2003 SPE/IADC Drilling
Conference
SPE/IADC 79880
Well Control Procedures for Dual Gradient
Drilling as Compared to Conventional Riser
Drilling
February 21, 2003
1
21.1
Well Control Procedures for Dual
Gradient Drilling as Compared to
Conventional Riser Drilling
Dr. Jerome J. Schubert
Dr. Hans C. Juvkam-Wold
Texas A&M University and
Dr. Jonggeun Choe
Seoul National University
2
Overview
Introduction to Dual Gradient Drilling
Goal of the SMD Well Control Team
Comparison of Well Control for DGD
and Conventional Riser Drilling
Conclusions
21.1-3
What is Dual Gradient Drilling?
Novel drilling system where the annulus
pressure at the seafloor is reduced to
near seawater HSP.
Results in a pressure gradient from the
rig to the seafloor near that of seawater
HSP, and mud gradient from the
seafloor to the bottom of the hole
21.1-4
Dual Gradient Concept
Seawater
Hydrostatic
SMD Mud
DEPTH
Hydrostatic
Conventional
Hydrostatic
PRESSURE 21.1-5
How is the dual gradient
achieved?
Seafloor pumps and an external return
line
Shell
DeepVision
SubSea MudLift Drilling
Injecting hollow glass spheres near the
seafloor
Maurer Technology
21.1-6
Goal of the SMD Well Control
Team
Develop Well Control Procedures for the
SMD JIP that were at least as safe if not
safer than conventional floating drilling
operations.
The authors feel that these procedures
are applicable for most DGD methods.
21.1-7
How was the goal met?
We had to study the state of the art in
conventional deepwater drilling
Determine what had to be modified or
re-written for the SMD project.
New procedures were written and re-
written as the project progressed.
21.1-8
How was the goal met?
Perform risk analysis in the form of
HAZOP
Modify or re-write procedures based on
HAZOP
If the procedure was re-written, a new
HAZOP had to be performed
21.1-9
How was the goal met?
Finally, most of these well control
procedures were proven on a DGD test
well.
21.1-10
Measurement of KCP
KCP is measured identically for DGD
and Conventional
No DSV – rate must be greater than the
freefall rate of the mud
W/DSV – must also measure the DSV
opening pressure
21.1-11
Kick Detection
Kick indicators
Drilling break
Flow increase
Pit gain
Decrease in circulating pressure
Increase in pump speed
Well flow with pumps off
Increase in torque, drag, fill
21.1-12
Flow Increase
MLP Increase
Kick Begins
MLP Inlet P Constant
DPP Decrease
21.1-13
Well Flow w/ Pumps Off
No DSV 700
U-tube Rate, gpm
600
U-tube makes this
500
much more difficult 400
Normal U-tube
Trend analysis is 300
needed 200 U-tube + kick
100
0
0 5 10 15 20 25
Time, min
21.1-14
Well Flow w/ Pumps Off
With DSV
Shut down Rig Pumps
Continued operation of the Sea Floor Pump
will indicate well flow.
21.1-15
Pit Gain
W/DSV there is no difference
No DSV – No difference in kick
detection. However pit gain after shut-in
is equal to the pit gain after complete u-
tube less the theoretical u-tube volume.
21.1-16
Shut-in on kick
With DSV, SI is very similar to
conventional
Shut down rig pumps,
Check for flow
If flowing, shut down MLP
Close BOP
With No DSV, preventing additional
influx is difficult during u-tube.
21.1-17
Shut-In on Kick
Kick Detected
Slow MLP
Rig Pumps Constant
MLP inlet P & DPP Increase
21.1-18
Shut-in Procedures
After the MLP and Rig pumps are
returned to the pre-kick rates:
Allow the DPP and MLP Inlet P to stabilize
Record stabilized pressures and rates
Continue to circulate at constant Rig Pump
Rate and Pressure until kick fluids are
circulated out.
DPP is maintained by adjusting MLP Rate
21.1-19
SIDPP
SIDPP is somewhat different.
W/DSV very similar to measurement of
SIDPP with a float and is the
Post kick DSV opening pressure less the
Pre kick DSV opening pressure.
