing of permanently installed surface pressure control equipment, surface gas handling facilities, and solid pipework components of the choke and kill lines on the riser and BOP stack.
6.4 TRAINING The following should be addressed:-
6-4
-
Operator’s plans/procedures to ensure that all operator and contractor personnel directly involved in drilling operations on the subject well and those with day to day operational decision making responsibility receive specific training to enable them to handle, or make decisions regarding, well control situations in deep high pressure wells in a competent manner.
-
Familiarisation of key members of the above mentioned personnel with the contingency plans developed by the Operator (through well control simulation, simulator training, previous experience etc.) for the most probable well control scenarios that could be encountered in the subject well.
-
Drilling crew safety/awareness meetings in respect of operations in progress or planned.
-
H2S training and drills.
HPHT Course - Section 6
6.5 MANAGEMENT AND CONTROL OF OPERATIONS. The following should be addressed:-
Reporting relationships both offshore, onshore, and between the two, withdefinite clarification of the person onboard the installation to whom ultimate authority for decision making in respect of safety of the installation has been given.
-
Level of supervision of operations offshore by Operator’s staff.
-
Communications between offshore and onshore.
-
Duties of individual personnel.
-
Any major changes in reporting relationship between normal and emergency situations.
6-5
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CONTENTS
7.1
SHUT-IN LINE UP
7.2
SURFACE BOP'S WHILE TRIPPING
7.3
SURFACE BOP'S WHILE DRILLING
7.4
SUBSEA BOP'S WHILE TRIPPING
7.5
SUBSEA BOP'S WHILE DRILLING
7.6
SURFACE & SUBSEA BOP'S WHILE OUT OF THE HOLE
7.7
SURFACE & SUBSEA BOP'S WHILE WIRELINE LOGGING
7.8
TYPICAL SHUT-IN DECISION TREE FOR SURFACE BOP'S
7.9
TYPICAL SHUT-IN DECISION TREE FOR SUBSEA BOP'S
7.10
KILL WELL DECISION TREE
7.11
KILL CIRCULATION DECISION TREE
7.12
BULLHEADING DECISION TREE
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7. SHUT-IN PROCEDURES AND DECISION TREES
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HPHT Course - Section 7 7.1 SHUT IN LINE UP The valves located on the BOP, surface and subsea, systems will be closed The choke and kill manifold will have the choke closed plus, in the event that the choke is not a positive sealing choke, a block valve immediately upstream or downstream closed. The valve downstream of the choke can only be used as a block valve if it is the same working pressure as the choke, and is equipped to open when underpressure. 7.2 SURFACE BOP’S WHILE TRIPPING -
Set slips below top tool joint. Install full opening safety valve, torque connection and close safety valve. Close annular and open choke valves. Ensure the well is shut in and begin recording shut in pressures. Pass word to the OIL COMPANY REPRESENTATIVE and SENIOR DRILLING CONTRACTOR REPRESENTATIVE of the well condition. Make up the kelly or top drive or circulating kill assembly. Open safety valve. Complete recording of shut in pressure build up and pit gain. Decide on kill programme. Refer to decision tree Section 7.11.
7.3 SURFACE BOP’S WHILE DRILLING -
Stop drilling. Pick drill string off bottom to predetermined shut in point. Stop the mud pump. If flow is excessive begin next step immediately and strip drill string to close in predetermined point once well is secured. Close annular and open choke line valves. Ensure well is shut in and begin recording shut in pressures. Pass word to the OIL COMPANY REPRESENTATIVE and SENIOR DRILLING CONTRACTOR REPRESENTATIVE of the well condition. Pick up circulating kill assembly if it is to be used. Check space out then close upper pipe rams. Bleed off any trapped pressure between the annular and rams. Open annular. Complete recording of shut in pressure build up and pit gain. Decide kill programme. Refer to decision tree Section 7.11.
7.4 SUBSEA BOP’S WHILE TRIPPING 7-2
Set slips below top tool joint. Install full opening safety valve, torque connection and close safety valve. Close upper annular and open choke line failsafe valves. Ensure the well is shut in and begin recording shut in pressures. Pass word to the OIL COMPANY REPRESENTATIVE and SENIOR DRILLING CONTRACTOR REPRESENTATIVE of the well condition. Make up the kelly or top drive or circulating kill assembly. Open safety valve. Complete recording of shut in pressure build up and pit gain. Decide kill programme. Refer to decision tree Section 7.11.
HPHT Course - Section 7
7.5 SUBSEA BOP’S WHILE DRILLING -
-
-
Stop drilling. Pick drill string off bottom to predetermined shut in point. Stop the mud pump. If flow is excessive begin next step immediately and strip drill string to close in predetermined point once well in secured. Close upper annular and open choke line failsafe valves. Ensure well is shut in and begin recording shut in pressures. Pass word to the OIL COMPANY REPRESENTATIVE and SENIOR DRILLING CONTRACTOR REPRESENTATIVE of the well condition. Pick up circulating kill assembly if it is to be used. Check space out and close upper pipe rams. Adjust BOP closing pressure as required for stripping and landing drill string on upper pipe rams. Land drill string on upper pipe rams, adjust BOP closing pressure and down weight on upper pipe rams to prevent the hydraulic effect on the drill string. Close wedge locks. Bleed off any trapped pressure between the annular and rams. Open annular. Complete recording of shut in pressure build up and pit gain. Decide kill programme. Refer to decision tree Section 7.11.
7.6 SURFACE & SUBSEA BOP’S WHILE OUT OF THE HOLE -
Close shear/blind rams and open kill line valves. Allow pressure to stabilise, record pressure and pit gain. Pass word to the OIL COMPANY REPRESENTATIVE and SENIOR DRILLING CONTRACTOR REPRESENTATIVE of the well condition. Prepare to bullhead influx to formation. If well is dead run in hole to condition mud. If well is not dead, strip in the hole for kill operations. Refer to decision tree Section 7.11.
7.7 SURFACE & SUBSEA BOP’S WHILE WIRELINE LOGGING -
Direct the wireline loggers to cease operations and close the well on the upper annular. Open kill line valves and begin to record shut in pressure and pit gain. Pass word to the OIL COMPANY REPRESENTATIVE and SENIOR DRILLING CONTRACTOR REPRESENTATIVE of the well condition. Decide on kill programme. Refer to decision tree Section 7.11. Note: If at all possible the wireline should be pulled or stripped out of the hole. If the line needs to be cut and dropped, a surface hydraulic cable cutter should be used. The shear rams should be considered as a last resort and used only if the annular(s) fail to secure the well. 7-3
HPHT Course - Section 7
7.8 TYPICAL SHUT-IN DECISION TREE FOR SURFACE BOP'S WELL FLOWS OPERATION IN PROGRESS DRILLING (BIT ON BOTTOM)
TRIPPING (BIT OFF BOTTOM)
RAISE KELLY OR TOP DRIVE
INSTALL OPEN SAFETY VALVE
CLOSE SHEAR RAMS
STOP PUMP
CLOSE SAFETY VALVE
OPEN CHOKE LINE
CLOSE BOP'S
CLOSE BOP'S
OPEN CHOKE LINE
OPEN CHOKE LINE
CLOSE KELLY COCK OR TOP DRIVE SAFETY VALVE
COLLARS IN BOP?
NO PIPE IN BOP
NOTE 1. IS UPWARD FORCE ACTING ON COLLARS GREATER THAN STRING WEIGHT? YES
NO INSTALL KILL ASSEMBLY & TEST
INSTALL KILL ASSEMBLY & TEST
CHECK SURFACE PRESSURES SEE NOTE 1
YES
NO
DROP STRING WAIT THEN CLOSE SHEAR RAMS PRESSURE UP TO S.I.D.P.P. OPEN KELLY COCK OR TOP DRIVE SAFETY VALVE
OPEN SAFETY VALVE OBSERVE WELL MUSTER HALL CREWS FOR INFORMATION CALCULATE PREPARE TO KILL
7-4
WITHDRAW ALL WORK PERMITS
ADVISE STANDBY BOAT
INFORM DRILLING CONTRACTOR OFFICE
INFORM OFFICE
HPHT Course - Section 7
7.9 TYPICAL SHUT-IN DECISION TREE FOR SUBSEA BOP'S
WELL FLOWS OPERATION IN PROGRESS DRILLING (BIT ON BOTTOM)
TRIPPING (BIT OFF BOTTOM)
RAISE KELLY OR TOP DRIVE
INSTALL OPEN SAFETY VALVE
CLOSE SHEAR RAMS
STOP PUMP
CLOSE SAFETY VALVE
OPEN CHOKE LINE
CLOSE UPPER ANNULAR
CLOSE UPPER ANNULAR
OPEN CHOKE LINE
OPEN CHOKE LINE
CLOSE KELLY COCK OR TOP DRIVE SAFETY VALVE
COLLARS IN BOP?
NO PIPE IN BOP
NOTE 1. IS UPWARD FORCE ACTING ON COLLARS GREATER THAN STRING WEIGHT? YES
INSTALL KILL ASSEMBLY & TEST
NO INSTALL KILL ASSEMBLY & TEST
CHECK SURFACE PRESSURES
CHECK SPACE OUT
CHECK SPACE OUT
SEE NOTE 1
CLOSE UPPER 5" PIPE RAMS
CLOSE UPPER 5" PIPE RAMS
LAND STRING CLOSE RAM LOCKS
LAND STRING CLOSE RAM LOCKS
PRESSURE UP TO S.I.D.P.P.
OPEN KELLY COCK OR TOP DRIVE SAFETY VALVE
OPEN KELLY COCK OR TOP DRIVE SAFETY VALVE
OBSERVE WELL MUSTER HALL CREWS FOR INFORMATION CALCULATE PREPARE TO KILL
YES
NO
DROP STRING WAIT THEN CLOSE SHEAR RAMS
WITHDRAW ALL WORK PERMITS
ADVISE STANDBY BOAT
INFORM DRILLING CONTRACTOR OFFICE
INFORM SHOREBASE OFFICE
7-5
7-6
BULLHEAD INFLUX See Section 7.12
TRIPPING
BULLHEAD TO REDUCE VOLUME
?? bbls
KICK SIZE
DRILLING
KICK TAKEN WHILST:
FLOW DETECTED WELL SHUT IN
CIRCULATE OUT INFLUX See Section 7.11
?? bbls
BULLHEAD INFLUX See Section 7.12
OUT OF HOLE
HPHT Course - Section 7
7.10 KILL WELL DECISION TREE
HPHT Course - Section 7
7.11 KILL CIRCULATION DECISION TREE Monitor DP/CSG Pressures
is pipe on bottom?
NO
Strip to bottom
YES Doubt exists
YES
NO Wait and Weight Calculate the following: Max anticipated surface pressure. Max anticipated surface gas volumes. Hydrate formation points Max SCR at surface
Driller's Method
Line up surface facilities: a) Poorboy/trip tank b) Blow down line c) Glycol injected unit d) Cement unit for glycol injection
Start circulation at selected SCR
Influx ??? ft from BOP
Are hydrates predicted at BOP
YES
Start injecting glycol at ?? gall/min down kill line
NO Stop pumps and restart at lower SCR
YES
U/S Choke temperature approaching ?? °F
NO Gas at choke
Start injecting glycol into CM at ?? gall/min
Restart pumps at lower SCR
Shut choke. Stop pumps. Open vent line.
Monitor Buffer Tank Pressure
Exceeding ??? psi?
Stop pumps. Select lower SCR Exceeding Trip Tank gauge pressure
Shut choke. Stop pumps. R/U to heat manifold to clear plug
Approaching ??? psi
Redirect flow to another choke. Increase glycol injection rate.
Monitor Poorboy Pressure
Approaching Trip Tank gauge pressure
YES Hydrates plug formed?
NO Influx circulated out
Stop pumps. Monitor pressures
0 psi?
NO
Perform further circulation
YES Clear BOP Circulate riser Open well
7-7
HPHT Course - Section 7
7.12 BULLHEADING DECISION TREE DECISION MADE TO BULLHEAD PIPE HUNG OFF IN U.RAMS UPPER CHOKE LINE F/S's OPEN - CHOKE CLOSED CALC: INFLUX VOLUME VOLUME TO BE BULLHEADED MAX. INJ. PRESSURE GRAPH POSITION OF INFLUX
ALLOW PRESSURES TO STABALISE
LINE UP SURFACE EQUIP TO KILL PUMP P/T SURFACE LINES TO BULLHEAD DOWN KILL LINE
START KILL PUMP BRING UP TO SPEED AT LOW RATE START BULLHEADING AT CONSTANT RATE PLOT INJECTION PRESSURE/VOLUME RELATIONSHIP MONITOR DP AND CGS PRESSURES
YES CONTINUE BULLHEADING
NO
IS FLUID BEING INJECTED?
IS INJECTION PRESSURE AT MAXIMUM?
NO INCREASE INJECTION PRESSURE
YES GO TO WELL KILL CIRCULATION
YES
IS INJECTION PRESSURE DECREASING?
NO
STOP PUMPS SHUT IN. ALLOW PRESSURES TO STABILISE
IS SICP< ORIGINAL SICP?
YES
YES
BULLHEAD REQUIRED INFLUX VOLUME.
NO
7-8
BLEED OFF TRAPPED PRESSURE
YES IS SIDP=SICP?
IS PRESSURE TRAPPED IN WELL?
NO
GO TO WELL KILL CIRCULATION
NO
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8. BULLHEADING OVERVIEW
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HPHT Course - Section 8 Rev.1/07-05-96 BULLHEADING OVERVIEW
Aberdeen Drilling Schools & Well Control Training Centre Bullheading is a method used to displace an influx back into the formation using available mud weight. The well is later killed circulating heavy mud as required. The advantage with this method is that it avoids handling of gas at surface. With this in mind bullheading should be considered a gas handling method rather than a primary well control method. If the bit is off bottom, the influx can be bullheaded and the well killed with the normal mud weight. In most cases (i.e. the influx was induced by swabbing). Bullheading can also be used if it is apparent that the surface pressure (or H2S presence) would pose a serious risk to the rig and its equipment during normal killing operations. When bullheading where open hole sections are exposed, there is a chance that the formation could break down at the shoe rather than at the formation where the influx came from. It should always be kept in mind that bullheading may aggravate the development of an underground blowout. Due diligence must be taken when using bullheading therefore, the injection pressure should normally decrease as the influx is forced back to the formation. A constant injection pressure indicates that the influx is below the fractured zone/injection point. Bullheading a mixture of mud and hydrocarbons into the formation may create an “artificial” pore pressure which is equal to fracture closure pressure. This charged formation will tend to act as a “kick” and will create problems in relation to the amount of fluid pumped and the properties of the formation. Small and minor zones/fractures with no or little porosity and permeability are more likely to swell while more porous and permeable zones may absorb the injected fluid more easily. When injecting hydrocarbons with an increasing content of mud the injection pressure may increase due to plugging of the pores. The pressure will increase further when non-contaminated mud is being bullheaded into the formation and a fracture is created. The well MAASP figure should be considered and reviewed prior to the bullheading operations. Maximum bullheading pressure needs to be worked out well in advance so as to minimise any confusion in this operation.
8-1
HPHT Course - Section 8
The success of a bullheading operation is dependent of several things such as: -
Record and double check pressure limitations of pumping equipment, wellhead equipment and casing. These limitations must be monitored and be used to govern the bullheading procedure.
-
The earlier an influx is bullheaded the less volume has to be bullheaded. If a gas kick occurs and is allowed to migrate, a larger volume than the initial conditions will have to be bullheaded back into the formation.
-
A smaller volume bullheaded will create less super-charging effect on the formation.
-
Based on influx volume, migration time, pressures and hole configuration decide whether to bullhead down drillstring and annulus or annulus only.
-
Dependent on surface rig up, it is recommended to have a check valve between the pumping unit and the well. This will act as a fail-safe valve in the event surface equipment should fail during bullheading.
-
If an influx is to be bullheaded, the pumping rate for bullheading must be fast enough to exceed the rate of any gas migration. This can be a problem in large diameter holes.
-
If pump pressure increases instead of decreasing, it might be an indication that the pumping rate is too low to bullhead the influx back into the formation.
Bullheading a kick can be the method used when the following conditions exist: A. The kick size is too large to be circulated to the surface. B. Returns are lost when starting to circulate out the kick. C. When the drillstring is out of the hole. D. The kick is caused by swabbing when POOH. E. The influx or drilling mud returns contain more H2S than the operation can tolerate. F. Plugged or parted drillstring where kill mud cannot get to the bottom of the hole. G. Rig operation must gain time when short of material, skilled personnel and/or equipment problems. 8-2
HPHT Course - Section 8
PROCEDURE FOR BULLHEADING When an influx is detected and the well is shut in, the following critical parameters shall be evaluated: -
estimated maximum surface pressure
-
estimated surface gas volumes
-
possibility of hydrate formation
-
capacity of Mud Gas Separator and limits placed on kill rate
-
probability of breaking down the formation circulating the kick to surface
NOTE: A decision should be taken fairly soon to avoid packing off annulus due to settling of barite or drill solids. Decide the rate and the volume to be bullheaded. The volume shall be based on the influx volume and how the influx was taken. For a kick taken during drilling, the volume circulated while the kick was taken must be added to the measured surface gain plus a safety factor for uncertainty and migration. For a kick taken during tripping (swabbed), the volume should be equal to the influx. Make sure sufficient mud volume is on hand to complete the bullheading operation. Line up and pressure test surface equipment. Keep an estimate of surface pressure needed to fracture the formation based on an estimate of the formation strength of the kicking zone. If the influx occurred during drilling, do not start bullheading before the shut-in drillpipe pressure has stabilised. The maximum allowed bullheading pressure shall be determined and decided upon before bullheading operations commence.
NOTE: The weight of the mud can be the same as the actual mud in use when the kick or influx occurred. Start the bullheading at a low rate and establish an injection rate. (Volume vs. Pressure). Monitor the injection pressure to check that it is less than the maximum pressure to be used. If this pressure is less than MAASP value there is a good chance that the influx is being pumped back to where it came from.
8-3
HPHT Course - Section 8
Attempt to keep a constant rate and plot the injection pressure versus the volume. Have the LOT information available so this information can be compared.
NOTE: Update the leak-off test plot each time the mud weight is changed. Take SCR down kill/choke-line with the cement unit after setting the first competent casing string and all succeeding casing/liner strings. Bullheading should be interrupted if injection is not obtained within the predetermined maximum allowable injection pressure. Start over again with a lower pump rate. If surface injection pressure exceeds the predetermined pressure, re-evaluate the situation where consideration is given to proceed with a conventional kill operation where circulating back to surface is performed. When the initial predetermined volume is bullheaded, shut the well in and observe the annulus and drillpipe pressures. If the shut-in annulus pressure has dropped, proceed with the bullheading operation until the annulus and drillpipe pressures are equal. Bleed off any trapped pressure. If the kick or influx was taken during drilling and bullheading operations were performed, proceed with a conventional kill method. If the kick or influx was taken during tripping consider stripping back to bottom (possibly in stages) and using a conventional kill method once bullheading has been completed.
PROCEDURE IF INITIAL BULLHEADING WAS UNSUCCESSFUL If the initial bullheading was unsuccessful (injecting into formation above the influx), strip back to bottom (if off bottom) and proceed to bullhead down both drillstring and annulus in order to minimise the influx volume (influx too large to be circulated out).
NOTE: In this case the formation has been fractured and may have been charged. Shut the well in and bleed off any trapped pressure. Circulate out the influx with a limited SPM in order to maintain returns and to minimise the rate of gas on surface.
8-4
HPHT Course - Section 8
ALTERNATIVE TO BULLHEADING WHILE TRIPPING If a kick occurs during tripping, possibly consider using the following procedure as a alternative to bullhead. If the size of the influx volume is minor, shut in the well and consider to circulate in a heavy mud pill with sufficient density and volume to create at least 50 psi overbalance Flowcheck the well on trip tank, open the BOP and RIH if the well is stable. When the drillstring has displaced the top of the heavy pill to the surface, shut the well in and place another pill in the annulus. Flowcheck the well on trip tank, open the BOP and RIH if the well is stable. Repeat the steps until the drillstring enters the influx. Strip in to bottom (or to the top of the reservoir) and circulate the influx according to normal kick handling procedure.