21.1-20
SIDPP – No DSV
Upon kick detection, slow MLP to pre-
kick rate
Record the Stabilized DPP
SIDPP CircDPPPostKick CircDPPPr eKick AFP
21.1-21
Calculation of KWM
Conventional
SIDPP
KWM OWM
0.052 TVD
Dual Gradient
SIDPP
KWM OWM
0.052 (TVD WD )
21.1-22
DPP Pressure Decline Schedule
Calculating ICP is no different
FCP Conventional
FCP=KCP x KWM / OWM
21.1-23
FCP DGD
KWM
FCP ( Pdp _ bit AFP ) DSVset AFP
OWM
Pdp _ bit Frictional pressure in the drillstring and
bit pressure drop
AFP Annular Friction Pressure
DSVset The difference in hydrostatic pressure between
the KWM and seawater at the mudline
21.1-24
Driller’s Kill & Wait & Weight
Essentially the same for DGD and
Conventional except for the differences
noted earlier in measurement of SIDPP
and shut-in.
MLP is used as the adjustable choke
21.1-25
Other Kills
Volumetric
Lubrication
Stripping
Procedure have been developed but are
not included in this paper.
21.1-26
Conclusions
The u-tubing that is expected in DGD
causes some difficulties in many
aspects of well control – none of them
are show stoppers
The use of a DSV eliminates the
problems associated with the u-tube
phenomenon, but creates some of it’s
own
21.1-27
Conclusions
The complications from the DSV are
outweighed by the benefits
DSV makes well control seem more
conventional, but it is not absolutely
necessary.
21.1-28
Conclusions
Well control for DGD has been
developed to a point where it is at least
as safe if not safer than conventional
riser drilling.
A well control training program for DGD
will be essential for safe and efficient
operations.
21.1-29
IADC/SPE 79880
The End
30
DGD with Seafloor Pumps
21.1-31
Recent Advances in Ultra-deepwater Drilling
Calls for New Blowout Intervention Methods
Speaker:
Ray Tommy Oskarsen
Co-authors:
Jerome Schubert
Serguei Jourine
32
Sponsors and
Participants
Phase 1
Texas A&M
University
Cherokee Offshore
Engineering
Global Petroleum
Research Institute
Offshore Technology
Research Center
Minerals
Management Service
21.1-33
Drilling in ultra-deep
water
Window between pore pressure and fracture pressure gets narrower
High pore pressures and low fracture pressures lead to more casing
strings
More casing strings leads to more time spent on location
This leads to larger wellheads, even larger and heavier risers, and
finally to bigger and more expensive rigs
With a standard BOP and many casing strings, you may not reach
target.
Well control is more difficult - because of the pore pressure / fracture
pressure proximity, and long choke lines with high frictional pressure
drops
21.1-34
Deepwater drilling
projects
Dual Gradient
Drilling
Casing Drilling
Expandable
Casing
SX-riser
21.1-35
Blowout Containment
Procedures?
The most recent blowout containment
procedures can be found in the “DEA – 63,
Floating Vessel Blowout Control,” which was
released September 1990.
DEA - 63 considered deep water up to 1500’
Envisioned “future work” in water as deep as
3500’
21.1-36
DEA-63 Cont.
Focus on capping measures
No Dual Gradient Drilling
Concluded with
recommendations for more work
Are We Ready?
21.1-37
Safety Pyramid
Fatality
LTA
OSHA Recordable
At-Risk
Behaviors
21.1-38
Albert H. Schultz - DuPont
Statistics
Podio Study of OCS Blowouts, 1996
1 Blowout for every 285 wells drilled
2.7% of the wells studied deeper than 15,000 ft
These accounted for 8% of the blowouts
Wylie and Visram, 1990
1 Blowout for every 110 kicks
SINTEFF Deep Water, 2001
52 kicks for every 100 wells drilled
79% of kicks had significant problems
At least 21% of kicks resulted in loss of all or part of
the well
1992 to 2001 we drilled 1015 wells in water >1500 feet
deep
21.1-39
Blowout Pyramid
1 Blowout
20 Well Bore Losses
80 Significant Well Control
Problems
110 Kicks
? At Risk Operations
200+ Wells Drilled
21.1-40
Are wells in deep water likely to
occur more frequent?
Higher pore pressure gradients
Difficulties in handling highly
compressed gas
Increased exposure time
Longer open hole sections
More tripping time
Increased risk of lost circulation
Odds are not in our favor!