8-5
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CONTENTS
9.1
THE VOLUMETRIC METHOD OF WELL CONTROL
9.2
BASIC THEORY
9.3
PHASE 1: BRINGING THE GAS TO THE SURFACE CHOKE
9.4
STANDARD CONDITIONS
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9. VOLUMETRIC METHOD OF WELL CONTROL
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HPHT Course - Section 9
9.1 THE VOLUMETRIC METHOD OF PRESSURE CONTROL Occasions arise when it is necessary to use the volumetric method of well control although there is commonly less emphasis upon this method than normal circulation methods. However it is a reliable and well-tried method for removing a gas influx from a well. The circumstances when the VOLUMETRIC METHOD is used fall into the following categories: (a)
Drill-string at or near bottom but with some problem which makes it impossible to circulate a kick in a normal way. (Plugged or damaged or burst string).
(b)
Drill string off-bottom, with a gas kick rising below or above the bit. (Possibly a swabbed kick).
(c)
Drill string out of the well with a migrating gas influx shut-in within the well. (Possibly a swabbed kick).
The basic procedure is in 2 parts: Part 1, whereby the gas is allowed to migrate to the surface and mud is bled from the well in pre-determined volumes, while the gas is within the annulus. During this stage the gas pressure is reduced and the choke pressure rises, whilst the bottom hole pressure remains almost constant, within a safety tolerance margin. At the end of this stage, the gas volume and the choke pressures are substantially the same is if the gas had been brought to the choke by the first circulation of the Driller’s Method. Part 2, when the gas is bled from the well at the choke and mud is lubricated (pumped) into the well. During this stage the gas volume and choke pressure reduce, while the bottom hole pressure again remains substantially constant. Current mud is used throughout.
9-2
HPHT Course - Section 9
The fundamental principles which apply for the gas behaviour, assuming that no gas escapes from the annulus, are : (a)
The gas migrates upwards, either as a large single bubble or as a system of small bubbles. Care has to be taken in estimating the rate of gas migration, and a large slug of gas is known to migrate more rapidly than small bubbles. At shut-in conditions, the nominal rate of gas migration, Umg, is likely to be in excess of the rate calculated from:
Umg =
Rate of rise of choke pressure (psi/hr) ——————————————————— Mud gradient (psi/ft)
[Eqn 9.11]
(b)
Changes of gas temperature and compressibility factor, Z, are ignored. ie, if the gas does not expand, its pressure and its volume do not change (Boyle’s Law).
(c)
The total gas hydrostatic pressure in the well is constant regardless of whether the gas is expanded or unexpanded, or if it is a single bubble or a system of small bubbles. This means that as the gas is allowed to expand its density and its pressure gradient reduce.
(d)
If a volume of mud is bled from the well, then the gas in the well must expand by the same volume.
Other definitions which are used in this method are :
SAFETY MARGIN:
This is a small amount of additional bottom hole pressure which is held above the formation pressure. This is applied by allowing some extra gas compression during its initial migration. Depending on fracture and formation conditions this may be between 100 and 300 psi.
OPERATING MARGIN: This is the additional pressure which is allowed to build up and on the choke in the periods when no mud is being bled at the choke and the gas is rising in the annulus. This is commonly allocated as 100 or 200 psi, depending on the well conditions.
9-3
HPHT Course - Section 9
9.2 BASIC THEORY Although the method is primarily a practical hands-on method, it is still of some value to make an estimate of : (a)
The approximate value of the expected maximum choke pressure.
(b)
The approximate volume of the expanded gas at the choke. From this it is then possible to estimate the total volume of mud which needs to be bled from the choke during the rise of the gas in the annulus.
It is also assumed that the following data is known: Well TVD (ft) Mud density (ppg) and gradient (psi/ft) Bottom hole pressure (psi) Initial gas influx volume (bbl). Annulus geometry and capacities (bbl/ft) for each part of the well. It is also unlikely that the SIDPP will be known and in many cases when the volumetric method is used, the kick will have been swabbed and hence the degree of final pressure imbalance, when the bit is eventually back on bottom, should be zero. 9.2.1 Maximum Anticipated Choke Pressure and Gas Volume. It has been indicated above, that even although no mud is circulated, but mud is bled off as the gas rises, and the choke pressure is adjusted accordingly to maintain “constant” bottom hole pressure, the net result is the same as if the 1st circulation of the Driller’s Method is used. From Section 2 “The Behaviour of Gases”, the maximum pressure at the choke for a gas kick , using the Driller’s Method, is calculated from Equation 2.62, by substituting the value of zero for the depth of interest. Then : Pckmax = 0.5 x √(Pdp2 + 4 x Vg1 x Gm x Pbh/Ca) + 0.5 x Pdp
9-4
HPHT Course - Section 9
For a swabbed kick, with the correct pre-swab bottom-hole pressure, the SIDPP = Pdp = 0. Then : Pckmax = √(Vg1 x Gm x Pbh/Ca) Where
Vg1 Gm Pbh Ca
[Eqn 9.21]
= = = =
initial gas influx volume, bbl. current mud gradient, psi/ft. bottom hole pressure, psia. annulus capacity at the top section of the annulus, bbl/ft. Pckmax= maximum anticipated pressure when gas is at the choke psia.
This formula can be simplified to give : Pck max = 228 x √(P x Vg1 x W/C) Where
P W C
[Eqn 9.22]
= Bottom hole pressure, in 1000’s of psia. = Mud density, in ppg. = Annulus capacity, in bbl/1000ft at the top of the annulus.
NB:Some texts use 200 instead of 228 as the coefficient in Eqn 9.22. This produces an error of about 10% on the low side for Pckmax. Once the maximum choke pressure has been calculated, it is possible to calculate (by Boyle’s Law) the volume of gas which can be expected when it reaches the top of the annulus, as:
Vgck = Vg1 x Pbh/Pckmax
(bbl)
[Eqn 9.23]
The expansion of the gas, and the total amount of mud to be bled off is then : Vmud
= Vgck - Vg1
(bbl)
[Eqn 9.24]
Those values of Pckmax and Vmud should be used only as a guide.
9-5
HPHT Course - Section 9
9.2.2 Calculation of Change in Choke Pressure for Bleeding Off a Volume of Mud. The change in choke pressure for bleeding off a volume of mud changes from section to section of the well, if there is drill string in the hole. Let Gm = mud gradient, psi/ft. Let Cdc = capacity of the drill collar/hole/casing annulus, ft/bbl. Let Cdp = capacity of the drillpipe/hole/casing annulus, ft/bbl. Let Ch = capacity of the open hole or casing, ft/bbl. Let dP = change in choke pressure, psi, during one bleed-off stage. Let dVm = change in mud volume ( ie mud bled off), bbl, during one bleed-off stage. This is also the gas expansion. Example : Mud gradient = 0.65 psi/ft. Cdc = 0.0291 bbl/ft. for 600 ft inside the casing. Cdp = 0.0459 bbl/ft. for 10400 ft inside the casing. Ch = 0.0702 bbl/ft. for 4000 ft below the collars. How much mud has to be bled off at each stage of the well to give a change in choke pressure of 200 psi? The volumetric change in mud hydrostatic pressure in the well is calculated from : dPhm = Gm (psi/ft)/ Capacity (bbl/ft)
[Eqn 9.25]
= 0.65/0.0702 = 9.259 psi/bbl in open hole or
= 0.65/0.0291 = 22.34 psi/bbl in DC annulus
or
= 0.65/0.0459 = 14.16 psi/bbl in DP annulus
The volume of mud to be bled off at each stage to give a 200 psi change in the choke pressure is then : dVm
9-6
= DPck / dPhm
[Eqn 9.26]
HPHT Course - Section 9
And if the change in choke pressure for each bleed-off is to be 200 psi (ie DPck = 200), the : dVm = 200/9.259 = 21.60 bbl in open hole or
= 200/22.34 = 8.95 bbl in DC annulus
or
= 200/14.16 = 14.12 bbl in DP annulus.
ALTERNATIVELY, if it was decided always to bleed ,off the same volume of mud, say 15 bbl at each step, then the change in choke pressure could be calculated from Eqn 9.26 as:
DPck = dVm x dPhm = 15 x 9.259 = 139 psi in the open hole or
= 15 x 22.34 = 335 psi in the DC annulus
or
= 15 x 14.12 = 212 psi in the DP annulus.
9.3 PHASE 1 : BRINGING THE GAS TO THE SURFACE CHOKE. Prior to starting this operation it is necessary to ensure the following: (a)
All pressure control equipment and the choke has been checked and is correctly lined up.
(b)
There is an accurate means of measuring the volume of mud which is bled from the annulus into a trip tank. It may be useful to hook up a small volume bleed tank which has a volume of 10 to 15 bbl, which can be drained into the main trip tank.
(c)
The mud pump delivery per stroke is known accurately.
(d)
The choke pressure gauge is accurate and has as fine a scale graduation as possible.
9-7
HPHT Course - Section 9
It is possible to proceed in one of 2 ways: (1)
Elect to bleed off a constant volume of mud on each step and then calculate the increase in choke pressure due to the reduction in the mud hydrostatic pressure. This gives THE CONSTANT VOLUME METHOD OF WELL CONTROL. This means that, as the gas rises past the various sections of the drillstring (if it is in the hole), then the change of choke pressure will differ from one section to the next.
OR (2)
Elect to bleed off a constant amount of mud hydrostatic pressure and then calculate the volume of mud which has to be bled off at each stage of the well. Some operating companies regard this as a more reliable method, as the value of the pressure change at the choke at each stage is constant and there is a more accurate control of bottom hole pressure.
Obviously, if there is no drillstring in the hole, the calculations involve only one value of dPhm. 9.3.1 Phase 1 Procedure. (a)
Estimate the rate of gas migration and the approximate position of the gas in the well as the operation is about to start.
(b)
Estimate the total volume of mud to be bled off and the maximum choke pressure.
(c)
Confirm the values of Safety Margin and Operating Margins to be used, making sure that while the gas is below the casing shoe, the MAASP will not be exceeded.
(d)
Allow the choke pressure to build up above its initial shut-in value by (i) The Safety Margin PLUS (ii) The operating margin. This value is : Pck1 = SICP + Safety Margin + Operating Margin
9-8
(e)
When Pck1 has been reached, the choke operator opens the choke and HOLDS THE CHOKE PRESSURE CONSTANT AT THIS VALUE while the correct amount, dVm, of bleed-off mud is bled to the measuring tank. When this has been done, the choke is closed.
(f)
The choke pressure is now allowed to rise again ( due to gas migration without expansion) until the choke pressure is now Pck2, where: Pck2 = SICP + Safety Margin + 2 x Operating Margin
HPHT Course - Section 9
(g)
When Pck2 has been reached, Step (e) is repeated. If the gas has moved from one section of the well to another, the new mud bleed volume will require to be bled off.
(h)
This process is repeated until gas is recorded to be at the choke. For each step, the new choke pressure is : Pckn = SICP + Safety Margin + n x Operating Margin
Graphs of (a) Choke pressure against gas distance ( or time interval) from bottom hole and (b) Choke pressure against mud bled-off volume are shown in FIGS 9.1 and 9.2 below.
CHOKE PRESSURE (PSI)
FIG 9.1
δVM δVM δVM Pck4
δVM Pck3 Pck2 Pck1
SKP
GAS POSITION - HEIGHT ABOVE BOTTOM HOLE (TIME)
Pck (PSI)
FIG 9.2
Pck1 δVM
δVM
MUD BLED OFF (BBL) 9-9
HPHT Course - Section 9
When the gas is located behind the surface choke the PHASE 1 of the operation is completed. NOTE OF CAUTION : THE ABOVE MATERIAL HAS BEEN WRITTEN FOR THE CASE OF FREE GAS WITHIN THE MUD IN THE ANNULUS. IF AN OIL-BASED MUD IS IN USE IT IS POSSIBLE THAT AN INITIAL SWABBED INFLUX OF FREE GAS WILL DISPERSE AND STREAM WITHIN THE MUD, AFTER WHICH IT IS LIKELY TO DISSOLVE WITHIN THE OIL PHASE OF THE MUD. THIS WILL LEAD TO A VOLUME CHANGE AND POSSIBLY A CHANGE OF CHOKE PRESSURE. IF THE BUBBLE POINT PRESSURE OF ANY GAS/LIQUID SOLUTION SO FORMED IS BELOW THE MAXIMUM ANTICIPATED CHOKE PRESSURE ( WHICH MAY BE APPROXIMATELY EQUAL TO THE SICP) THEN THERE WILL BE NO FREE GAS TO EXPAND TO THE SURFACE AND LITTLE OR NO MUD TO BLEED OFF. IN SUCH CIRCUMSTANCES, THE GAS WOULD NOT BE RELEASED FROM THE MUD UNTIL THE GAS/LIQUID SOLUTION IS DOWNSTREAM OF THE CHOKE AND ON ITS WAY TO THE MUD GAS SEPARATOR.
9.4 PHASE 2 PROCEDURE: PUMPING IN MUD AND BLEEDING OFF GAS. The process of pumping mud into the top of a closed-in well containing gas, and then bleeding off gas at the choke, is known as lubricating mud into the well. Prior to starting to lubricate it is necessary to check the following : (a) An adequate supply of clean CURRENT mud should be available. (b) The pump manifold alignment and the choke/downstream alignment to the MGS should be checked. (c) The setting of automatic valves to open overboard lines should be checked. (d) The output per stroke of any pump to be used should be accurately known. “Pumps” include mud pumps, cement pumps or dedicated kill pumps. (e) The setting of any MGS blowdown/seal-tube alarms should also be checked.
9 - 10
HPHT Course - Section 9
9.4.1 Calculations At the end of the Phase 1, the gas will be behind the choke and the choke pressure will still have the Safety Margin component within it. It is generally advisable to release gas in small quantities, to avoid the possibility of overloading the MGS/seal tube which might happen with large “bursts” of gas. Since the gas is at the top of the well, it will usually be only one annulus capacity at the top of the well which enters into the calculations, unless there is drillpipe and collars in the well near to the top. As in Eqn 9.25, the volumetric change in mud hydrostatic pressure is calculated from : dPhm = Gm/C
(psi/bbl),
where C is the particular annulus capacity, bbl/ft.
The total volume of gas at the choke is estimated from Eqn 9.24 as : Vgck = Vmud + Vg1 (bbl), where Vmud is the total volume of mud bled off in Phase 1 and Vg1 is the initial gas volume. This can be used as a guide to determine how much mud has to be lubricated into the well, but when no more gas is being released at the choke, the lubrication would be stopped, unless a policy of lubricating and bleeding extra (clean) mud is adopted as a safety measure. The total volume of mud to be lubricated into the well is broken down into manageable slugs, so that the choke pressure is not being reduced too rapidly when gas is bled off. As a rule, lubricating mud to give an in crease of mud hydrostatic pressure of 100 psi is reasonable. Thus, per 100 psi of mud hydrostatic pressure pumped into the well, the volume of mud injected will be :
dVmi = 100/ dPhm
(bbl)
[Eqn 9.41]
The number of pump strokes which have to be pumped to inject this volume of mud are given from : Strokes = Vol of mud to inject(bbl)/Pump delivery (bbl/stk) = Vmi / Vpst
[Eqn 9.42]
9 - 11
HPHT Course - Section 9
When mud is lubricated into the well against a closed choke, the bottom hole pressure rises due to: (a) The extra mud hydrostatic pressure in the well. (b) The extra compression of the gas, which is given by: New Pchk after mud injection - Old Pchk before injection. In addition, the Safety Margin pressure will still be acting on the bottom hole. Then, if Pchk1 = initial choke pressure ( with SM) before mud injection, Pchk2 = new choke pressure after mud injection. And when gas is bled off, for a 100 psi mud injection, the choke pressure is allowed to fall by: dPchk = Pchk2 - Pchk1 - 100
[Eqn 9.43]
9.4.2 Lubrication Procedure (a) Record the final pressure at the choke after all mud of Phase 1 has been bled off and the gas is stabilised at the choke. This is Pchk1. (b) Operate the pump slowly and for the pre-determined number of strokes to inject (via the kill line) the correct volume of injection mud, Vmi. It is essential to do this slowly so that the mud (heavier than the gas) has time to sink down through the gas. When the mud has been injected, the pump is stopped. (c) The choke pressure will rise to a new value, Pchk2. Give this time to stabilise and calculate the drop in choke pressure, dPchk, necessary as gas is bled off. (d) The choke operator should then open the choke slowly and allow the choke pressure to fall by the predetermined amount ÎPchk, as calculated . (e) This procedure is repeated until all the gas has been exhausted from the annulus. (f) When all the gas has been exhausted and the system stabilised, record the final choke pressure : Pck (end) . It should be remembered that the Safety Margin pressure is still held within this pressure.
9 - 12
HPHT Course - Section 9
If the choke pressure is greater than the Safety Margin, the well will still be underbalanced and kill mud will have to be circulated eventually. (g) If it is possible, drillstring may be snubbed and stripped back into the well to bottom, with current mud in the well. (h) If there is a shut-in drillpipe pressure at this point, it will be necessary to calculate the correct kill mud density and circulate this around the well. (j) If there is no SIDPP when string has been stripped back to bottom, then it would be necessary to flowcheck and condition the mud before proceeding with further operations. A typical graph of choke pressure against volume of mud injected is shown in FIG 9.3. FIG 9.3
Pchk2
CHOKE PRESSURE (PSI)
Pchk1
BLEED-OFF GAS
MUD HYDRO
δVmi
δVmi
ALL GAS REMOVED.
δVmi δVmi
FINAL SICP
VOLUME OF MUD INJECTED (BBL)
9 - 13
HPHT Course - Section 9
EXAMPLE: At the end of a volumetric process to bring a 30 bbl swabbed gas influx to the surface the following were the relevant values: Choke pressure Gas volume Mud gradient Annular capacity Pump output Operating margin
= = = = = =
2300 psig (including a 200 psi Safety Margin) 135 bbl 0.806 psi/ft 0.04892 bbl/ft 0.117 bbl/stk 200 psi
The mud volumetric hydrostatic ratio is dPhm
= 0.806 / 0.04892 = 16.48 psi / bbl
For a 200 psi hydrostatic operating margin, the volume of mud to be pumped is the dVm = 200 / 16.48 = 12.14 bbl. The pump strokes to do this are dSt = 12.14 / 0.117 = 104 strokes. With the choke closed, the pump is slowly stroked for 104 strokes and the mud is injected through the kill line. As it does so it (a) increases the mud hydrostatic pressure on the bottom hole by 200 psi and (b) it compresses the gas by a volume of 12.14 bbl. The new choke pressure after the mud injection therefore rises to : Pchk = P gas = Initial gas vol x Initial choke press / New gas vol = 135 x 2300 / (135 - 12.14) = 2527 psig. Once pressures have settled, the choke is then slowly opened, and the gas is allowed to vent to the MGS . The choke is held open until the 200 psi of mud hydrostatic pressure is removed from the bottom hole, ie until the choke pressure has fallen to 2300 - 200, ie 2100 psi. It should be noted that in doing so, the mass of gas in the well has been reduced and the gas hydrostatic pressure is less than it was before. This process is repeated, with successive 12.14 bbl mud injections and choke pressures, after the bleed-offs of gas, coming down in 200 psi intervals, eg 1900, 1700, 1500 psi, etc, until all the gas (135 bbl) has been vented from the well.