21.1-41
Deep Water Blowouts
Proposed practical solutions:
capping,
injecting solidified reactive fluids,
dynamic kill/momentum kill,
inducing bridging
21.1-42
Fastest and Least Expensive
Mode of11Control Duration
7%
9 4% 15%
9
10%
5
14%
19
39 % 3 5 14%
36%
Bridging BOP 0-1 hour
1 hour-1 day
Cement Depletion 1-3 days
Equipment Mud 3 days-1 week
1 week- 1 month
Relief Well Missed > 1 month
Missed
FOR MORE INFO...
SPE 53974, IADC/SPE 19917, http://www.boots-coots-iwc.com /references/ 02_Ultra-
deepwater %20blowouts.htm
21.1-43
Bridging Scenarios
Total
1 4 Massive Solid Wellbore Wellbore Bridging
16000
Gas Iinflow and Outflow PR
14000
12000
Production Collapse
10000
Pre sure, psi
Unstable
5 6 7
8000
6000 5000
4000
2000 Concentration 4000 Solid
0
Load
0 2000000 4000000 6000000 8000000 1000000 1200000
Pressure
Gas0 Rate, Mscf
0 3000
Bridge
2000
1000
Time,
Moderate
sec
3 Distance, m
0
0 50000
Flow Rate
100000 150000
Negligible Solid Stable Fluid- Bridge Formation
Production Solid Flow Failure Failure
0 5000 10000 15000 20000
0
Pressure, psi
5000 Pressure Profiles
Overburden
Hydrostatic
Stable
10000 Fluid
Depth, ft
Stable Fluid
Blowout Underground Blowout
15000
Flow
20000
2
25000
21.1-44
1. Well is out of Control
16000
14000
12000
Gas Iinflow and Outflow PR
1
10000
Presure, psi
8000
6000
4000
1. Wellbore and Reservoir
Performance Relationships
2000
0
0 2000000 4000000 6000000 8000000 1000000 1200000
Gas0 Rate, Mscf
0
2. Stress and Pressure
Distributions
3 3. Stress-Strength
Relationships
0 5000 10000 15000 20000
Flow and Geomechanics
0
Pressure, psi
5000 Pressure Profiles
Models
Overburden
Hydrostatic
10000 Fluid
Depth, ft
15000
2
20000
25000
21.1-45
2. Wellbore Instability
4
Unstable
3. Stress-Strength
Relationships
4. Solid Production Potential
Moderate
Wellbore Stability Model
3
Stable
21.1-46
3. Solid Production
4 Massive Solid Production
5 4. Solid Production Potential
Concentration
5. Actual Solid Production
Time, Solid Production Model
sec
Distance, m
Negligible Solid Production
Stable Fluid
Flow Blowout
21.1-47
4a. Wellbore Collapse
Total Wellbore
Massive Solid Production Wellbore
Collapse Bridging
5 5000
4000
6
3000
Pressure
5. Actual Solid Production
2000
1000
0
0 50000
Flow Rate
100000 150000 6. Outflow Performance with
Actual Solid Load
Negligible
Solid Flow and Geomechanics
Production Models
21.1-48
4b. Bridge Formation
6 6. Outflow Performance with
5000
4000
7 Actual Solid Load
7. Bridge and Formation
3000
Pressure
Bridge
Stability
2000
1000
0
0 50000
Flow Rate
100000 150000
Flow and Geomechanics
Models
Stable
Fluid-Solid
Flow
Blowout
21.1-49
5. Bridge Stability
Wellbore
Bridging
7 7. Bridge and Formation
Stability
Flow and Geomechanics
Models
Formation
Failure
Bridge
Failure
Underground
Blowout Blowout
21.1-50
Deep Water Tendency
Total
1 4 Massive Solid Wellbore Wellbore Bridging
16000
Gas Iinflow and Outflow PR
14000
12000
Production Collapse
10000
Pre sure, psi
Unstable
5 6 7
8000
6000 5000
4000
2000 Concentration 4000 Solid
0
Load
0 2000000 4000000 6000000 8000000 1000000 1200000
Pressure
Gas0 Rate, Mscf
0 3000
Bridge
2000
1000
Time,
Moderate
sec
3 Distance, m
0
0 50000
Flow Rate
100000 150000
Negligible Solid Stable Fluid- Bridge Formation
Production Solid Flow Failure Failure
0 5000 10000 15000 20000
0
Pressure, psi
5000 Pressure Profiles
Overburden
Hydrostatic
Stable
10000 Fluid
Depth, ft
Stable Fluid
Blowout Underground Blowout
15000
Flow
20000
2
25000
21.1-51
Rock Properties
In Progress
Center for Tectonophysics, TAMU
21.1-52
Well, if it doesn’t
bridge….