9 - 14
• ABE
RD
CONTENTS
10.1 STRIPPING 10.2 ANNULAR STRIPPING PROCEDURE 10.3 RAM COMBINATION STRIPPING PROCEDURE 10.4 SAFETY MARGIN (OVERBALANCE) AND OPERATING MARGIN 10.5 RECORDING OF DATA IN A KICK AND/OR STRIPPING OPERATION
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10. STRIPPING
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HPHT Course - Section 10
10.1 STRIPPING Annular stripping technique equipment requirements: -
Ability to read annulus pressure satisfactory A method of bleeding volumes from the annulus A small measuring tank Surge dampener on annular Record keeping of operation (pressures, volumes & depths)
10.2 ANNULAR STRIPPING PROCEDURE 1) Establish initial shut in conditions. -
Continue to monitor for migration
2) Install NRV : -
Drillpipe Dart Gray Valve
3) Determine the close end displacement of drill string Example:
Hole Size - 8 3/8" 5" DP Cap = 0.01776 bbls/ft Drill Pipe Size - 5" 5" DP Displ. = 0.0076 bbls/ft
Closed in Displacement
= = =
Capacity + Open End Displacement 0.01776 bbls/ft + 0.0076 bbls/ft 0.02536 bbls/ft
4) Determine hydrostatic pressure per barrel of mud. Example:
Hydrostatic
Hole Size 8 3/8" Mud Weight 18 ppg Drill Pipe Size 5" =
Gmud psi/ft Annulus Cap bbls/ft
=
0.052 X WT ppg D2 - d 2 bbls/ft 1029.4
(
=
( =
= 10 - 2
)
0.052 X 18 8 3/82 - 52 1029.4
)
0.938 0.04385 21.35 psi/bbls
HPHT Course - Section 10
5) Estimate surface pressure rise when BHA enters influx. Example 1: Hole Size 8 3/8" Mud Weight 18 ppg Influx Gradient converted to ppg 16 ppg Influx Volume 10 bbls BHA O.D. 6 1/2" Max Surface Pressure Increase =
1 1 0.433 X 1029.4 X (MW - Influx MW) X Influx Vol X (D2 - d2) - D2
=
0.433 X 1029.4 X (18 - 16) X 10 X
(
)
1 (8 3/8 - 6 1/22)
(
=
53.53 X 2 X 10 X [0.03585 - 0.01426]
=
23 psi
2
1 8 3/82
)
Example 2: Hole Size 8 3/8" Mud Weight 18 ppg Influx Gradient converted to ppg 2.9 ppg Influx Volume 10 bbls BHA O.D. 6 1/2" Max Surface Pressure Increase
(
)
=
1 1 0.433 X 1029.4 X (MW - Influx MW) X Influx Vol X (D2 - d2) - D2
=
0.433 X 1029.4 X (18 - 2.9) X 10 X
1
((8 3/8 -6 1/2 )
=
53.53 X 15.1 X 10 X [0.03585 - 0.01426]
=
175 psi
2
2
-
1 8 3/82
)
6) Determine overbalance margin and allow annulus pressure to rise. Maintain overbalance between 50 to 200 psi 7) The following points are possible recommendations by a manufacturer concerning their annular when performing stripping operations. Stripping Operations Manufacturer's Recommendations : a) Allow a slight leak by annular when stripping for lubrication purposes. b) When closing on anything which is not moving use the manufacturer's recommended closing pressure, 10 - 3
HPHT Course - Section 10
8) Strip in the Hole. -
Drill floor remove burrs from Tooljoint & Dope.
-
Reduce running speed as tooljoint travels through annular.
-
Bleed off mud volume when drill string is stationary, at connections.
-
Fill drill string while RIH and completely fill every 5 stands.
-
Post person at BOP Driller's panel for shut in purposes in case of annular failure.
10.3 RAM COMBINATION STRIPPING PROCEDURE The following procedure can be used as a guideline for the implementation of annular to ram stripping. The procedure for ram to ram stripping is similar. 1.
Monitor surface pressures and establish initial shut in conditions.
2.
Install NRV :
3.
Determine the close end displacement of the drillpipe.
4.
Determine hydrostatic pressure per barrel of mud.
5.
Estimate the surface pressure rise when BHA enters the influx.
6.
Check ram spaceout by : A) Ensuring the distance below the Drill Floor to the two preventers to be used for stripping is known.
-
Drillpipe Dart Gray Valve
B) Ensuring the distance between the two preventers to be for stripping has enough length to fit a drill pipe tool joint connection plus 4 to 6 inches extra. 7.
Isolate the accumulator bottles at full operating pressure. Note:
10 - 4
It is a good practice to keep the accumulators as back-up in the event of pump failure.
8.
Allow the surface pressure to increase by the overbalance margin.
9.
Reduce annular closing pressure to recommended manufacturer values for stripping and begin stripping operations.
HPHT Course - Section 10
10. Stop when tool joint is above top preventer. 11. Close lower preventer at normal regulated manifold pressure. 12. Bleed off cavity pressure between the preventers. Note:
Before opening the top preventer it will be necessary to bleed down the pressure below it.
13. Reduce lower preventer operating pressure. 14. Open top preventer and strip in. 15. Stop stripping when tool joint is just below top preventer. 16. Close top preventer at maximum operating pressure. 17. Pressurise the cavity between the two preventers to equalise across them. Note:
Do not use wellbore pressure to equalise across this space.
18. Reduce top preventer closing pressure. 19. Open lower preventer. 20. Continue to strip in according to the above procedure. Note: Fill the drillstring as required when stripping in.
10 - 5
HPHT Course - Section 10
10.4 SAFETY MARGIN (OVERBALANCE) AND OPERATING MARGIN SAFETY MARGIN
150
250
OPERATING MARGIN
Pore P ressur e
0
4,500
1300 SAFETY MARGIN 1417
MAASP
1,500
PRESSURE GAUGE (psi)
3,000
Closed End D.P. Disp. = 0.02536 bbls/ft Stand = 93.9 ft Stand = (approx.)
9 5/8"
10,900 ft
27.7 Stands (approx.)
MAASP = 1417 psi
10 - 6
13,500 ft
10 bbls
8 1/2" TVD
HPHT Course - Section 10
10.5 RECORDING OF DATA IN A KICK AND/OR STRIPPING OPERATION 10.5.1 Recording of Data in a Kick Operation. It's extremely important that good relevant data gets recorded when a well control incident occurs. It cannot be stressed enough how vital recorded information will be in determining future courses of actions and assisting in learning from an unscheduled event. It is the Driller's sole responsibility to accurately record all relevant information during a well control situation. The Mud Loggers, if onboard, will provide back-up recording information to the Driller. It will be the Driller's responsibility to advise the necessary supervisory staff plus the Mud Loggers should a well control event occur. The Mud Loggers once informed will switch their equipment to well control status and establish running logs and tables as accurately as possible. The minimum information a Driller should record during a well control situation is listed as follows. Mud Loggers should record and duplicate this information. 1) Time, Depth, Operations in progress, Shut-in Pressures and Kick Volume Amount when incident initially occurs. 2) A well kill sheet will be completed for the incident. 3) Start of time of Killing Operation and Method used. 4) Time, Strokes and Pressure, when Kill Mud is at Bit. 5) Estimated Time of Influx at Shoe. 6) Time and Gauge Pressure when Influx at Surface. 7) Time and Gauge Pressure when old Mud behind Influx at Surface. 8) Time and Gauge Pressure when Kill Mud at Surface. 9) Time of Opening BOP's to Circulate up an open Annulus to add in Trip Margin. 10) Start and Completion of time when Removing Trapped Gas in BOP's. 11) Time of any unusual events during the Well Kill. 12) Choke Operations and Pump Operations during the Kill. 13) BOP device the well is closed in on. 14) Time of resumption of normal operations. It is strongly recommended that the Driller assign a dedicated person to record data during the kill operation. This leaves the Driller's hands and mind free to concentrate on the kill. Verbal instruction can then be passed to the recorder for recording purposes. 10 - 7
HPHT Course - Section 10
10.5.2 Recording of Data in a Stripping Operation. In a stripping situation the Driller or Toolpusher will assign a permanent person to record and fill out the Stripping Sheet Data. STRIPPING WORKSHEET Well No.
Rig
Bit Depth
Date & Time
TD
MW in Hole
Safety Margin (Overbalance)
psi
Page No. Lub. MW
Operating Margin
Closed End Drill Pipe Displacement
per/ft.
psi
per/stand
Volumetric Well Control Information Psi per bbl of Psi per bbl of Psi per bbl of Psi per bbl of Time (Hr/Min)
10 - 8
ppg Mud in ppg Mud in ppg Mud in ppg Mud in Operation
Surface PSI
Change in Surface PSI
x x x x Bit Depth
Annulus = Annulus = Hole = Hole = Pipe Stripped
PSI of Mud Bled/Lub
psi/bbl. psi/bbl. psi/bbl. psi/bbl. Over Balance
Vol of Mud Total Vol Bled/Lub of Mud
• ABE
RD
CONTENTS
11.1
EFFECTS OF PRESSURE AND TEMPERATURE ON DENSITY.
11.2
SURFACE DENSITY VARIATIONS WITH TEMPERATURE
11.3
TEMPERATURE OF MUD IN THE CHOKE LINE
11.4
TEMPERATURE AND PRESSURE EFFECTS ON RHEOLOGY OF MUDS
11.5
REFERENCES FOR SECTION 11
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11. THE EFFECTS OF TEMPERATURE AND PRESSURE ON MUDS
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11.1 EFFECTS OF PRESSURE AND TEMPERATURE ON DENSITY Liquids are not totally incompressible and those compressibilities are themselves influenced by temperature and pressure. Compressibility is usually defined as : Compressibility = Change of volume per unit volume per unit of pressure. = bbl/bbl/psi = 1/psi. ie c = ∆V VxP An indication of compressibilities of typical OBM base oils and saturated NaCl brine is given in FIG 11.1 below:FIG 11.1 Pressure psig
Compressibility 1/psi Base oil
2500 15000 2500 15000
Temperature °F
NaCl Brine
0.0000050 0.0000031 0.0000100 0.0000048
0.0000016 0.0000019 0.0000028 0.0000033
78 78 350 350
Changes in compressibility cause changes in density which lead to differences between the common “isothermal” calculations of downhole pressures and the actual downhole values. Under certain circumstances this may lead to a real value of downhole pressure which may be either higher or lower than the basic calculated value. This has obvious implications on pressure control whilst drilling and tripping, apart from any influences on other rheological properties. Density of a material is defined as : w = mass/volume
11 - 2
HPHT Course - Section 11
Referring to FIG 11.2, the effects of changes in pressure and temperature can be reasoned, as follows: (a)
Increasing pressure: As pressure increases with depth into a well, then the compressibility reduces the volume, whilst mass stays the same. Thus density is increased with pressure.
(b)
Increasing temperature. As depth increases in a well, temperature also (generally) increases. Liquids expand with temperature and consequently the volume increases and thus the density decreases. FIG 11.2
START DENSITY
Increase Temperature
Increase Pressure
HIGHER DENSITY
? =
LOWER DENSITY
The simple isothermal formula for hydrostatic pressure is written as : Phyd = c x density x TVD
Eqn [11.11]
This assumes that the density does not change with depth. This assumption itself additionally assumes that the increase in density due to pressure effects is balanced exactly by the reduction in density due to temperature effects within a well. This assumption is not necessarily correct. The effects of temperature and pressure on the compressibility and density of 2.041 SG (17 ppg) oil-based muds are shown, at constant temperature conditions of 78°F and 350°F, in FIGS 11.3(a) and (b), and the implications of those upon static (isothermal) density (at 78, 200 and 350°F) are shown in FIG 11.4.
11 - 3
HPHT Course - Section 11
FIG 11.3(a) and (b) 350°F
6.0e-6
78°F
COMPRESSIBILITY (1/psi)
COMPRESSIBILITY (1/psi)
4.0e-6
2.0e-6
17-lbm/gal Muds Diesel Oil Mud Mineral Oil Mud A Mineral Oil Mud B
4.0e-6
2.0e-6
17-lbm/gal Muds Diesel Oil Mud
0.0e+0
Mineral Oil Mud A
0
5000
10000
15000
Mineral Oil Mud B
PRESSURE (psig)
0.0e+0 0
5000
10000
15000
PRESSURE (psig)
FIG 11.4 18.0
78°F
17.5
DENSITY (lbm/gal)
200°F
17.0 350°F
16.5
17-lbm/gal Muds
16.0
Diesel Oil Mud Mineral Oil Mud A
15.5
Mineral Oil Mud B 15.0 0
5000
10000
15000
20000
PRESSURE (psig)
Temperature profiles in flowing wells differ from static or geothermal profiles, the mud generally being cooler whilst circulation is in progress. Also, the mud is warmer when moving up the annulus than when pumping down the drillstring. Typical flowing and static temperature profiles, from reference 2, are shown in FIG 11.5. Those have been used to show the effects of compressibility and temperature on actual downhole mud density pressure, as shown in FIGS 11.6(a) and (b) from reference 2.
11 - 4
HPHT Course - Section 11
FIG 11.5 MUD TEMPERATURE VS. DEPTH 0
➝
➝
5,000 ft, 300 gpm
5
➝
25,000 ft, 300 gpm 15
➝
DEPTH (1.000 ft)
➝ 15,000 ft, 300 gpm 10
TG = 0.020oF./ft
➝
20
25 0
100
200
300
400
500
600
700
TEMPERATURE (OF) MWO VSO VCO 13.50 23.00 0.0
VWO VDO 77.00 0.0
FIG 11.6(a) and (b) ∆ PRESSURE VS. DEPTH
∆ MUD WEIGHT VS. DEPTH 500
0.50
∆ PRESSURE (psi)
∆ MUD WEIGHT (ppg)
0.25 0 -0.25 -0.50 -0.75
0
-500
-1 -1.25 -1.50
-1,000 0
5,000
10,000
15,000
20,000
25,000
0
5,000
DEPTH (ft) MWO 13.50 13.50 13.50 13.50 13.50 13.50
VSO VCLO VWO VDO TG GPM 23.00 0.0 77.00 0.0 0.010 0 23.00 0.0 77.00 0.0 0.012 150 23.00 0.0 77.00 0.0 0.014 300 23.00 0.0 77.00 0.0 0.016 0 23.00 0.0 77.00 0.0 0.018 150 23.00 0.0 77.00 0.0 0.020 300
10,000
15,000
20,000
25,000
DEPTH (ft) MWO 13.50 13.50 13.50 13.50 13.50 13.50
VSO VCLO VWO VDO TG GPM 0 23.00 0.0 77.00 0.0 0.010 23.00 0.0 77.00 0.0 0.012 150 23.00 0.0 77.00 0.0 0.014 300 0 23.00 0.0 77.00 0.0 0.016 23.00 0.0 77.00 0.0 0.018 150 23.00 0.0 77.00 0.0 0.020 300
11 - 5
HPHT Course - Section 11
It can be seen that, for the conditions specified, bottom hole pressures at 20000 ft (6100 m) may be about 400 psi less than those anticipated by the constant temperature hydrostatic pressure formula. The implications of such pressure reductions on pressure control and on the potential for swabbing must be noted. An analysis has been made using the above graphs for a nominal 17 ppg OBM at depths to 16000 ft (4875 m), with a circulating temperature gradient of 1.5°F/100ft (4.94 °F/100m). The results are shown in FIG 11.7 and indicate that the static bottom hole pressure may be about 156 psi less than that calculated by a constant 17 ppg density assumption, which would have given a pressure of 14144 psi. FIG 11.7 Depth ft.
Temp °F
2000 4000 6000 8000 10000 12000 14000 16000
110 140 170 200 230 260 290 320
Density ppg 16.95 16.90 16.85 16.83 16.79 16.77 16.72 16.69
Pressure psi 1763 3521 5273 7023 8840 10608 12252 13988
Change ÎP psi -5 -15 -31 -49 -71 -95 -124 -156
It has also been estimated that for a water based mud with a starting density of 17ppg, with a similar circulating temperature profile, the reduction in bottom hole pressure would be about 105 psi below the constant density value.
11 - 6
HPHT Course - Section 11
11.2 SURFACE DENSITY VARIATIONS WITH TEMPERATURE. It can readily be deduced from FIG 11.4 that even at atmospheric pressure, as at the flowline, the effects of temperature can influence the mud density. This is shown in FIG 11.8 for a range of 90:10 oil based muds with SG’s ranging from 1.8 to 2.2 over a range of possible surface temperatures from 30 to 210°F.
TEMPERATURE (Deg F)
100 110 120 130 140 150 160 170 180 190 200 210 60 50 40 1.7
1.8
1.9
2.0
2.2
2.1
DENSITY (SG)
2.3
30
A
90:10 oil mud
1.862 SG
70
80
90
1.8 SG
B
1.9 SG
2.0 SG
2.1 SG
2.2 SG
REFERENCE TEMPERATURE = 120°F
FIG 11.8
11 - 7
HPHT Course - Section 11
To standardise the reporting of mud densities some companies now ask that all mud densities at the surface be corrected to a standard reference temperature. In this graph, the reference temperature is 120°F ie a 2.0 SG mud has a specific gravity of 2.0 at 120°F. and the graph is interpreted as follows :
Temperature °F
SG
30 80 100
2.055 2.02 2.01
120
2.00
150 200
1.98 1.95
Reference density at 120 °F.
This indicates that at temperatures below 120°F density is higher, at temperatures above 120°F density is lower.
11.2.1
WORKED EXAMPLE :
A 90:10 OBM has an input SG of 1.9 at 110°F. The flowline temperature is 160°F and the SG is measured as 1.88. Calculate the cuttings load, in SG terms, in the flowline mud. Solution. The mud inlet SG is 1.90 at 100°F. Draw a line AB from the 1.9/100°F point parallel to the 1.90 SG line. Read the SG of this line AB at the 160°F point. The value of this is 1.862 SG. Thus at 160°F, the cuttings load in the annulus is:
∆SG = 1.88 -1.862 = 0.018 SG
11 - 8
HPHT Course - Section 11
11.3 TEMPERATURE OF MUD IN THE CHOKE LINE As mud/gas rise within the annulus, it is cooled from the circulating bottom hole temperature down to the mud temperature at the subsea BOP. As the mud/gas then rises up the choke line, it is further cooled to the temperature at the surface choke. The degree of this cooling depends upon: (a)
The velocity of the flow in the chokeline and hence the friction “heating” effect.
(b)
The time interval during which the mud is moving from the BOP to the surface. The longer this is, the greater is the cooling effect.
Generally the higher the circulation rate, then the higher will be the choke line temperature, for the same starting BOP temperature. For a specific rig/well conditions those are shown in FIGS 11.9(a) and (b), for 12.25 and 8.375 inch open hole sections. FIG 11.9(a) and (b) 12 1/4" Hole Section
8 3/8" Hole Section
180
140 170
130
160
120
TEMPERATURE (°F)
TEMPERATURE (°F)
150 140
130
120
110
100
110
90 100
80 90
80
70 0
70
0
0.5
1.0
1.5
2.0
0.5
1.0
1.5
2.0
2.5
MUD FLOW RATE (bpm)
2.5
MUD FLOW RATE (bpm)
110
130
150
170
Mud Temperature at BOP (°F)
193
110
120
130
140
147
Mud Temperature at BOP (°F)
It should also be noted that those are for conditions when mud is present in the system. If a situation arises where the annulus becomes filled with gas which is flowing rapidly, then the BOP and the surface choke temperatures may be substantially higher than indicated, as shown in FIG 11.10. This applies to a computer model study for the flow of gas for a 12 hour period at different flowrates with a bottom hole temperature of 350°F. 11 - 9
HPHT Course - Section 11
FIG 11.10 300
250
Temperature at Sub-Sea BOP °F
Predicted BOP Temp °F 200
150
Predicted Surface Choke Temp °F 100
B.H. Temp = 350°F Water Depth = 300 ft B.H. Press = 14000 psi 50
20
40
60
80
100
120
140
160
Gas Flowrate MMSCF/Day
11.4 TEMPERATURE AND PRESSURE EFFECTS ON RHEOLOGY OF MUDS Many papers have been produced regarding the downhole effects of temperature and pressure upon the downhole rheology of drilling fluids. Reference 3 below gives some interesting data relating to the PV, Yield and filtration characteristics of a range of oil-based muds at elevated temperature and pressure. It is concluded that for such muds there is a relatively simple linear log relationship between PV and the value of temperature expressed as 1000/T°F, although the relationship for change of viscosity for water-based muds was a direct linear relationship with temperature. It should be stressed that swabbing effects under the bit depend largely upon the PV and that those will not only change with tripping speed per stand but also with the temperature profile in the well. It is likely that at higher pulling rates there is little difference in swab pressure predictions between power law and Bingham plastic models, but at slower tripping rates the power law model is likely to give more reliable predictions of swab pressure. Some typical PV-Temperature graphs for oil-based and water based muds are shown in FIG 11.11. 11 - 10
HPHT Course - Section 11
FIG 11.11 70
VISCOSITIES OF 1.92 SG (16 ppg) MUDS AT 5,000 psia.
65
B
60 55
MUD VISCOSITY cP
50
A
45
A = LT Oil Based 90:10 OWR.
40
B = Lignosulfonate Mud.
35
C = Lime/Polymer Mud.
30 25
C
20 15 10 5 0 100 °F
200 °F
300 °F
400 °F
MUD TEMPERATURE °F
11.5 REFERENCES FOR SECTION 6 (1)
A Model for Predicting the Density of Oil-Based Muds at High Pressures and Temperatures. By E.K.Peters, M.E.Chenevert and C.Zhang. SPE Drilling Engineering, June 1990, pp141-148.
(2)
Here’s How Compressibility and Temperature Affect Bottom-Hole Mud Pressure. By L.L.Hoberock, D.C.Thomas and H.V.Nickens. Oil and Gas Journal, March 22nd 1982, pp159-164.
(3)
Physical Properties of Drilling Fluids at High Temperatures and Pressures. By J.V.Fisk and D.E.Jamieson. SPE Drilling Engineering, December 1989, pp341-346.
11 - 11
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12.0 THE EFFECTS OF BOREHOLE BALLOONING ON DRILLING RESPONSES 12.1 THE PLASTICITY CONCEPT 12.2 THE INSTABILITY "MECHANISM" 12.3 REFERENCES FOR SECTION 12
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12. THE EFFECTS OF BOREHOLE BALLOONING ON DRILLING RESPONSES
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HPHT Course - Section 12 12.0 THE EFFECTS OF BOREHOLE BALLOONING ON DRILLING RESPONSES It has been reported, as in the reference below, that on a number of occasions, with deep HP/HT wells, there have been surface indicators which have been contradictory to each other, particularly with respect to the behaviour of drilled and connection gas. It is suggested that, on occasion, this has led senior personnel to take actions which at the time seemed logical but which, in hindsight, proved to be erroneous. It has been established over many years that borehole stability is one of the essential features of safe and efficient drilling and shale stability or rock stability is of importance in this respect. When a rock or shale behaves in a stable way then problems such as sloughing shales do not occur. The opposite is also the case: when a shale or a rock behaves in an unstable way, then borehole problems show up. 12.1 THE PLASTICITY CONCEPT The instability "mechanism" is in some ways similar to the plastic behaviour of salt beds. Where a formation, such as a salt bed, overlies a potential producing zone below, then plasticity of the salt bed can lead to substantial over-pressure in the zone below it, as shown in FIG 12.1, due to the fact that the salt bed cannot support its correct share of the overburden load. FIG 12.1
Normal Press. grad. 1.074 SG
Overburden = 2.31 SG 2000 m
Plastic Salt Bed O/B = 2.5 SG Overpressured
150 m
Pore Pressure = 2.32 SG
It has been demonstrated that if shales are either over or under-pressurised, then they also can behave in a plastic manner which leads to bore hole instability. Suspicions about this type of formation behaviour may be raised by : (a) Conflicting surface responses in relation to gas levels and flow checks. (b) Small SIDPP values after a small flow. 12 - 2
(c)
Inaccurate pore pressure measurements from logs.
HPHT Course - Section 12
12.2 THE INSTABILITY "MECHANISM" A shale stability diagram is shown in FIG 12.2, as in the reference given. Where a shale is under or over-pressurised from the mud, it is then possible for that shale to behave in a plastic mode. Two possible conditions may arise : FIG 12.2
Un
de rb
ala Pla nc et sti oc cB Un au eh der se bal av co anc lla e to iou ps e ind r uce slou Stable Sh ghin ale
4
3
2
1
0
13 12
Fracture
e
5
14
r e ur ou ct vi fra ha
6
Underbalance, ppg
15
e
7
16
us
8
Shale ballooning
17
B g ca tic oonin to ll as ce Pl ce ba an al du n oi et nc hale ala erb le S Ov Stab
Collapse
18 rb ve O
g
Shale sloughing
Natural pore pressure of shale body, ppg
Pressure Imbalance and Induced Plastic Flow
11 10
1
2
3
4
5
6
7
8
Overbalance, ppg
Case (a) When the shale is being drilled underbalanced From the above diagram, if the shale is being drilled underbalanced, into its plastic mode, then the shale sloughs into the wellbore. eg a shale with a pore pressure of 13 ppg (1.56 SG) could be safely drilled underbalanced with mud as low as 11.5 ppg (1.38 SG), but with a mud of 11 ppg, the shale would behave plastically and slough into the wellbore. Case (b) When the shale is being drilled overbalanced For the same 13 ppg (1.56 SG) pressurised shale, it could be safely drilled by at least 2.5 ppg overbalance, ie with 15.5 ppg (1.86 SG) without showing signs of plastic instability. However, with 16.5 ppg mud (1.98 SG), it is likely that it would deform in an outward or ballooning plastic mode. When a shale balloons outwards, it exerts extra pressure upwards and downwards and thus may generate over-pressures in adjacent formations. It is apparently possible to transmit such over-pressures to gas stringers both below and above the plastic formation, resulting in gas flows from such zones which are anomalous to their pore pressure behaviour. Also, it can be seen that, as the natural pressure of the shale increases, the margin of tolerance to cause such plastic behaviour diminishes : a 17 ppg (2.04 SG) shale may require only about 0.8 ppg to cause it to behave in this way. 12 - 3
HPHT Course - Section 12
When such a shale behaves in a plastic mode it effectively causes the borehole diameter to expand as a balloon. While circulating, additional over-pressures are applied by the APL thus expanding the wellbore further. When circulation stops, the wellbore "balloon" is allowed to relax again as the added over-pressures are removed. It is suggested by the writer of the reference that this may cause a number of indicators at the surface : (a) Drilling rate appears to be insensitive to weight-on-bit. If plasticity is present, then the over-pressures are transmitted ahead of the bit and the bit always appears to be drilling as if on balance. (b) The well appears to take fluid whilst circulating and to flow fluid back when circulation is stopped due to the ballooning effect. For instance, it is estimated that a nominal 8 inch hole may balloon to 9 inches. If this happens over a 2000 ft long section, the hole volume may be 17 bbl larger whilst circulating than with the pumps off. (c) Even after mud density may have been increased, there may still be increasing gas levels. If there is a SIDPP which approximates to or is slightly less than the APL, it is possible that this may be caused by the ballooning effect, which is shown in FIG 12.3. FIG 12.3 Borehole Wall Flexing 2,000 + units reflex gas expanding at surface
10,000 ft
Zone of induced pressure
17.5 ppg mud
(Extends some 1,000 ft around wellbore)
17.5
17.5
17.5
17.5
Borehole wall "balloons" or breathes
"Natural" shale pressure
"Natural" shale pressure
(16.0 ppg)
(16.0 ppg)
17.5
14,000 ft Induced pressure precedes drill bit, increasing drilling rate
12 - 4
Borehole flexing "milks" sand stringers producing 2,000 + units of reflex gas or CI
HPHT Course - Section 12
Where such confusing indicators exist, it is suggested that all indicators should be carefully examined before specific action is taken. If ballooning is suspected, it may be necessary to maintain mud weight rather than increase it. Great care needs to be taken in trying to interpret what the hole is telling. On occasion, when successive increases in gas level have led to mud weight increases, due to SIDPP values, it may be necessary to consider the effects of bleeding off some pressure at the choke with the well shut in. In the case of a "normal" influx situation, the effects of opening the choke to bleed off and then closing the choke again should lead to (i) an increase in choke pressure (more influx has been taken) and (ii) the SIDPP should remain unchanged while (iii) the pit gain rises slightly. In the case of wellbore ballooning, the effects of opening the choke should give the following : (i) The choke pressure should either stay the same or drop when the choke is closed again. (ii) The SIDPP should drop by a little, as the ballooning effect is allowed to relax, when the well has been shut in again. IT CANNOT BE OVER-EMPHASISED THAT THIS PROCEDURE IS ONE WHICH SHOULD BE TAKEN ONLY AFTER FULL CONSULTATION WITH ALL SENIOR PERSONNEL. While this material and the indicated reference have been written with respect to shales, there have been indications that this problem has arisen in HPHT wells in shales, limestones and sandstones in deep Jurassic sections in proximity to gas sands when ECD effects were substantial. One way of reducing the ballooning may be to circulate slowly and to minimise APL effects. 12.3 REFERENCE FOR SECTION 12 " How Borehole Ballooning Alters Drilling Responses." By J.A. Gill. Oil and Gas Journal, March 13th, 1989, pp43-52.
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CONTENTS
13.1 RESPONSIBILITIES OF THE OIL COMPANY REPRESENTATIVE 13.2 PLANNING OF OPERATIONS 13.3 DRILLING PROGRAMME 13.4 TYPICAL REPORTING RELATIONSHIP 13.5 FIELD AND OFFICE COMMUNICATIONS 13.6 RIG SITE COMMUNICATIONS 13.7 HPHT KICK HANDLING
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13. MANAGEMENT OF OPERATIONS
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HPHT Course - Section 13
13.1 RESPONSIBILITIES OF THE OIL COMPANY REPRESENTATIVE It is the sole responsibility of the Oil Company Representative to ensure that Drilling Operations are conducted with due regard to safety and well control. It is the Representative’s duty to:-
Ensure that Company policies and instructions are properly given, and that they are properly understood and implemented.
-
Familiarise him/herself with the environment in which he/she is operating.
-
Review the Well Plan (Drilling Programme) in detail.
-
Advise the Office Management of the day to day progress and of any aspects of the prognosis or well plan which might cause the loss of well control.
-
Understand rules and regulations of the Government of which the field operation is in and ensure compliance.
-
Ensure contractor’s emergency procedures manual and operating/safety procedures conform to the Government regulations and Contractor complies with all requirements.
-
All personnel are fully familiar and trained in well control procedures.
-
Pressure tests and drills are carried out in accordance with procedures specified.
-
Mud logging personnel are fully familiar and experienced in over-pressure prediction, and all other aspects relating to data monitoring for well control.
-
Ensure calculated mud weights provide sufficient overbalance to control the well.
-
The cement unit is fully operational at all times.
The responsibilities of the Oil Company Representative does in no way reduce those of the Drilling Contractor, with regard to well control and the safety of the installation and the personnel onboard. It is the ultimate responsibility of the Drilling Contractor’s Senior Person-in-Charge, commonly referred to as the OIM, to ensure the safety of the installation and its personnel. Should a conflict occur between the objectives of the well and the Rig Personnel or well safety, the OIM will have the final decision. A typical Field Reporting Relationship Schematic is included (see 13.4). 13 - 2
HPHT Course - Section 13
13.2
PLANNING OF OPERATIONS
The procedures will cover the operating practices and minimum equipment requirements so that safety of personnel and equipment is achieved. A thorough review of the intended operation will be made to effect proper planning, training and good oil field practices. Before operations commence: -
Close scrutiny of all safety aspects of each step of any proposed programme.
-
The capability to deal effectively with non-anticipated situations.
-
Ensuring responsibilities are clearly defined for all well control considerations.
When operations are extended to involve work classed as “High Pressure High Bottomhole Temperature” specialized drilling and well control procedures with increased equipment considerations and training will be specified and implemented. 13.3
DRILLING PROGRAMME
The drilling programme is a written document for the intention of covering all details in managing and conducting a drilling operation. It is produced by the drilling department and used as a information source in achieving the operation’s objectives. Based on available well data it provides, with as much accuracy as possible, information on: -
Well Targets.
-
Characteristics of formations (i.e. porosity, permeability, fluid types, gas zones, lost circulation etc).
-
Abnormal pore pressures and expected formation strength gradients at the proposed casing setting depths.
-
The deviation control programme (this is issued for all wells including intended straight holes).
-
The sequence of operations.
-
Any shallow gas predictions and shallow gas procedures.
-
Hole sizes with recommended drilling assemblies.
13 - 3
HPHT Course - Section 13
-
Indicates when formation integrity tests (leak-off tests) are required to confirm formation strength gradients.
-
Minimum leak-off values required to maintain kick tolerance.
-
Special instructions including any abnormalities that may be encountered.
-
Casing, cementing and mud programmes.
Any deviation from the Drilling Programme will need to be confirmed and approved by the Oil Company Drilling Manager. 13.4
O N S H O R E
O F F S H O R E
TYPICAL REPORTING RELATIONSHIP
DISTRICT MANAGER
OIL COMPANY
DRILLING CONTRACTOR
DRILLING MANAGER DRILLING SUPERINTENDENT
RIG MANAGER SENIOR DRILLING ENGINEER
DRILLING ENGINEER
OIL COMPANY REPRESENTATIVE
OIM
LINE REPORTING CONTRACTUAL REPORTING COMMUNICATION LINE
SERVICE PERSONNEL
TOOLPUSHERS
DRILLER
DRILL CREW
13 - 4
HPHT Course - Section 13
13.5 FIELD AND OFFICE COMMUNICATIONS Each operation should have a minimum of two modes of communication between the office and field operation. The Oil Company Rig Site Representative should communicate with his/her Office Drilling Superintendent or the person designated daily. Should field operations warrant, communication between the two will occur as many times throughout the day as required. The Drilling Contractor should establish lines of communication between the office and field operation in accordance with their operating policy. This policy should follow along similar lines as practised by the Oil Company. The Oil Company office and the Drilling Contractor’s office should communicate with each other as required. Daily communication while drilling below the last casing seat above the HPHT section should take place. This frequency should increase if field operation concerns become apparent. All Oil Company office personnel as well as the Drilling Contractor’s personnel who have a position of responsibility over the field operation should have provided, modes of communication, (e.g.) pagers, mobile telephones etc., thereby being available on a 24 hour basis.
13.6 RIG SITE COMMUNICATIONS A Daily Operations Meeting should be held on the rig by the Senior Rig Staff. In attendance will be the Oil Company personnel, Senior Drilling Contractor personnel and Third Party Personnel directly involved in well operations, such as the Mud Engineer, Mud Logging Engineer and Cementer. This meeting will be chaired by the OIM and will discuss current and planned operations. Recording of this meeting will be documented in the vessel log book. Briefings, from the Daily Operations Meeting, to the crews will be passed on by those in attendance. All instructions to the Driller should be in written form and posted on the drill floor, and a copy kept on file. All crews should start each working shift with a brief meeting, stressing Safety Awareness for procedures and practices to be followed. Each crew member should have a short hand-over with his counterpart. This person should bring to his Supervisor’s attention anything out of the normal practice. The Supervisor should correspondingly discuss any points he/she feels needed with the person in charge, so all personnel are fully conversant with the operations and conditions present. Rig Safety Meetings should occur as normal in field operations. The out of norm procedures and practices will be highlighted in each meeting where crews have open discussions increasing their safety and operational awareness. 13 - 5
HPHT Course - Section 13
In the event of an emergency, the installation OIM will be responsible to initiate his own Emergency Procedure and also report the incident to the Oil Company Office. For out of office hours the Oil Company on duty person should be called. Oil Company & Drilling Contractor personnel will then follow the procedures laid down in the Emergency Procedures Manual. Oil Company personnel should also ensure that the installations owners management and duty personnel are alerted and stand-by for assistance.
13.7
HPHT KICK HANDLING
The OIM will be in charge in any kick situation. Consideration for moving the installation off location (if a mobile unit) should be made if an emergency well control situation is deteriorating to the extent where the risk to personnel and/ or the installation is becoming evident. This decision should be made after consultation with key members of the offshore management team. Consultation with shore based operational personnel can be made, but due to the gravity of the situation, it may not be possible or warranted.
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CONTENTS
• BOP SCHEMATIC • CHOKE AND STANDPIPE MANIFOLD SCHEMATIC • SPIRO TORQUE CENTRALISERS TO AVOID DIFFERENTIAL STICKING • MUD GAS SEPARATOR - DESIGN & OPERATING GUIDELINES • WELL CONTROL PROCEDURES
1.1 1.2 1.3 1.4 1.5 1.6
General HPHT Drilling Policies and Procedures HPHT Tripping Procedures HPHT Coring Procedure Suspension of Operations Casing Wear
• WELL CONTROL DECISION TREES • ROLES AND RESPONSIBILITIES DURING A WELL CONTROL INCIDENT
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14. SAMPLE HPHT WELL CONTROL PROCEDURES (SEMI)
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HPHT Course - Section 14
Riser Extension Kill Line
Choke Line Flex Joint
13 5/8" Annular Kill Line Temp. Sensor
Temp. Sensor Test Valve
Test Valve Mini Collet Connector
Mini Collet Connector
Cameron Collet Connector Upper Outer Kill Valve Upper Outer Choke Valve
Upper Inner Kill Valve
Upper Inner Choke Valve
Shear/Blind Rams 5" Pipe Rams 31/2" Pipe Rams
Lower Outer Choke Valve Lower Inner Choke Valve
Lower Outer Kill Valve Lower Inner Kill Valve 5" Pipe Rams
Wellhead Connector
14 - 1
HPHT Course - Section 14
10" VENT UP DERRICK
HOT MUD RECIRCULATING LINE
6" VENT
28' - 8 1/2" ABOVE MAIN DECK 10" DOWN TO SHAKER HEADER BOX
THERMO-COUPLE AND PRESSURE TRANSDUCER FLANGE
FLOW LINE
18"
BY-PASS PRESSURE (psi)
THROUGHPUT PERFORMANCE AT 60 DEG F.
50.0
30
47.6
28
45.2
26
42.8
24
40.4
22
37.9 35.5
AD LO N U
18 16 14 12
D OA L UN
10
H IT W
6
N GI AR M I PS
33.0 30.4 27.8
22.4 19.5
6
16.4
4
13.0
2
8.9 8
20" PIPE X - STG
25.1
8
0
10" PIPE Sch. 80 INSIDE
6" TO TRIP TANK
9 10 11 12 13 14 15 16 17 18 19 20 FLUID DENSITY Lb/gal
MUD GAS SEPARATOR FLOW CAPACITY CURVE
14 - 2
GAS FLOW (mm scf/day)
32
20
10" CLEAROUT
27' - 5"
24' - 4"
3', 1"
10" Sch. 80 PIPE
MUD HEAD
HPHT Course - Section 14
VENT TO TOP OF DERRICK 10" VENT LINE
MGS PRESSURE SENSOR
8 FROM C & K MANIFOLD, 4" PIPE
36" DIAMETER MUD - GAS SEPERATOR
DOWNSTREAM CHOKE TEMP. SENSOR
DRILL FLOOR LEVEL
REMOTELY ACTUATED VALVES
6
TO MUD/GAS SEPARATOR
TO SHALE SHAKER
MANUAL CHOKE
REMOTE CHOKE
MANUAL CHOKE
5
REMOTE CHOKE TO PORT FLARE LINE
MAIN DECK LEVEL
DIP TUBE PRESSURE SENSOR
6 Meters TO STARBOARD FLARE LINE
7 UPSTREAM KILL LINE TEMP. SENSOR
4
DATA MONITORING SYSTEM AND BYPASS CONTROL UNIT STBD
MGS
PORT
DIP TUBE PRESSURE
7
OPEN CLOSED
OPEN CLOSED
PRESSURE
8
TEMP.
GLYCOL INJECTION POINT
TO SHALE SHAKER
BOP
MGS OPEN CLOSED
DOWNSTREAM CHOKE TEMP. SENSOR
TO CEMENT UNIT MUD PUMPS
1,2
UPSTREAM CHOKE LINE
KILL LINE
CHOKE LINE
3
TEMP.
UPSTREAM CHOKE TEMP. SENSOR
3
DECK LEVEL
UPSTREAM KILL LINE TEMP.
VALVE STATUS ALARM
4
DOWNSTREAM CHOKE TEMP.