Present thinking: Relief well is the
only option
MMS NTL 99-G01
Requires assurance that operator is
capable of handling blowout operations
such as relief well
21.1-53
Dynamic Kill Simulator
BOP SEAFLOOR
21.1-54
0.052x20,000x16 = 16,640
0.052(10,000x8.6 + 10,000x23,4) = 16,640
8.6 ppg 23.4 ppg
16 ppg
10,000 ft
20,000 ft
4,472 psi 16,640 psi
21.1-55
Dynamic Kill
Comparison
20,000’ onshore well with 16 ppg
20,000’ deepwater well in 10,000’ of
water with 16 ppg
10000’ of 8.6 + 10000’ of 23.4 ppg?
Friction pressures developed during
dynamic kill could be much less in a
deep water well
Can we choke it back at the mudline?
How?
21.1-56
Dynamic Kill Simulator
Static Part:
STATIC DATA
Common User Input
Static Data During Simulation
TIME
Dynamic Part : DEPENDENCIES
Data that Changes with Time
Transient Effects PRESSURE
CALCULATION
Computational Part:
PressureCalculations for Given
Moment in Time
21.1-57
Static Part
#Relief Wells?
Injection Points?
Ha
ng
Dua
ing
Reservoir properties D
BO rillst
lG
P? rin
radi
g?
Formation fluid
e
nt?
Well geometry:
Number of relief BOP BOP BOP BOP
wells
Blowing well
geometry
Inflow and outflow
of kill fluid
21.1-58
Deep Water Blowouts
4 deepwater sustained
underground blowouts
controlled by Boots &
Coots
3 broached mud line
gas flows (20” casing
set BOPs installed)
1 BOP Failure Gas
Blowout
No oil blowout has
FOR MORE INFO... reported to date
Flak L.: “Control of Well Issues”, “Marine Insurance – Facing the Changed World”,
International Union of Marine Insurance-NEW YORK – 2002, on-line http://www.iumi-
newyork -2002.org/Flak.htm
21.1-59
Static Part:
Determine
Uncontrolled Flow
Below Casing
Seat:
Drilling X X X X X X X X X X X X
Completion X X X X X X X X X
Production X X X X X X X
21.1-60
Deliverables for Dynamic Kill
Simulator
Fully Three Phase Transient Multiphase Flow
Model
Any Possible Well Configuration
All Possible Leakage Points
Dual Gradient Drilling Option
Multiple Influx Zones
Lost Circulation at Weak Zones
Newtonian and Non-Newtonian Kill Fluid
Bridging Prediction
Simulator Written in Java Code
21.1-61
Comparison of Dynamic Kill
Simulators Available
Inflow Kill Fluid
through Dual Any (Newtonian, Fluid Loss Available
Drillpipe or Gradient Leakage Bingham plastic, in Openhole Inclined Transient Bridging for us to
Relief Well Drilling Scenario Power law) Section Wellbore Effects Prediction use
Sidekick X X X ?
OLGA X X X X X
Petrobraz X X X
Dyn-X X X X X X
ADR/Cherokee X X X X X X X X X
Dynamic kill simulator
will be a tool for us to
develop kill
procedures.
21.1-62
Questions we need to
answer:
Can a well be dynamically killed when
half the well bore is gone?
How do you dynamically kill a well
when half the well is full of sea water?
How do you model the kill operation?
Will it bridge?
Can you induce bridging?
Do you want it to bridge?
21.1-63
Question Cont.
With our high reliance on bridging
Should we not understand the mechanisms of
bridging better than we do now?
Should we gain an understanding of the factors
that contribute to bridging?
Are there ways that we can promote bridging?
Should we not have a mechanism where we
can predict where the bridge is likely located?
In long open hole sections, do we really want
the well to bridge?
21.1-64
Questions Cont.
Only 1 DGD well has been drilled to
date
Little thought has been given as to
how a blowout on a Dual Gradient
well will be killed.
Can we expect to be able to use
“conventional” blowout containment
methods?
21.1-65
Deliverables
A best practice guide for blowout procedures.
A study to determine the likelihood of of a well bridging.
Ways to induce bridging.
The consequences of undesirable bridging.
A dynamic kill simulator for conventional and dual density
wells
Blowout control methods for dual density wells.
Cost estimate for deepwater intervention.
A final report in electronic format.
21.1-66