REMOTE CHOKE AREA
5,6
SEA LEVEL
SUBSEA TEMP. SENSOR
1
2 FLEX JOINT ANNULAR PREVENTER
REMOTE CHOKE CONTROL PANEL
DRILLPIPE PRESSURE
ANNULUS PRESSURE
SUBSEA TEMP. SENSOR
CHOKE POSITION INDICATOR
H-4 CONNECTOR KILL LINE
CHOKE LINE
ANNULAR PREVENTER
CHOKE CONTROL
SHEAR RAMS 5" RAMS
B
B1
A
A1
VARIABLE RAMS
C
SEABED
C1
5" RAMS
H-4 CONNECTOR
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HPHT Course - Section 14
STARBOARD
PORT
REMOTE CHOKE CONTROL PANEL VENT LINE TO DERRICK DRILLPIPE PRESSURE
ANNULUS PRESSURE
CHOKE POSITION INDICATOR
MUD GAS SEPARATOR CHOKE CONTROL
MGS
OPEN CLOSED
STBD
OPEN CLOSED
PORT
OPEN CLOSED
RETURN TO MUD SHAKERS
MGS
BOP
PRESSURE
TEMPERATURE
OVERBOARD LINE
PRESSURE/TEMP. SENSOR
TO STARBOARD/PORT VALVES
TEMPERATURE
TO MGS VALVE ALARM
TO BOP TEMP. SENSOR
VALVE STATUS
MUD GAS SEPARATOR BUFFER CHAMBER
REMOTE CHOKE/MONITORING AND BYPASS CONTROL UNIT
MANUAL CHOKE REMOTE CHOKE
REMOTE CHOKE
CHOKE/KILL MANIFOLD
MUD MANIFOLD
BYPASS
CMT UNIT CHOKE LINE ANNULAR
RAM HCR VALVE
KILL LINE
RAM RAM RAM
15 M BOP STACK
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HCR VALVE
GLYCOL INJECTION
HPHT Course - Section 14
1.1 GENERAL This document is the HPHT Well Control Supplement for *** and should be used in conjunction with the contractor Well Control Manual (Well Operations Manual Part 4 Sections 1 to 4) and the operator Well Control Manual. *** is not classified as an HPHT well as defined by the criteria in Petroleum Operations Notice No.4. The undisturbed bottom hole temperature at total depth is expected to be 285 deg F, the maximum anticipated pore pressure is 0.75 psi/ft, and maximum anticipated wellhead pressure is 83338 psi. However, these procedures will be adopted in the high pressure section of the well. It is essential that in the event of an influx entering the wellbore the well is closed in as soon as possible. For this reason Pit and Trip drills need to be carried out on a regular basis (daily initially) to ensure the rig crews are fully trained. Stripping drills will be carried out while tripping in the hole before drilling out the 13 3/8" and 9 5/8" shoes. The "HARD" shut in will be the method used in normal drilling circumstances (choke closed, shut-in with pipe rams), in order to minimise influx volume. During tripping operations, the "FAST" shut in should be used (choke closed, shut-in with annular). The Driller has the authority and responsibility to shut the well in at any time that he suspects the well is flowing. It is better to shut the well in quickly and then bleed off any suspected trapped pressure than to flow check a kick indicator. The shut-in procedures are listed in the Contractor Well Control Manual. The mud logging company will provide independent and continuous monitoring of the well. The Driller should react to their indications of flow as he would his own and act accordingly. Once a kick is identified, and the initial well closure performed, a procedure to kill the well should be discussed and agreed by key personnel. No changes to this procedure should be made by any individual without agreement from Drilling Management and the key offshore personnel. If there is any doubt about the status of the well then it should be shut-in and the situation analysed. Note that the well design allows for shut-in at any stage in the operation without casing or other mechanical failure.
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HPHT Course - Section 14
1.2 HPHT DRILLING POLICIES AND PROCEDURES The following procedures should be adhered to while drilling below the 9-5/ 8" shoe. 1) Always determine the choke and kill line slow circulating pressure each time the BOP is tested. 2) A float valve will not be run in any BHA. 3) Always drill with a drop-in dart sub in the string placed in the BHA above the HWDP. Check all ID's for restrictions and ensure that the drillpipe has been drifted to maximum required. 4) A connection gas will be obtained for every single drilled throughout the HPHT section. A FOSV (full opening safety valve) will be installed at some point below the top drive which will allow the safe installation of a kill assembly during a well control situation. The optimum procedures to accomplish these requirements will be developed by the Drilling Supervisor in consultation with the Rig Superintendent. 5) Connection gas due to the reduction of ECD can be a good indicator of increasing pore pressure. Ensure that the trend of gas levels are recorded by the mud loggers. Do not make more than one connection in the 8 1/2" hole until gas levels from the previous connection are checked at surface. 6) Flowcheck all significant drilling breaks for a minimum of 15 minutes, with a minimum ROP increase of 25% before checking. Continue to rotate pipe while flowchecking. 7) Ensure that the flowline drain down volume is known at various pump rates, and not just the drilling pump rate. The mud loggers should monitor drain down on every connection to check that the well is not flowing. 8) Record trapped pressures remaining on the standpipe when pumps are turned off. This pressure can be used during a kick to evaluate the actual kill weight required. The Bariod XP07 POBM has a low rheology so this will not be a problem. 9) After drilling out the 9 5/8" shoe and prior to performing the LOT pull into the shoe. Close in the well for at least one hour and observe for a pressure build up as the mud heats up. Record this pressure and the volume of mud bled off. This may eliminate any well control false alarms later.
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HPHT Course - Section 14
10) Minimise any requirement to change the active mud volume by adding, subtracting, or weighting up while the well is being drilled. This will mask any small kicks. Stop drilling while any essential mud volume changes are required. Ensure the Driller has given his permission and the Mud Loggers are aware of the operation. Be aware that doubling the active pit volume, halves the ability to detect a pit volume increase. 11) It is proposed to drill with a mud weight which provides a static overbalance over the estimated maximum pore pressure with the riser disconnected. Note that the overall hydrostatic head of the mud column will increase slightly when the well is static due to cooling of the mud in the shallower sections of hole. 12) It is proposed to maintain a minimum stock level of 200 MT of Barite, together with the required chemical additives, to retain acceptable mud properties throughout the 8 1/2" section. 14) A sufficient quantity of LCM material should be maintained as specified in the Drilling and Mud Programmes.
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HPHT Course - Section 14
1.3 HPHT TRIPPING PROCEDURES 1) The Operator Drilling Supervisor and Rig Superintendent should be on the rig floor at the start of any trip out the hole. 2) The following steps should be followed when POOH: a) Pull off bottom circulating. Continue to circulate for about 15 minutes (depending on ROP) to move cuttings up the hole. b) Flowcheck for a minimum of 15 minutes. Rotate pipe throughout. c)
Circulate the hole clean, and check for gas levels.
d) Do not pull out of the hole if the hole is not stable, i.e. no losses or flow. e) Pull out (not pumped) of the hole 10 stands and run back in hole to bottom no faster than the calculated swab/surge rate. f)
Circulate bottoms up. Record gas levels. An option to circulate the last 3000 ft over the choke should be considered depending on hole conditions.
g) Drop dart. Flowcheck for a minimum of 15 minutes. Rotate pipe throughout. h) Pump out of the hole in 8 1/2" hole to the previous shoe. i)
Pump a slug at the shoe, allow to settle before pulling out.
j)
Stop tripping while filling the trip tank. Allow level to stabilise prior to resuming trip.
k)
Flow check as a minimum on bottom, at the shoe, and before pulling the drill collars through the BOP. Monitor the well on the Trip Tank when out of the hole.
3) The following steps should be followed when running in the hole: a) Stop tripping while the trip tank is emptied and lined back up. b) Flow check as a minimum half way to the shoe and at the shoe. c)
Break circulation slowly at the shoe and when back on bottom.
d) Circulate bottoms up. Record gas levels. An option to circulate the last 3000 ft over the choke should be considered depending on hole conditions. 14 - 8
HPHT Course - Section 14
1.4 HPHT CORING PROCEDURE A core of the Volgian Sand will be required on hydrocarbon shows. The following precautions and procedures should be followed when coring the HPHT section is required. 1) Drill at least 30 ft of reservoir prior to coring. 2) Use steel core barrels with pressure relief ports/plugs. Maximum length of barrel is 60 feet. 3) Run a Hydril Drop-in sub above the core barrel. 4) Follow the HPHT tripping procedures. 5) Drop the Hydril Drop-in dart at the shore before pumping the slug. This will prevent any gas breaking out the core and expanding up the drillpipe. 6) POOH to 1500 ft. Circulate through the choke and record gas levels. 7) POOH 8) When handling the core on surface breathing apparatus should be worn until H2S levels are checked.
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HPHT Course - Section 14
1.5 SUSPENSION OF OPERATIONS The criteria for suspension or abandonment of the well, or of that section of the hole giving rise to continuing problems are as follows: 1) Well control and surface equipment have been exposed to temperatures or pressures outside their recommended operating envelope. 2)
Mechanical failure of any critical pressure containment equipment [wellhead, casing (including excessive wear), BOP, choke/kill manifold] unless redundancy exist.
3) If any vital safety equipment fails (mud or gas monitoring equipment, mud mixing equipment if reserve mud stock low, lifesaving equipment) unless redundancy exists. 4) If severe downhole loss of mud does not reduce after repeated treatments. 5) If the pore pressure while drilling increases to a value requiring a mud weight to balance which reduces the kick tolerance to an unacceptable level. 6) If the stock levels of Barite, Cement , Mud or Mud additives falls below a minimum level. 7) If the weather conditions are predicted to be outwith the operating envelope of the rig or are considered unsafe by the OIM. The rip back to the casing shoe may be slow due to additional precaution taken. Sufficient time must be allowed to complete this operation safely. Excessive heave during trips may contribute to the swabbing effect. 8) If rig motion prohibits accurate pit monitoring. 9) If TD is reached without encountering any significant hydrocarbons or after completion of testing any hydrocarbons encountered. 10) If there is a danger to the position keeping or structure of the rig (mooring equipment failure, collision). 11) If any other condition exists which the operator considers to create a hazard which is unacceptable.
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HPHT Course - Section 14
1.6 CASING WEAR The 9 5/8" casing has been designed to have sufficient strength to withstand reservoir pressure less a gas gradient to surface. During the Jurassic testing phase the 9.5/8" casing will act as the production casing and water is planned to be utilised as the packer fluid. It is therefore important that this string of casing, plus the wellhead components, do not suffer significant wear. Should significant wear take place then a contingency 7-5/8" tie-back string will be run, but this is not the preferred option. The total drilling time to TD, from the 9.5/8" casing point, is prognosed as 11 days. This short period of drilling, at minimal casing inclination, should contribute significantly to minimal casing wear, as should the use of best practices including minimising deviation in 36" hole and close control of mud properties in 8-1/2" hole. Furthermore, the safety factor on the burst rating of the casing is 1.38 (after allowing for temperature derating) which is considerably higher than the normally recognised minimum design rating of 1.1. For nominally vertical well, casing wear will not be a concern. However, ditch magnets and wear bushings will be utilised and monitored during the 8.1/2" hole section. Although these methods can identify whether or not any wear has taken place they cannot define the casing's residual strength. Only if excessive dogleg or inclination results from unplanned operations (eg. sidetrack) in the 12-1/4" hole section, then the following will be performed in order to accurately determine the status of the string of casing. (1) The casing will be calipered during the wait-on-cement time. (2) Consideration will be given to re-running the caliper if rotating hours inside 9-5/8" casing are excessive. (3) A final caliper survey will be performed and the casing's residual burst capacity determined prior to any testing operations taking place.
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HPHT Course - Section 14
SECTION 2.0
WELL CONTROL DECISION TREES
Shut-In Diagram - Top Drive (Green Chart) Off Bottom Kill Chart (Red Chart) On Bottom (Yellow Chart) Bullheading (Purple Chart)
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HPHT Course - Section 14
SHUT-IN DIAGRAM – TOP DRIVE GREEN CHART
WELL FLOWS
OPERATION IN PROGRESS DRILLING
TRIPPING
PICK UP & SPACE OUT STRING
INSTALL OPEN STAB-IN FOSV CLOSE STAB-IN FOSV
STOP PUMPING
OUT OF HOLE
OR
INSTALL TOP DRIVE CLOSE UPPER ANNULAR
CLOSE MIDDLE PIPE RAMS
CLOSE SHEAR RAMS
OPEN CHOKE LINE FAILSAFES
OPEN CHOKE LINE FAILSAFES
RECORD PRESSURES AND TIME OPEN CHOKE LINE FAILSAFES
RECORD PRESSURES AND TIME
CLOSE MIDDLE PIPE RAMS HANG OFF STRING
CLOSE UPPER ANNULAR HANG OFF STRING
INSTALL TOP DRIVE OPEN STAB-IN FOSV
RECORD PRESSURES AND TIME
DRILLER SUPERVISOR
Pdp > 3000 psi
YES INSTALL KILL ASSEMBLY & TEST
YELLOW CHART
DRILLING
NO OBSERVE WELL
MUSTER CREWS
WITHDRAW HOT WORK PERMITS
PREPARE TO KILL WELL
INFORM ONSHORE
OPERATION WHEN KICK OCCURRED
OUT OF HOLE
INFORM STANDBY BOAT
RED CHART
TRIPPING
RED CHART
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HPHT Course - Section 14
BULLHEADING PURPLE CHART
KILL MUD WEIGHT AND INFLUX VOLUME KNOWN. MAXIMUM ALLOWABLE SURFACE INJECTION PRESSURE KNOWN.
ADEQUATE VOLUME OF KILL WEIGHT MUD ON SURFACE. LINE UP KILL PUMP TO DRILLPIPE AND ANNULUS. TEST LINES.
ESTABLISH INJECTION RATE/PRESSURE. IS PRESSURE ABOVE MINIMUM PRESSURE TO FRACTURE SHOE?
SHUT-IN WELL DISCUSS OPTIONS
CONTINUE BULLHEADING AT MAXIMUM RATE UNTIL CALCULATED VOLUME PUMPED.
OBSERVE WELL. BLEED OFF TRAPPED PRESSURE IN SMALL INCREMENTS. ESTABLISH WELL DEAD.
YES
PIPE ON BOTTOM?
NO
PERFORM CIRCULATION IF POSSIBLE DISCUSS FUTURE OPERATIONS. RUN DRILLING LINER?
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STRIP IN OR RUN IN HOLE TO BOTTOM.
HPHT Course - Section 14
OFF BOTTOM KILL CHART RED CHART
YES TRIPPING.
ESTIMATE EXPECTED SURFACE PRESSURE/GAS VOLUME.
NO
BULLHEAD
NO
NO
PIPE IN HOLE?
OUT OF HOLE.
YES
MIGRATION RATE LESS THAN 1000 FT/HR.
BULLHEAD
NO
IS SURFACE EQUIPMENT CAPABLE OF HANDLING?
YES
ALLOW INFLUX TO MIGRATE AND EXPAND TO SURFACE.
IS STRING WEIGHT GREATER THAN THE UPWARD FORCE FROM WELL?
NO WELL DEAD
BULLHEAD SNUBBING UNIT?
YES
STUCK
YES BULLHEAD
YES RUN IN HOLE TO BOTTOM. CIRCULATE BOTTOMS UP.
NO ABLE TO STRIP?
NO YES BULLHEAD DEVELOP STRIPPING PROGRAMME.
INSTALL NON RETURN VALVE IN STRING. OPEN FOSV
REDUCE CLOSING PRESSURE ON ANNULAR. REMOVE WIPER RUBBERS.
BIT ON BOTTOM
ON BOTTOM KILL. YELLOW CHART.
STRIP IN PIPE DOPING CONNECTIONS UNTIL.
GAS AT SURFACE
CIRCULATE ANNULUS FREE OF GAS
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HPHT Course - Section 14
ON BOTTOM KILL YELLOW CHART
WELL SHUT IN. SICP, SIDP, GAIN RECORDED. KILL CALCULATIONS COMPLETE
NO BULLHEAD
SURFACE EQUIPMENT CAPABLE OF HANDLING KICK AT SURFACE?
HAVE SIDP AND SICP RISEN DUE TO GAS MIGRATION AND REQUIRE BLEEDING OFF?
NO
YES
BLEED OFF CALCULATED AMOUNT
CAN SHOE WITHSTAND CALCULATED MAXIMUM PRESSURES DURING KILL?
BULLHEAD
DECIDE ON DRILLER'S METHOD OR WAIT AND WEIGHT.
HOLD MEETING TO DISCUSS PROCEDURES. BEGIN KILL.
NO
YES
ARE LOSSES TO FORMATION?
SHUT DOWN AND EVALUATE OPTIONS?
LOSE RETURNS?
NO
CONTINUE KILL AS PER SCHEDULE
REDUCE PUMP STROKES PRIOR TO GAS AT SURFACE IF REQUIRED. INJECT GLYCOL AT CHOKE.
YES
OPTIONS: SLOW DOWN PUMPS UNTIL CIRCULATION REGAINED. BULLHEAD KILL WEIGHT FLUID. SPOT LCM, BARITE OR CEMENT PLUG ACROSS LOSS ZONE. BULLHEAD MUD DOWN ANNULUS WHILE SPOTTING HEAVY MUD DOWN DRILLPIPE BELOW THIEF ZONE. RUN TEMPERATURE LOG INSIDE DRILLPIPE TO EVALUATE UNDERGROUND BLOWOUT.
SHUT IN WELL. CLEAR BLOCKAGE. ALLOW TEMPERATURE TO INCREASE.
YES
HYDRATES? CHOKE MANIFOLD TEMPERATURE APPROACH. -20 DEG F?
NO SLOW DOWN PUMPS AND BY-PASS M.G.S.
YES
IS MUD GAS SEPERATOR APPROACHING CRITICAL LEVEL?
NO SHUT IN WELL UNTIL MUD TEMPERATURE DECREASES.
YES
IS MUD TEMPERATURE APPROACHING FLASH POINT (212 DEG F)?
NO CIRCULATE OUT INFLUX
CONFIRM WELL DEAD. PERFORM SECOND CIRCULATION (THIRD IF DRILLER'S METHOD USED). INCLUDE TRIP MARGIN IF REQUIRED.
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HPHT Course - Section 14
SECTION 3.0 ROLES AND RESPONSIBILITIES DURING A WELL CONTROL INCIDENT 1) Operator Supervision Operator Drilling Manager The Drilling Manager is responsible for the management of the technical, financial, EHS and contractual aspects of the Company's drilling activities. During any Well Control Incident the Drilling Manager will liaise with the Offshore Drilling Supervisor and the Manager and agree a plan to kill the well with them. Operator Drilling Superintendent The Drilling Superintendent is responsible for the day to day operation on the rig. He will ensure the drilling programme is completed using safe and efficient drilling practises by daily consultation with the Offshore Drilling Supervisor. During any Well Control Incident he will provide operational assistance to the Drilling Manager. Head of Well Engineering The Head of Well Engineering is responsible for technical supervision of well design, engineering and operations. During any Well Control Incident he will be the company focal point for external contact with the Health and Safety Executive etc. he will provide assistance to the Drilling Manager to ensure that all operations activities are executed in accordance with company and legislative EHS requirements. He will manage and supervise the activity of the Senior Drilling Engineer. Senior Drilling Engineer The Senior Drilling Engineer is responsible for providing technical assistance to support the operation. He will liaise with the Offshore Drilling Supervisor and Drilling Superintendent on a daily basis. During any Well Control Incident he will assist the Drilling Manager with any technical problems. Drilling Supervisor The Drilling Supervisor is operator senior representative on the rig. He is responsible for issuing detailed written daily drilling instructions to the Superintendent and supervising any service personnel contracted to Operator.
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HPHT Course - Section 14
He should hold daily planning meetings, pit drills and attend pre-job safety meetings to keep the rig crew informed of potential drilling hazards that may arise. During any Well Control Incident the Drilling Supervisor must ensure the well is secure and confirm pressures and gains recorded. He must then develop a well kill procedure in consultation with the Superintendent / OIM and the Operator Drilling Manager. Once the procedure is approved he must ensure it is followed and any changes are agreed between all parties. If there is any doubt he should shut the well in. Night Drilling Supervisor The night Supervisor provides cover for the Drilling Supervisor and ensures his instructions are followed. He should inform the Drilling Supervisor of any unplanned events. During any Well Control Incident he should provide support for the Drilling Supervisor and follow his instructions. 2) Supervision Rig Manager The Rig Manager provides onshore support for the OIM and Rig Superintendent. He communicates daily with the Operator Drilling Superintendent to discuss operations, safety and logistics. During any Well Control Incident the Rig Manger will liaise with the OIM and Operator Drilling Manager to develop and approve the programme to kill the well. Offshore Installation Manager (O.I.M.) The OIM is legally responsible to the Secretary of State for the safety of the installation and the safety, health and welfare of all persons on or about the installations. During any Well Control Incident the OIM must be kept informed of and agree to all operations. The OIM has the authority to stop any operation he believes to be unsafe. Rig Superintendent The Rig Superintendent must ensure the crews are trained in, and the rig equipment is capable of, the early detection of over pressure. This shall include pit drills in consultation with the Operator Drilling Supervisor.
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HPHT Course - Section 14
During any Well Control Incident the Rig Superintendent shall ensure the well has been properly secured by the Driller. He will take an active role in the development of the plan to kill the well and will supervise the crew and operation of the well control equipment throughout the well killing operation. He may delegate responsibility to the Day/Night Toolpusher. Day / Night Toolpusher The Day and Night Toolpushers work opposite shifts. Each report to the Rig Superintendent. The Day Toolpusher must supervise the Drilling crews to ensure the procedures detailed by the Operator Drilling Supervisor and outlined in the Drilling Programme are carried out in a safe and efficient manner. The Night toolpusher has similar responsibilities as the Day Toolpusher during the nightshift. He works in consultation with the Operator Night Drilling Supervisor. The Day/Night Toolpusher shall report any Well Control Incident to the Rig Superintendent once the well has been secured. Driller The Driller is responsible for supervising the Drilling crew and implementing the instructions issued by the Operator Drilling Supervisor in a safe and efficient manner. The Driller is responsible for monitoring the well using the rigs instrumentation for signs of a kick or Well Control Incident and reacting to those signs to secure the well.
14 - 19
• ABE
RD
CONTENTS
WELL CONTROL PROCEDURES
1.1 1.2 1.3 1.4 1.5 1.6
General HPHT Drilling Policies and Procedures HPHT Tripping Procedures HPHT Coring Procedure Suspension of Operations Casing Wear
WELL CONTROL DECISION TREES
ROLES AND RESPONSIBILITIES DURING A WELL CONTROL INCIDENT
C
CE
N TRE
OL S •
ON
C
15. SAMPLE HPHT WELL CONTROL PROCEDURES (JACK-UP)
D RI L LI N G S
HO
L & WEL
HPHT Course
EE N
TR O L T R AI NIN
G
HPHT Course - Section 15
SECTION 1.0
WELL CONTROL PROCEDURES
1.1 GENERAL This document is the HPHT Well Control Supplement for well *** and should be used in conjunction with the contractor. Well Control Manual. It should be referred to during the HPHT section of the well which will be below 13,500 ft TVD RKB. As this document has been developed specifically for the drilling of well *** it will form part of the well *** it will form part of the well-specific training which has been planned. It is essential that in the event of an influx entering the wellbore the well is closed in as soon as possible. For this reason Pit and Trip drills need to be carried out on a regular basis (daily initially) to ensure the rig crews are fully trained. Stripping drills will be carried out while tripping in the hole before drilling out the 13 5/8" and 95/8" shoes. The "FAST" shut in will be the method used in normal circumstances (choke closed, shut-in with annular). In special circumstances where the Kick Tolerance is deemed to be too low, about 40 bbls, then the "HARD" shut in should be used (choke closed, shut-in with pipe rams). The actual method to be used will be determined by the Drilling Supervisor in consultation with the Rig Superintendent. The Driller has the authority and responsibility to shut the well in at any time that he suspects the well is flowing. It is better to shut the well in quickly and then bleed of any suspected trapped pressure that to flow check a kick indicator. The shut-in procedures are listed in the Contractor Well Control Manual. The mud logging company will provide independent and continuous monitoring of the well. The Driller should react to their indications of flow as he would his own and act accordingly. Once a kick is identified, and the initial well closure performed, a procedure to kill the well should be discussed and agreed by key personnel. No changes to this procedure should be made by any individual without agreement from operator Drilling Management and the key offshore personnel. If there is any doubt about the status of the well then it should be shut-in and the situation analysed. Note that the well design allows for shut-in at any stage in the operation without casing of other mechanical failure.
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HPHT Course - Section 15
1.2 HPHT DRILLING POLICIES AND PROCEDURES The following procedures should be adhered to while drilling below 13,500 ft TVD RKB in the HPHT section where the bottom hole pressure is estimated to be at least 10,000 psi. 1) Always drill with a ported float in the string. This will allow the well to be shut-in in the event of a flow yet enables SIDPP to be read with some accuracy in heavy POBM. Due to the inaccuracy in monitoring the well while RIH regular flow checks should be carried out as well as a trip record kept. 2) Always drill with a drop-in dart sub in the string placed in the BHA above the HWDP. Check all ID's for restrictions and ensure that the drillpipe has been drifted to maximum required. 3) Drill in singles throughout the HPHT section. Use a range 3 joint of pipe as a kelly equivalent with two kelly cocks and a saver sub at the end. 4) Connection gas due to the reduction of ECD can be a good indicator of increasing pore pressure. Ensure that the trend of gas levels are recorded by the mud loggers. Do not make more than one connection in the 8 1/2" hole until gas levels from the previous connection are checked at surface. 5) Flowcheck all significant drilling breaks for a minimum of 15 minutes, with a minimum ROP increase of 25% before checking. Continue to rotate pipe while flowchecking. 6) Ensure that the flowline drain down volume is known. The mud loggers should monitor drain down on every connection to check the well is not flowing. 7) Record trapped pressures remaining on the standpipe when pumps are turned off. This pressure can be used during a kick to evaluate the actual kill weight required. The Bariod XP07 POBM has a low rheology so this will not be a problem. 8) After drilling out the 9 5/8" shoe and prior to performing the LOT pull into the shoe. Close in the well for at least one hour and observe for a pressure build up as the mud heats up. Record this pressure and the volume of mud bled off. This may eliminate any well control false alarms later.
15 - 4
HPHT Course - Section 15
9) Do not change the active mud volume by adding, subtracting , or weighting up while the well is being drilled. This will mask any small kicks. Stop drilling while any essential mud volume changes are required. Ensure the Driller has given his permission and the Mud Loggers are aware of the operation. 10) It is proposed to maintain a minimum stock level of 200 MT of Barite, together with the required chemical additives, to retain acceptable mud properties throughout the 8 1/2" section. 11) It is proposed to maintain a minimum stock level of 60 MT of cement and associated chemicals throughout the 8 1/2" section. 12) A sufficient quantity of LCM materials should be maintained as outlined in the Drilling and Mud Programmes.
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HPHT Course - Section 15
1.3 HPHT TRIPPING PROCEDURES 1) The Drilling Supervisor and Rig Superintendent should be on the rig floor at the start of any tip out the hole. 2) The following steps should be followed when POOH: a) Circulated the hole clean. b) Flowcheck for a minimum of 15 minutes. Rotate pipe throughout. c)
Do not pull out of the hole if the hole is not stable, i.e. no losses or flow.
d) Pull out (not pumped) of the hole 10 stands and run back in hole to bottom no faster than the calculated swab/surge rate. e) Circulate bottoms up. Record gas levels. An option to circulate the last 3000 ft over the choke should be considered depending on hole conditions. f)
Flowcheck for a minimum of 15 minutes. Rotate pipe throughout.
g) Pump out of the hole in 8 1/2" hole to the previous shoe. h) Pump a slug at the shoe, allow to settle before pulling out. i)
Flow check as a minimum on bottom, at the shoe, and before pulling the drill collars through the BOP. Monitor the well on the Trip Tank when out of the hole.
3) The following steps should be followed when running in the hole: a) Flow check as a minimum half way to the shoe and at the shoe. b) Break circulation slowly at the shoe and when back on bottom. c)
15 - 6
Circulate bottoms up. Record gas levels. An option to circulate the last 3000 ft over the choke should be considered depending on hole conditions.
HPHT Course - Section 15
1.4 HPHT CORING PROCEDURE A core of the Fulmar Sand will be required on hydrocarbon shows. The following precautions and procedures should be followed when coring the HPHT section is required. 1) Drill at least 30 ft of reservoir prior to coring. 2) Use steel core barrels with pressure relief ports / plugs. Maximum length of barrel is 60 feet. 3) Run a Hydril Drop-in sub above the core barrel. 4) Follow the HPHT tripping procedures. 5) Drop the Hydril Drop-in dart at the shoe before pumping the slug. This will prevent any gas breaking out the core and expanding up the drillpipe. 6) POOH to 1000 ft. Circulate through the choke and record gas levels. 7) POOH 8) When handling the core on surface breathing apparatus should be worn until H2S levels are checked.
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HPHT Course - Section 15
1.5 SUSPENSION OF OPERATIONS The criteria for suspension or abandonment of the well, or of that section of the hole giving rise to continuing problems are as follows: 1) Well control and surface equipment have been exposed to temperatures or pressures outside their recommended operating envelope. 2) Mechanical failure of any critical pressure containment equipment [wellhead, casing (including excessive wear), BOP, choke/kill manifold] unless redundancy exists. 3) If any vital safety equipment fails (mud or gas monitoring equipment, mud mixing equipment if reserve mud stock low, lifesaving equipment) unless redundancy exists. 4) If severe downhole loss of mud does not reduce after repeated treatments. 5) If the pore pressure while drilling increases to a value requiring a mud weight to balance which reduces the kick tolerance to an unacceptable level. 6) If the stock levels of Barite, Cement, Mud or Mud additives falls below a minimum level. 7) If the weather conditions are outwith the operating envelope of the rig or are considered unsafe by the OIM. 8) If TD is reached without encountering any significant hydrocarbons or after completion of testing any hydrocarbons encountered. 9) If there is a danger to the structure of the rig (seabed condition, collision). 10) If any other condition exists which the operator considers to create a hazard which is unacceptable.
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HPHT Course - Section 15
1.6 CASING WEAR The 10 3/4" * 9 5/8" casing has been designed to have sufficient strength, including a safety factor, to withstand reservoir pressure less a gas gradient to surface. During the Jurassic testing phase the 10.3/4" * 9.5/8" casing will act as the production casing and water is planned to be utilised as the packer fluid. It is therefore imperative that this string of casing, plus the wellhead components, are as close to original specification as possible. Should significant wear take place then a contingency liner will be run but this is not the preferred option. The total drilling time to TD, from the 10.3/4" * 9.5/8" casing point, is prognosed as 6 days. This short period of drilling should contribute significantly to minimal casing wear, as should the use of best practices including close control of mud properties, minimal wellbore inclination and non-rotating sleeves. Ditch magnets and wear bushings must be utilised and monitored during the 8.1/2" hole section. Although these methods can identify whether or not any wear has taken place they cannot define the casing's residual strength. In order to accurately determine the status of the string of casing the following will be performed during the drilling of the 8.1/2" hole section. (1) The casing will be calipered during the wait-on-cement time. (2) Ditch magnets and a wearbushing will be utilised and monitored during drilling operations. (3) Should drilling operations continue beyond 15 days, and there are definite indications from the ditch magnets that some casing wear has taken place, then the caliper will be re-run. The casing burst should be reviewed at this time and compared to the requirements of further drilling operations in terms of well control. (4) Should, for any reason, drilling continue beyond 30 days, and where a caliper was not re-run at 15 days, then a caliper should be run and the casing re-evaluated. (5) Irrespective of (3) or (4) above a final caliper survey will be performed and the casing's residual burst capacity determined prior to any testing operations taking place.
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HPHT Course - Section 15
SECTION 2.0 WELL CONTROL DECISION TREES
Shut-In Diagram - Top Drive (Green Chart) Off Bottom Kill Chart (Red Chart) On Bottom (Yellow Chart) Bullheading (Purple Chart)
15 - 10
SHUT-IN DIAGRAM – TOP DRIVE GREEN CHART
WELL FLOWS
OPERATION IN PROGRESS
DRILLING
OUT OF HOLE
TRIPPING
INSTALL OPEN STAB-IN FOSV
PICK UP & SPACE OUT STRING
CLOSE STAB-IN FOSV
STOP PUMPING
CLOSE ANNULAR
OR INSTALL TOP DRIVE
CLOSE SHEAR RAMS
OPEN HCR VALVE
OPEN HCR VALVE CLOSE ANNULAR INSTALL TOP DRIVE OPEN STAB-IN FOSV OPEN HCR VALVE
RECORD PRESSURES AND TIME
DRILLER SUPERVISOR
Pdp > 3000 psi
YES INSTALL KILL ASSEMBLY & TEST
YELLOW CHART
DRILLING
NO OBSERVE WELL
MUSTER CREWS
WITHDRAW HOT WORK PERMITS
PREPARE TO KILL WELL
INFORM ONSHORE
OPERATION WHEN KICK OCCURRED
OUT OF HOLE
TRIPPING
RED CHART
INFORM STANDBY BOAT
RED CHART
OFF BOTTOM KILL CHART RED CHART
YES TRIPPING.
ESTIMATE EXPECTED SURFACE PRESSURE/GAS VOLUME.
NO
BULLHEAD
NO
NO
PIPE IN HOLE?
OUT OF HOLE.
YES
MIGRATION RATE LESS THAN 1000 FT/HR.
BULLHEAD
NO
IS SURFACE EQUIPMENT CAPABLE OF HANDLING?
YES
ALLOW INFLUX TO MIGRATE AND EXPAND TO SURFACE.
IS STRING WEIGHT GREATER THAN THE UPWARD FORCE FROM WELL?
NO WELL DEAD
BULLHEAD SNUBBING UNIT?
YES
STUCK
YES BULLHEAD
YES RUN IN HOLE TO BOTTOM. CIRCULATE BOTTOMS UP.
NO ABLE TO STRIP?
NO YES BULLHEAD DEVELOP STRIPPING PROGRAMME.
INSTALL NON RETURN VALVE IN STRING. OPEN FOSV
REDUCE CLOSING PRESSURE ON ANNULAR. REMOVE WIPER RUBBERS.
BIT ON BOTTOM
ON BOTTOM KILL. YELLOW CHART.
STRIP IN PIPE DOPING CONNECTIONS UNTIL.
GAS AT SURFACE
CIRCULATE ANNULUS FREE OF GAS
ON BOTTOM KILL YELLOW CHART
WELL SHUT IN. SICP, SIDP, GAIN RECORDED. KILL CALCULATIONS COMPLETE
NO BULLHEAD
SURFACE EQUIPMENT CAPABLE OF HANDLING KICK AT SURFACE?
HAVE SIDP AND SICP RISEN DUE TO GAS MIGRATION AND REQUIRE BLEEDING OFF?
NO
YES
BLEED OFF CALCULATED AMOUNT
CAN SHOE WITHSTAND CALCULATED MAXIMUM PRESSURES DURING KILL?
BULLHEAD
DECIDE ON DRILLER'S METHOD OR WAIT AND WEIGHT.
HOLD MEETING TO DISCUSS PROCEDURES. BEGIN KILL.
NO
YES
ARE LOSSES TO FORMATION?
SHUT DOWN AND EVALUATE OPTIONS?
LOSE RETURNS?
NO
CONTINUE KILL AS PER SCHEDULE
REDUCE PUMP STROKES PRIOR TO GAS AT SURFACE IF REQUIRED. INJECT GLYCOL AT CHOKE.
YES
OPTIONS: SLOW DOWN PUMPS UNTIL CIRCULATION REGAINED. BULLHEAD KILL WEIGHT FLUID. SPOT LCM, BARITE OR CEMENT PLUG ACROSS LOSS ZONE. BULLHEAD MUD DOWN ANNULUS WHILE SPOTTING HEAVY MUD DOWN DRILLPIPE BELOW THIEF ZONE. RUN TEMPERATURE LOG INSIDE DRILLPIPE TO EVALUATE UNDERGROUND BLOWOUT.
SHUT IN WELL. CLEAR BLOCKAGE. ALLOW TEMPERATURE TO INCREASE.
YES
HYDRATES? CHOKE MANIFOLD TEMPERATURE APPROACH. -20 DEG F?
NO SLOW DOWN PUMPS AND BY-PASS M.G.S.
YES
IS MUD GAS SEPERATOR APPROACHING CRITICAL LEVEL?
NO SHUT IN WELL UNTIL MUD TEMPERATURE DECREASES.
YES
IS MUD TEMPERATURE APPROACHING FLASH POINT (212 DEG F)?
NO CIRCULATE OUT INFLUX
CONFIRM WELL DEAD. PERFORM SECOND CIRCULATION (THIRD IF DRILLER'S METHOD USED). INCLUDE TRIP MARGIN IF REQUIRED.
BULLHEADING PURPLE CHART
KILL MUD WEIGHT AND INFLUX VOLUME KNOWN. MAXIMUM ALLOWABLE SURFACE INJECTION PRESSURE KNOWN.
ADEQUATE VOLUME OF KILL WEIGHT MUD ON SURFACE. LINE UP KILL PUMP TO DRILLPIPE AND ANNULUS. TEST LINES.
ESTABLISH INJECTION RATE/PRESSURE. IS PRESSURE ABOVE MINIMUM PRESSURE TO FRACTURE SHOE?
SHUT-IN WELL DISCUSS OPTIONS
CONTINUE BULLHEADING AT MAXIMUM RATE UNTIL CALCULATED VOLUME PUMPED.
OBSERVE WELL. BLEED OFF TRAPPED PRESSURE IN SMALL INCREMENTS. ESTABLISH WELL DEAD.
YES
PIPE ON BOTTOM?
NO
PERFORM CIRCULATION IF POSSIBLE DISCUSS FUTURE OPERATIONS. RUN DRILLING LINER?
STRIP IN OR RUN IN HOLE TO BOTTOM.
HPHT Course - Section 15
SECTION 3.0 ROLES AND RESPONSIBILITIES DURING A WELL CONTROL INCIDENT 1) Operator Supervision Operator Drilling Superintendent The Drilling Superintendent is responsible for the day-to-day operations on the rig. He will ensure the drilling programme is completed using safe and efficient drilling practises through daily consultation with the Offshore Drilling Supervisor. During any Well Control Incident the Drilling Superintendent will liaise with the Offshore Drilling Supervisor and the Contractor Rig Manager and agree a plan to kill the well with them. Operator Senior Drilling Engineer The Senior Drilling Engineer is responsible for providing technical assistance to support the operation. He will liaise with the Offshore Drilling Supervisor and Drilling Manager on a daily basis. During any Well Control Incident he will assist the Drilling Manager with any technical problems. Operator Drilling Supervisor The Drilling Supervisor is the Operators senior representative on the rig. He is responsible for issuing detailed written daily drilling instruction so the contractor to the operator. He should hold daily planning meetings, pit drills and attend pre-job safety meetings to keep the rig crew informed of potential drilling hazards that may arise. During any Well Control Incident the Drilling Supervisor must ensure the well is secure and confirm pressures and gains recorded. He must then develop a well kill procedure in consultation with the contractor Rig Superintendent / OIM and the Operator Drilling Manager. Once the procedure is approved he must ensure it is followed and any changes are agreed between all parties. If there is any doubt he should shut the well in. Operator Night Drilling Supervisor The Night Supervisor provides cover for the Drilling Supervisor and ensures his instructions are followed. He should inform the Drilling Supervisor of any unplanned events. During any Well control Incident he should provide support for the Drilling Supervisor and follow his instructions.
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HPHT Course - Section 15
2) Contractor Supervision Contractor Rig Manager The Rig Manager provides onshore support for the OIM and Rig Superintendent. He should communicates daily with the operator Drilling Manager to discuss operations, safety and logistics. During any Well Control Incident the Rig Manager will liaise with the OIM and Operator Drilling Manager to develop and approve the programme to kill the well. Offshore Installation Manager (O.I.M.) The OIM is legally responsible to the Secretary of State for the safety of the installation and the safety, health and welfare of all persons on or about the installation. During any Well Control Incident the OIM must be kept informed of and agree to all operations. The OIM has the authority to stop any operation he believes to be unsafe. Rig Superintendent The Rig superintendent must supervise the Contractor Drilling crews to ensure the procedures detailed by the Operator Drilling Supervisor and outlined in the Drilling Programme are carried out in a safe and efficient manner. He must ensure the crews are trained in, and the rig equipment is capable of, the early detection of over pressure. This shall include pit drills in consultation with the Operator Drilling Supervisor. During any Well Control Incident the Rig Superintendent shall ensure the well has been properly secured by the Driller. He will take an active role in the development of the plan to kill the well and will supervise the crew and operation of the well control equipment throughout the well killing operation. He may delegate responsibility to the Night Toolpusher. Night Toolpusher The Night Toolpusher has similar responsibilities as the Rig Superintendent during the nightshift. He works in consultation with the Operator Night Drilling Supervisor. The Night Toolpusher shall report any Well Control Incident to the Rig Superintendent once the well has been secured.
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HPHT Course - Section 15
Driller The Driller is responsible for supervising the Contractor Drilling crew and implementing the instructions issued by the Operator Drilling Supervisor in a safe and efficient manner. The Driller is responsible for monitoring the well using the rigs instrumentation for signs of a kick or Well Control Incident and reacting to those signs to secure the well.
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CONTENTS
APP 1.1 INTRODUCTION APP 1.2 WELL PLANNING APP 1.3 GENERAL OPERATING PROCEDURES APP 1.4 KICK HANDLING APP 1.5 MINIMUM EQUIPMENT REQUIREMENTS APP 1.6 INSPECTION AND TESTING OF WELL CONTROL EQUIPMENT REFERENCE I REFERENCE II REFERENCE III
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APPENDIX 1.UKOOA GUIDELINES FOR HPHT WELLS
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HPHT Course - Appendix 1
APP 1.1
INTRODUCTION
These Procedures, covering operating practices and minimum equipment, were developed with the primary aim of ensuring the safety of personnel. The first step in achieving this goal is to minimise the impact of well control incidents through proper planning, comprehensive training, and good operating practice. The second step is to ensure that kicks can be safely handled with rig equipment without jeopardising the installation or the personnel on board.
APP 1.2
WELL PLANNING
Pressure Design A prediction of static bottom hole pressure must be made based on nearest offset well data. A prediction of maximum surface pressure must be made based on a fully evacuated of mud and formation fluid from TD to the surface. A fluid gradient of .15 psi/ft will be used unless offset data can support the use of an alternative gradient. Temperature Design A prediction of static bottom hole temperature must be made based on nearest offset well data. Continuous Temperature Requirement: A prediction of the maximum anticipated surface and mudline circulating temperatures during drilling operations must be made. The curves in Appendix No. I can be used unless the Operator has an alternative method. The purpose of the continuous temperature requirement is to define temperatures that will not be exceeded during normal drilling and well control operations. Peak Temperature Requirement: A prediction of the peak surface temperature must be made. The curves in Appendix No. II should be used unless the Operator has an alternative method. The purpose of the peak temperature requirement is to ensure integrity of the BOP system during rig evacuation. In a situation where it is impossible to shut in the well, the peak temperature is defined as the highest temperature that may be achieved if the well is flowing uncontrolled up the annulus through the choke manifold for one hour. Casing Design The deep intermediate casing string (i.e. the last string set prior to drilling into the deep high pressure objective) must be designed for the lesser of the maximum anticipated surface pressure determined in 2.1, or the pressure determined by the deep intermediate casing shoe strength minus the formation fluid gradient to the surface. If the operator determines that sour service tubular design is applicable, then appropriate actions will be taken to incorporate those considerations into the design.
APP 1 - 3
HPHT Course - Appendix 1
Elastomer Design All elastomers in the well control system must be certified by a certifying authority for a continuous temperature rating and a peak temperature rating (for one hour). API Specification 16A stipulates the relevant ASTM mechanical properties testing requirement for the elastomers. These standards ASTM tests should be conducted on the sample after exposure to the rated temperatures (continuous and peak). Well Control Programme Procedures such as shut-in method, flow checks, circulating rates, kill method to be utilised, and alternatives to use if primary kill method does not work, must be established prior to drilling the well. A specific decision tree should be made for the well to cover the alternative well control methods and at what point the well is shut-in to re-evaluate the situation. Specific procedures must be planned to safely handle swabbing during a trip. Criteria for the decision to abandon the well will be established as part of the well control programme. Specialised Training Crew training specific to the well being drilled, should be conducted on each HP well to ensure correct reactions to well control situations and to understand the specific decision tree to be followed for that well. Pre-Spud Meeting: A pre-spud meeting should be held on the rig to brief all crews on the well and its hazards. Crew Safety Meeting: A crew safety meeting should be held prior to drilling out the deep intermediate casing to discuss and clarify well control procedures. Pre-tour meetings should update all crews as to current situations. Well Control Courses: Well control training should be expanded to include specific training drilling HP wells. Operator Supervision The Operator should have 24 hour supervision on the rig, from prior to drilling out below the deep intermediate casing until the HP zone is abandoned. Well Consent It will be necessary to submit additional information outlined in Appendix III with the well consent application in addition to CSON 11 to ensure that sufficient planning has been performed for the HP well.
APP 1 - 4
HPHT Course - Appendix 1
APP 1.3
GENERAL OPERATING PROCEDURES
Temperature Monitoring Temperatures upstream of the choke, at the flowline, and on the test system flowline, must be monitored to ensure that the continuous temperature rating of the elastomer system is not exceeded during drilling, well control operations and testing. If the continuous temperature is approached, corrective measures must be taken to reduce the temperature such as slowing down the pumps, reducing the choke size or closing in the well. Drilling Data Analysis The pressure and temperature of the well should be monitored as drilling progresses and compared with the original prediction, to ensure that equipment ratings are not exceeded. Circulation Of Trip Gas Bottoms up should be circulated after making a trip when the HP zone is exposed to the wellbore. A flow check should be considered when bottom hole returns get to a point in the annulus where gas break out can occur (+/- 2000 ft BRT is recommended). Considerations should be given to taking returns thereafter through the choke manifold and mud gas separator, particularly when gas break out is indicated. Short Trips A short trip (5-10 stands) should be made prior to tripping out of the hole while the high pressure hydrocarbon-bearing zone is exposed to the wellbore and bottoms up should be circulated to ensure adequate hydrostatic overbalance over the formation pressure. Coring Precautions Procedural and equipment precautions should be taken while coring HP reservoirs to avoid inducing swab kicks and provide necessary options to handle a kick. Coring of the HP reservoir while drilling on the first well on a structure should be discouraged. Mud Mixing And Transferring Mixing and/or transferring of mud should be avoided or carefully controlled while drilling through and below the HP reservoir. BOP Drills BOP drills should be performed at frequencies to ensure crew proficiency. Simulated kick drill should be conducted prior to drilling out previous casing shoe track.
APP 1 - 5
HPHT Course - Appendix 1
Barite Supplies Prior to drilling below deep intermediate casing, there must be sufficient barite on the rig to weight up the active mud system; and there must be sufficient capacity for weighting up the mud quickly to enable the mud weight to be raised to a level above the maximum predicted pore pressure for the well. Flow Checks Flow checks should be longer with OBM (15-20 mins) and more frequent when approaching HP objective. If in doubt, circulate bottoms up with intermediate flow check(s) as per 3.4 above. Autochoke Control The maximum allowable annulus surface pressure control should be disabled for 12-1/4" and smaller hole sections. Communications And Responsibilities There should be clearly defined communication channels and responsibilities for all emergency situations on the rig, particularly during protracted or complicated well control situations. Move Off Procedures Procedures and systems for floaters should be in place to allow rapid disconnection of riser and to winch the drilling unit off location 400-500 ft in any direction in the event of an out of control well. Automatic release anchor lines can be considered as an alternative to winching off location. Drilling Limitation Drilling should not be continued into and/or through the high pressure hydrocarbon section unless a mud can be used in the well which is heavy enough to hydrostatically balance the predicted formation pressure and still maintain returns at the surface. Shoe Test After drilling 10-20 ft of new formation below the deep intermediate casing string, a formation leak-off or integrity test must be performed to determine if shoe strength is adequate to drill into the high pressure objective.
APP 1 - 6
HPHT Course - Appendix 1
APP 1.4
KICK HANDLING
Fast Shut-In And Kill System If a kick is taken, a fast shut-in method should be used to minimise the influx volume. The 15,000 psi kill system should be used to circulate the kick out. Kick Volume And Kill Rate If a kick is taken, the volume of gas which will be seen at the surface should be determined. (For OBM, only an estimate is possible due to gas solubility.) Kill rate(s) should be determined to ensure that gas handling capability of the mud gas separator is not exceeded. Plans should be made to by-pass the mud gas separator or slow the kill rate if the mud gas separator capacity is approached. If the kick volume is large, bullheading should be considered as an option to reduce surface gas volume and wear on surface well control equipment, particularly when H2S is expected. Swabbing If the well is swabbed and not flowing, the drillstring should be un back to TD and bottoms up circulated through the choke. If the well is swabbed and flowing, bullheading or weighting up off bottom are alternate options to enable running back to bottom to circulate out of the influx. Long stripping jobs back to bottom should be discouraged to avoid undue wear and tear on the BOP’s. Preferred Chokeline Outlet When handling kicks in HP wells the upper choke line should be used initially for circulating out a kick. If there is an outlet below the lowermost set of rams, the outlet should not be used to take returns to the choke manifold. If the upper outlet(s) or line(s) wash out, then the outlet below the lowermost set of rams should not be used for conventional circulation and should only be used for either bullheading or lubricating mud into the well. Choke Operations The person controlling the well kill operations must have available a schedule for predicted drill pipe pressure during the kill operation. If abnormal response is indicated from the schedule then the well should be shut in. If the well is losing or behaving incorrectly, then the decision to circulate out the kick should be re-evaluated and bullheading should be considered. Mud Gas Separator Monitoring The mud gas separator must be monitored during well kill operations to enable the choke operator to know when the degasser will be overloaded and to take the corrective measures to avoid blowing out the mud seal. Temperature Monitoring The temperature must be monitored at the flowline and upstream of the choke with readout on the rig floor, so that the rig crew knows when the continuous temperature rating is approached during drilling, or well control operations and corrective measures can be taken. APP 1 - 7
HPHT Course - Appendix 1
Mustering Of Crews At the discretion of the OIM or other designated personnel, muster stations should be sounded when a kick is taken and people given explicit instructions as to their courses of action. The situation should be reviewed as well control progresses, and the option of abandonment or evacuation reevaluated in light of well conditions.
APP 1.5
MINIMUM EQUIPMENT REQUIREMENTS
Surface Gas Handling System Mud Gas Separator (MGS): The mud gas separator must be designed and certified for a given capacity of gas and mud. Design will include vessel working pressure, sizing of vent lines, length of mud seal, retention time, and control system. The degasser should be designed, constructed, inspected, tested and stamped in accordance with ASTM VIII Division 2 - Boiler and pressure vessel code or similar pressure vessel code. MGS Instrumentation: The MGS should be instrumented and controlled so that the working pressure is not exceeded. MGS Bypass: An alternative method to dispose of produced fluids must be provided in the event the capacity of the MGS is exceeded. Glycol Injection System: A system for injection of glycol upstream of the choke to prevent hydrate formation should be available. Temperature Monitoring Equipment A temperature monitoring system must be in place to ensure that the continuous temperature rating of the elastomer system is not exceeded during drilling, well control operations and well testing. Temperatures should be monitored at the mud return flowline, at the chokeline upstream of the choke, and at the well test flowline upstream of all chokes.
APP 1 - 8
HPHT Course - Appendix 1
High Pressure Well Control System Failsafe Valves: Sequenced ( manual or automatic) closing of the fail safe valves on a subsea stack, with the outer valve closing first, should be used to limit the effects of cutting out of the gates. Also consideration should be given to the closure mechanism and whether additional hydraulic assist should be incorporated in order to increase closing force. Flexible Hoses: Strict attention must be given to the flexible hoses to ensure that they are designed for appropriate temperatures, pressures and well fluids. The hose should be checked to ensure that it is the correct length for the given stack. BOP Stack Outlets: There should be a minimum of two outlets to the choke manifold below the upper set of pipe rams on a subsea stack. Hang Off Rams: The upper pipe rams should be positioned in the stack so that they can be used to hang off the drillstring with the blind/shear rams closing above. Chokes: The choke manifold should be equipped with two remote hydraulic chokes and at least one manually operated choke.
Kill System Kill Pump: A 15,000 psi kill pump capable of slow circulation rates +/- 0.5 bbls/mins should be available. There should be a good communications link between the kill pump and rig floor. Consideration should be given to equipping the kill pump for remote operations from the rig floor. There should also be a choke on the bleed down line to reduce erosion of plug type valves when bleeding off pressure. High Pressure Line: High pressure line from the kill pump to the rig floor with a circulating head and flexible hose or chicksans ready for quick make up should be available. Drillstring Back Pressure Valve A means of avoiding back flow up the drill pipe should be incorporated by either using a sub for a drop in back pressure or by using a float valve in the BHA before drilling through the transition zone from normal to abnormally high pressure, commonly reached below the 13-3/8" casing point. Drillstring Circulating Capability A high pressure lubricator and drill pipe perforation system or drillstring circulating sub should be available while drilling below deep intermediate casing. Pit Level Indicator Minimum pit level indicator requirements are 2 pit level indicators per active tank for semi submersibles. All tanks should be monitored and include a pit volume totaliser. APP 1 - 9
HPHT Course - Appendix 1
APP 1.6
INSPECTION AND TESTING WELL CONTROL EQUIPMENT
The BOP stack including flexible hoses should be pressure tested to their full working pressure on the test stump prior to running. Hoses should be visually inspected externally and in accordance with manufacturers recommendations every time the stack is retrieved to surface and prior to running. Kill and choke lines, including moonpool hoses, should be pressure tested to their full working pressure prior to drilling out deep intermediate casing or more frequently if recommended by manufacturer. Consideration should be given to the effects of wear on the strength of casings. Regular inspection of wear bushing, calliper logs, ditch magnets, and casing pressure tests are methods of checking casing wear. Regular visual inspection of key well control components should be undertaken as below: Autochokes, target flange -
Prior to drilling out the deep intermediate casing on HP wells After each kick After 48 hours cumulative routine circulating through the chokes After 24 hours cumulative circulating through the chokes in a well kill situation if possible.
Failsafes, choke valves, target flanges wall thickness on long sweep bends should be checked between wells or if poor condition is discovered while checking the autochokes and target flanges in the above inspections. Detectors The gas detectors should be cleaned and inspected weekly. They should be tested every two weeks and prior to drilling into the high pressure objective of the well in accordance with manufacturers recommendations. Sensors And Monitors Trip tanks, flow meters and critical sensors/monitors should always be accurately calibrated. A special check/calibration should be carried out prior to drilling into the high pressure objective.
APP 1 - 10
HPHT Course - Appendix 1
REFERENCE I GRAPH FOR PREDICTING MAXIMUM ANTICIPATED TEMPERATURE WHILE DRILLING The following curves have been developed to show the relationship between static bottom hole temperature and temperatures at the mud line (390 feet) and rig floor (0 feet), when drilling is in progress in either 8-1/2" or 12-1/4" inch hole. The assumed static temperature at different depths are indicated on the graphs. Prediction of Wellhead Temperature while drilling 8 1/2" hole
160
X
ANNULAR FLOW TEMPERATURE (deg F)
155
150
X
390 ft
+
0 ft
X X
X 145
+
140
135
+ 130
+
+
125 15000
16000
17000
18000
19000
BHT TAKEN TO BE CONSTANT AT 420
Prediction of Wellhead Temperature while drilling 12 1/4" hole
ANNULAR FLOW TEMPERATURE (deg F)
210
X
390 ft
+
0 ft
X
200
+
190
180
X
X
X 170
+
+
+
160
Depth 12000 Static BHT
340
13000
14000
15000
16000
346
350
354
358
APP 1 - 11
HPHT Course - Appendix 1
REFERENCE II GRAPH PREDICTING PEAK SURFACE TEMPERATURE DURING ANNUAL FLOW This set of curves represents the worst case scenario for the sea floor flowing temperature conditions for wells with a static bottom hole temperature of 420 F. flowing at 50 MMCFD rate for one hour up the annulus. Any lower condensate content in the gas would result in a lower sea floor flowing temperature than that on the curves. Wellhead Transient Temperature Following One Hour Flow Period
ANNULAR FLOW TEMPERATURE (deg F)
400
380
E AT WR ) F/D C P MS DE M L ) L (50 F/D WE FT SC 00 MM 150 0 5 ( FT 00 190 LO
F TH
360
340
320 GAS / CONDENSATE INFLUX FLOWS THROUGH ANNULUS BETWEEN CASING AND DRILLSTRING PRODUCING GOR : 5000 SCF/BBL o CONDENSATE GRAVITY : 46 API
300
280
260 300
320
340
360
380
400 O
BOTTOM HOLE TEMPERATURE ( F)
APP 1 - 12
420
440
HPHT Course - Appendix 1
REFERENCE III ADDITIONAL INFORMATION REQUIRED WITH WELL CONSENT APPLICATION
1
BHP and BHT estimate for proposed well with offset well data including location, depth, pressure and temperatures, and method of estimating BHP and BHT.
2
Estimate of continuous and peak surface temperatures and method used.
3
The certified temperature ratings of well control system.
4
The surface gas handling system details including operating limitations and bypass capabilities.
5
BOP stack details including ram and outlet configuration.
6
Well control programme for the well.
7
Specialised crew training.
APP 1 - 13
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CONTENTS
PREFACE APP 2.1 INTRODUCTION APP 2.2 PLANNING AND PREPARATION APP 2.3 REQUIREMENTS TO SEISMIC AND GEOLOGICAL DOCUMENTATION, PROGNOSTICATION, MONITORING AND INTERPRETATION APP 2.4 OPERATIONAL REQUIREMENTS FOR DRILLING OF DEEP HIGH PRESSURE WELLS APP 2.5 OPERATOR AND CONTRACTOR QUALIFICATIONS APP 2.6 REQUIREMENTS TO EQUIPMENT APP 2.7 SUMMARY OF CRITICAL ASPECTS IN CONNECTION WITH HIGH PRESSURE DRILLING
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HPHT Course - Appendix 2
PREFACE The purpose of the present guidelines is to show how the provisions concerning drilling of deep high pressure wells in the Regulations concerning drilling and well activities and geological data collection in the petroleum activities can be met. Functional requirements in the regulations signify that there are various ways in which to comply with the regulations. The Norwegian Petroleum Directorate’s guidelines indicate one way to meet the requirements. The guidelines are not legally binding. The user may consequently select other technical and operational solutions than those indicated in the guidelines, provided it can be documented that the selected solutions meet the requirements of the regulations. The guidelines are intended to be considered as a whole. The user should consequently exercise caution in using only parts of it.
APP 2.1 INTRODUCTION If the operator when commencing drilling for the first time in an area does not have necessary information from previous drilling operations in the area, the Norwegian Petroleum Directorate will be able to assist in obtaining basic documentation. Scope The guidelines deal with issues that should be taken into consideration during drilling of deep high pressure wells. The term deep high pressure wells shall be understood as wells deeper than 4000 m (TVD) and/or has an expected shut-in wellhead pressure greater than or equal to 690 bar (10,000 psi). If the well is deeper than 4000 m (TVD), but has an expected shut-in wellhead pressure lower than 690 bar, the particular part of the guidelines dealing with 1035 bar equipment (15 000 psi) is not applicable. Even if a number of the recommendations made below are evaluations which will naturally have to be made for every drilling operation, the consequences of not giving sufficient consideration to these factors will be far more extensive in the case of deep high pressure wells than for more routine drilling operations.
APP 2 - 1
HPHT Course - Appendix 2
APP 2.2 PLANNING AND PREPARATION All wells should be planned on the basis of the most comprehensive regional survey of the pressure conditions available. If the regional picture indicates the probability of ending up with a high pressure well, the requirements relating to planning and preparation will increase. Important factors to be given particular consideration are: Casing string wear In connection with design of casing strings the operator should estimate expected casing string wear and should include necessary safety margins. During the drilling phase, the operator should give particular attention to signs indicating abnormal wear such as steel chips in the return flow from the well or abnormal wear of the wear bushing. When signs of abnormal wear are detected, logs should be run to verify the degree of wear. Important factors that should further be subject to consideration are suitability of steel quality (e.g. use of V-150 casings) and design assumptions (e.g. pressure and temperature) for casings with regard to production test. The need to run additional casings (e.g. 7" tie-back during production start) should be given special consideration. Drilling mud The choice of drilling mud should be considered in detail on the basis of well stability and well control, and should be tested prior to and during drilling at expected pressure and temperature conditions. The following should in particular be considered for the choice and use of drilling mud: Drilling mud (with the necessary admixtures) should be tested to the highest predicted temperature for the well during static and dynamic conditions in order to determine rheology and control of filter loss. These are critical parameters for the drilling, as a reduction of viscosity may impede well control, and an uncontrolled filter loss may result in “sticking pipe”. Another high temperature effect is dehydration of the drilling mud (“high temperature gelation”) resulting in a risk of “swabbing”. In connection with DST it is also important to have the drilling mud stability verified, as the drilling mud will remain static for considerable periods of time. The rheological behaviour of the mud is particularly important in the deeper layers of the well where the circulation pressure may contribute significantly to the hydrostatic pressure of the mud, entailing a risk of exceeding the fracturing pressure. Due to increased pressure and temperature in the well, the average specific density of the drilling mud will differ from the values measured on the surface. APP 2 - 2
HPHT Course - Appendix 2
Cementing Testing of cement mixtures should be carried out in accordance with the recommendations given for drilling mud. It is however important to carry out additional modelling in order to determine an exact circulation temperature. Exact testing of cement and admixtures is important to ensure good cement behind the casing string. The following factors should be given special consideration during cementing of high pressure wells: a) Cementing of liner in deep high pressure wells should be carried out so as to achieve a good mixture of the admixtures and uniform rheological properties. This can be done by using separate mixing tanks or by corresponding methods. b) Consider using two cement systems with different setting times. c)
Optimising cement properties with regard to, inter alia: -
filter loss hydration rheology setting times temperature short term strength long term strength (strength retrogression) gas density free water
In particular, the risk of gas migration should be given considerable attention. d) Displacement of cement with drilling mud requires consideration to be given to the following: -
optimum ratio between the well diameter and casing improved procedures for pumping of drilling mud prior to cementing use of compatible drilling fluids, spacers and cement mixtures optimising displacement velocity optimum use of centralisers rotation/reciprocation of casing/liners
e) Emphasise preparation of procedures/technologies for squeeze cementing of loss zones.
APP 2 - 3
HPHT Course - Appendix 2
An alternative to stage cementing may be to run a casing string first as liner and then carry out a tie-back to the wellhead. During such operation, with the primary cementing job in an open hole, there are good possibilities for a successful cementing operation. This solution may entail disadvantages which also have to be considered. It is the opinion of the Norwegian Petroleum Directorate that primary cementing of casing strings today in general is not carried out in a technologically satisfactory way. Improved mixing systems and process control should be developed in order that an adequate quality control of the mixing process can be carried out.
APP 2.3
REQUIREMENTS TO SEISMIC AND GEOLOGICAL DOCUMENTATION, PROGNOSTICATION, MONITORING AND INTERPRETATION
Geological and geophysical knowledge of the drilling locations is very important in order to obtain adequate prognoses. This means that experience from drilling of neighbouring wells is particularly important in assessing new prospects. Determining correct setting depth for casing will be essential in order to avoid problems, and knowledge of possible sand strings in transition zones may be required in order to avoid getting into critical situations. During drilling of such wells, the Norwegian Petroleum Directorate will consider very carefully the need for the operator to carry out an exact determination of formation tops by means of VSP logs (cf. Section 46 of the Drilling Regulations). Accuracy of geological prognoses is consequently of great importance. Furthermore it is necessary that prognoses and interpretations indicate what uncertainties can be expected, and indicate alternatives to the planned drilling programme. There should be a considerable flexibility with regard to alteration of for instance planned setting depth for casings if geology and pressure conditions differ from expected values. High pressure wells will always entail special and strict requirements to prognostication of pressure and temperature. Experience has shown that in the majority of cases where well control problems have occurred, there have been previous problems in connection with lost circulation. Consequently it will be of vital importance to a safe and efficient drilling operation to be able to predict the maximum expected pressure, as well as margins between fracturing pressure and pore pressure. During pressure prognostication it is therefore important that indicators such as D-exponent, gas content, cuttings and drilling mud temperature change are given adequate attention. During drilling, geological personnel will continuously and closely follow up prognostication and will immediately carry out the necessary deviation procedures. It is therefore important that communication between involved personnel on the rig and ashore is the best possible (e.g. operations geologist, drilling administration, well geologist and drilling supervisor). APP 2 - 4
HPHT Course - Appendix 2
APP 2.4
OPERATIONAL REQUIREMENTS FOR DRILLING OF DEEP HIGH PRESSURE WELLS
Organisation For planning and implementation of operations of this kind, it is necessary that the operator at all times has specially qualified personnel available for consultation, and that they take an active part in the planning of the work ashore as well as on board. On board the rig there should in addition to drilling supervisors and geologists also be stationed personnel with particular pore pressure expertise and with experience from the area during relevant drilling phases. The Norwegian Petroleum Directorate considers it to be of particular importance to carry out safety drills at regular intervals. Any deviation affecting safety that may come to light during such drills should be subject to critical deviation procedure. In addition to traditional drills such as fire and lifeboat drills, trip and flow drills, the Norwegian Petroleum Directorate will strongly recommend choke drills to be carried out. These drills should be carried out prior to drilling out of surface casing and intermediate casing. The well is circulated through choke lines to define pressure curves and response times during circulation through kill/choke lines at various rates. This drill will increase the familiarity of the personnel with such operations, and improve co-ordination between the driller and the choke operator. It is vital during high pressure drilling that the drilling crew is in no doubt as to what procedures to follow when well control equipment is activated. It is important that shut-in and circulation procedures are well drilled and understood. Good communication between all involved parties is important. Daily management and safety meetings will be necessary to ensure sufficient information between the parties involved.
APP 2 - 5
HPHT Course - Appendix 2
Operational requirements The following operational limitations should be considered: Weather conditions a) Requirements relating to acceptable weather prospects during drilling and testing of high pressure zones. In particular the necessity of having a meteorologist on board should be considered. b) Requirements relating to halting of operations if weather conditions cause helicopter and supply vessel accessibility to become impaired. c)
Requirements relating to halting of operations in the event of defined movements of the installation.
Drilling It is important that personnel on board the installation carry out thorough follow-up and interpretation of drilling and geological parameters, and carry out a continuous comparison with other wells in the area. If necessary the drilling rate will have to be reduced in order to maintain an acceptable control with relevant parameters. Tripping etc. During tripping in/out of the drillstring in the well the following should be taken into consideration: a) the need for a float-valve and circulation sub to be installed in the BHA before running the string b) that special procedures are drawn up for tripping in high pressure zones, e.g.: c)
APP 2 - 6
rotating the drillstring prior to circulation in order to reduce the gel strength seeing that circulation and “flow-checks” are carried out regularly
that the well during pulling of the drillstring is kept full with mud. When drilling a well with a small diameter, it is important to be able to circulate during pulling of the drillstring in order to prevent piston effect and resulting reduction of the bottom hole pressure.
HPHT Course - Appendix 2
Well killing In order to be prepared for handling a kill situation quickly, kill lines should be permanently connected to the cementing unit, alternatively have a permanent connection to a separate well killing system. Relief well It is important that plans for relief wells are drawn up together with the drilling programme. The plans should be regularly updated as drilling progresses. Based on directional measurements made in the well, there should be a regular assessment of suitable location(s) from where possible relief well(s) should be drilled. This will as a rule require the original well to be drilled with MWD from sea bed to TD. Furthermore, information on availability of installations and special equipment should be part of the emergency preparedness plans. Operators should enter into mutual agreements concerning use of installations, or agreements with drilling contractors concerning available drilling installations and special equipment (cf. also Section 42 of the Drilling Regulations). Well control A considerable part of the planning process in connection with deep high pressure wells should be related to ensuring that the drilling installation has suitable well control equipment to handle formation fluids under the expected volume, pressure and temperature conditions on the surface during circulation of a “kick”. The operator should in this connection consider the possibility of “bullheading” of “kicks” as an alternative to more traditional circulation procedures. Routines for “bull-heading” of kicks during drilling of deep high pressure wells should be considered. The reason for this is connected with the problems relating to safe handling of large volumes of hydrocarbons/gas on the surface. In connecting with planning of the well, volumes of reservoir fluid that may be produced on the surface for a given influx should be estimated. Furthermore, maximum circulation rates for surface equipment should be estimated. Also maximum flow rates for mud/gas separation equipment should be estimated during the planning stage. Furthermore, procedures for measures to be taken in the event that the capacity of the mud/gas separation system is exceeded, should be drawn up.
APP 2 - 7
HPHT Course - Appendix 2
Finally the risk of hydrate formation during a well control operation (e.g. during circulation) should be considered. Information from neighbouring wells (oil type, composition, “bubble point’, temperature) will be of particular importance in this type of evaluations. Other factors that should be considered are: a) the possibility of conducting gas/formation fluid direct to the burner boom without going via the choke manifold b) permanent installation of high pressure overboard dump lines from choke manifold c)
necessary additional instrumentation to the well control equipment to ensure that existing design criteria are not exceeded: -
temperature/pressure gauges on gas separator temperature/pressure gauges on the high pressure/low pressure side of the choke manifold flow indicator on all lines in the pressure system possibility of injection of antifreeze agents (e.g. methanol), upstream choke manifold instrumentation improvement (pressure and flow measurements) on the cementing unit.
Pressure control Careful evaluation of pressure conditions and formation integrity is important when drilling in transitional zones. The following parameters should be given special consideration: a) It is important that LOT/FIT is carried out in every new open hole interval, and where weaker zones are anticipated b) the need to run RFT at regular intervals, and where the pore pressure can be expected to change, should be considered c)
mud weights should be monitored closely to maintain full control of pore pressure and formation integrity
d) quality of available mud logging equipment and qualified personnel for follow-up of : -
APP 2 - 8
drilling parameters pore pressure stratigraphy early detection of “kicks”
HPHT Course - Appendix 2
Well testing During production testing of deep high pressure wells the following governing principles should be observed: a) a thorough check of all 1035 bar (15 000 psi) equipment b) use of permanent packers c)
use of additional mechanical circulation tools
d) limited cable operations during test phase e) consider alternative media when choosing completion fluid with a view to physical and chemical stability during high pressures and temperatures Due to the corrosive nature of the zinc bromide, alternative media should be considered during testing.
APP 2.5
OPERATOR AND CONTRACTOR QUALIFICATIONS
It is of vital importance to a successful drilling operation that the company’s personnel who are responsible for planning and implementation of deep high pressure wells have experience from corresponding drilling operations, and have a thorough knowledge of the area in question. With regard to the manning situation, the following key persons should be taking part in the operations during drilling of high pressure wells: Contractor personnel Through his internal control system, the operator will ensure that the drilling contractor and service contractors comply with the qualification requirements of the company, cf. Section 19 of the Drilling Regulations. In particular the operator should focus attention on ensuring thorough professional qualifications for personnel engaged in cementing, drilling and mud operations. It is of the utmost importance that the crew of the drilling installation function as a well coordinated team, and that procedures and routines are well established between the drilling contractor and the operator. This will as a rule exclude the use of a new installation/new crew for drilling of high pressure wells.
APP 2 - 9
HPHT Course - Appendix 2
Furthermore it will be of great importance to a successful operation that key personnel has previous experience from corresponding drilling operations, so that the necessary feeling of safety can be achieved on board. For example, it is not uncommon that this type of wells are drilled with much higher background gas level than in the case of more traditional drilling. Inexperienced drilling personnel may react inappropriately if they are not used to such situations. Regular safety meetings will be necessary, inter alia to ensure that involved personnel acquire adequate understanding of the physical/reservoir related principles that may cause a high background gas level during drilling under such conditions. It is also of importance that replacement of personnel does not lead to reduced continuity and reduced safety in the operation.
APP 2.6
REQUIREMENTS TO EQUIPMENT
It is important that evaluation and choice of drilling installation and drilling equipment is based on expected maximum pressure and temperature conditions, and requirements to maximum loads, hoisting capacity, mixing capacity and storage capacity. Trip tank, flow meter, mud logging instruments and other critical sensors should be subjected to a thorough maintenance and calibration programme. When there is a probability of encountering H2S or CO2, the drillstring, casing, wellhead, well control and kill systems shall be designed to be able to handle such gases, cf. Section 16 of the Drilling Regulations. Installation Requirements to the following equipment packages should be important when evaluating drilling installations for drilling of deep high pressure wells: a) Use of top-drive may contribute to reducing the risk of a stuck pipe, as well as reduce the probability of swabbing. Top-drive should be used when drilling such wells; b) the top kelly valve should be able to close during full flow conditions; c)
the installation should have sufficient loading and hoisting capacity for handling heavy casing;
d) drillstring and collars should be subjected to a thorough inspection programme;
APP 2 - 10
HPHT Course - Appendix 2
e) the mud system should have: -
-
sufficient capacity (pumping effect and pipe dimensions) for quick weigh-up of mud in the active system, as well as mixing of new drilling mud in the event of lost circulation; mud agitator with sufficient power reserve for reduced scaling of weight substances (baryte) in mud tanks; high quality particle control system with sufficient number and quality of shale shakers, mud cleaners and centrifuges; acceptable ventilation, in particular if oil- based mud is used; seals designed for high temperatures.
The mud/gas separator system (“poor boy degasser”) should be designed to handle the maximum anticipated flow rate that may occur in a well. If the mud/gas separator system is not designed to handle the maximum anticipated flow rates, it is important that acceptable bleed-off facilities are installed. An alternative routing of the fluid/gas flow may be directly from the choke manifold to high pressure overboard dump-lines. If the return is dry gas, it should be possible to conduct it directly to the burner boom for burning. It is important that well established procedures exist for the rig personnel, if dumping overboard is the alternative when the mud/gas separator capacity is exceeded. The instrumentation should include pressure sensors to measure the differential pressure over the return line for the mud/gas separator. The choke operator should be able to read pressure differences directly from a suitably located panel. The cementing unit should be: a) designed for at least 1035 bar (15,000 psi) working pressure; b) equipped with a fluid additive system and circulation mixer when mixing of heavy cement mixtures are required (specific weight 2.3 - 2.4 g/cm3); c)
the mixing system should have sufficient capacity with regard to rate, pressure etc. and should be fitted with “batch”-tank or similar method or cementing liners.
APP 2 - 11
HPHT Course - Appendix 2
The BOP system should be: a) designed for at least 1035 bar (15,000 psi) working pressure; b) fitted with “ram-packers” and annular packers designed for high temperatures; c)
fitted with “O” rings designed for high temperatures;
d) fitted with “fail-safe” kill/choke valves designed to be able to close during dynamic conditions at 1035 bar (15 000 psi) working pressure; e) equipped with kill/choke line designed for the expected pressure and temperature (including flexible parts and elastomers). It is important that also the production and testing equipment is designed to be able to meet the expected flow rates, pressure and temperatures. Finally there should be sufficient instrumentation of well control equipment to ensure that the equipment is not subjected to higher pressure or temperatures than it is designed for. To ascertain that all equipment has correct pressure rating, it is important to make a thorough check of the smaller components of a pressure system, in particular components with a high replacement frequency. Examples may be: a) b) c) d) e)
valves valve parts hoses adaptors connection arrangement
In connection with high pressure testing it is important that there is a stock of spare parts of high pressure components on the installation. What spare parts that should be kept in stock will depend on previous experience. As a minimum the spare part supply should cover components that are particularly exposed to wear at high pressures: a) choke valves b) valve parts c) gaskets etc. It is important that equipment as described above is subject to an efficient maintenance system.
APP 2 - 12
HPHT Course - Appendix 2
Equipment limitations In addition to high pressures, also high temperatures will be a problem during drilling of this type of wells. Downhole equipment such as LUB, electronic instruments etc. have proved to represent considerable weaknesses in electronic components. Temperatures in excess of 180°C (130°C - 140°C for LUB), pressures in excess of 1000 bar and accelerations during drilling up to 1000G have proved to be too demanding for existing equipment. Other limitations may be: a) corrosion b) pipe wear (casing, drillstring, BHA etc.) c)
mechanical pipe limitations
d) operational limitations well ageing reduced drilling progress Special equipment Particularly in the case of rigs with large built-in compensation for “riser tension”, flexible high pressure hoses will be exposed to considerable stress effects from wind as well as from waves in the moon-pool” area. The transition zones of the hoses between the rigid and the flexible parts will be particularly exposed. In the course of time the most affected areas may develop micro-cracks in the protective layers with increasing corrosion of the load-bearing part of the hoses. With more extensive cracking the hose may also be liable to frost burst. The Norwegian Petroleum Directorate has consequently focused on the life span and the integrity of flexible choke and kill hoses for drilling of deep high pressure wells. The scope of application of the hoses should be logged and they should be subject to a systematic programme of inspection and maintenance. As a rule there will also be high temperatures in deep high pressure reservoirs. The above mentioned hoses will however not be exposed to reservoir temperatures, even during circulation of deep “kicks”. The time required for transportation of gas and mud up to the surface will be sufficient to cause a considerable temperature reduction.
APP 2 - 13
HPHT Course - Appendix 2
In the case of sea bed and surface equipment, temperature limits will have to be considered in relation to expected values during testing. A critical area in this connection are BOP valves with flexible (elastomers) components which during the test phase may become subjected to temperatures close up to bottom hole temperature. For relevant high pressure wells, the operator should therefore attach particular importance to verifying the above mentioned well control equipment according to the expected pressure and temperature conditions.
APP 2.7
SUMMARY OF CRITICAL ASPECTS IN CONNECTION WITH HIGH PRESSURE DRILLING
Planning and drilling of deep high pressure wells is essentially not very different from the usual practice in ordinary drilling operations. In the text above the focus has been on matters requiring more attention and greater accuracy in order for drilling of deep high pressure wells to be successful. Key areas requiring a great deal of attention are: a) geological and seismic prognostication of neighbouring wells and mapping of the area b) continuous updating of geological and seismic prognoses. All available methods should be considered used, e.g. “look ahead VSP” c)
exact prognostication of pore pressure, rock burst pressure, temperatures and flow potential
d) careful follow-up of pressures and temperatures to enable prognoses to be updated and, if applicable, revised e) thorough understanding of physical and chemical processes that occur in a well control situation during drilling of deep high pressure wells f)
adequate well planning and preparation, follow-up and control
g) exact determination of setting depth for casing to separate possible loss zones from high pressure zones h) exact determination of setting depth for casing above the pressure build-up zone
APP 2 - 14
HPHT Course - Appendix 2
i)
evaluation of drilling related and geological deviations during the drilling operation to ensure continuous updating of prognoses, in order that necessary adjustments can be carried out (setting depth for casing, introduction of additional intermediate casing, mud weight etc.)
j)
early detection of kicks and requirements to accurate recording of volume changes
k)
cementing of deep casings and liners gas migration during setting; no isolation of problem zones due to lost return; mixing problems during use of heavy cement mixtures; well cleaning (displacement of drilling fluid); mixing of high specific weight mixtures;
l)
ensure that equipment and material (including chemicals) can withstand expected pressures and temperatures
m) qualifications and experience of company and contractor personnel n) organisation and operational requirements o) suitability of the drilling installation with regard to equipment specifications, operation and maintenance of equipment p) production testing requirements q) drilling mud verification of the physical and chemical properties of the drilling mud at high pressures and temperatures during static and dynamic conditions r)
programme for control, maintenance and calibration of logging instruments and critical sensors
s)
thoroughly prepared contingency plans, including planned relief well
t)
upgrading of the drilling fluid/gas separating system
APP 2 - 15
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APPENDIX 3. HPHT MUD PRESENTATION
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APPENDIX 4. HPHT CEMENT PRESENTATION
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