SPEIADC 79880

1
2003 SPE/IADC Drilling Conference

• SPE/IADC 79880
• Well Control Procedures for Dual Gradient
  Drilling as Compared to Conventional Riser
  Drilling
• February 21, 2003

2
Well Control Procedures for Dual Gradient
Drilling as Compared to Conventional Riser
Drilling
21.1

• Dr. Jerome J. Schubert
• Dr. Hans C. Juvkam-Wold
• Texas AM University and
• Dr. Jonggeun Choe
• Seoul National University

3
Overview

• Introduction to Dual Gradient Drilling
• Goal of the SMD Well Control Team
• Comparison of Well Control for DGD and
  Conventional Riser Drilling
• Conclusions

4
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

5
Dual Gradient Concept
6
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

7
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.

8
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.

9
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

10
How was the goal met?

• Finally, most of these well control procedures
  were proven on a DGD test well.

11
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

12
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

13
Flow Increase
14
Well Flow w/ Pumps Off

• No DSV
• U-tube makes this much more difficult
• Trend analysis is needed

700
gpm
600
500
400
tube Rate,
300
200
-
100
U
0
0 5 10
15
20
25
Time, min
15
Well Flow w/ Pumps Off

• With DSV
• Shut down Rig Pumps
• Continued operation of the Sea Floor Pump will
  indicate well flow.

16
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.

17
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.

18
Shut-In on Kick
19
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

20
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
SIDPP No DSV

• Upon kick detection, slow MLP to pre-kick rate
• Record the Stabilized DPP

22
Calculation of KWM

• Conventional
• Dual Gradient

23
DPP Pressure Decline Schedule

• Calculating ICP is no different
• FCP Conventional
• FCPKCP x KWM / OWM

24
FCP DGD
25
Drillers 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

26
Other Kills

• Volumetric
• Lubrication
• Stripping
• Procedure have been developed but are not
  included in this paper.

27
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 its own

28
Conclusions

• The complications from the DSV are outweighed by
  the benefits
• DSV makes well control seem more conventional,
  but it is not absolutely necessary.

29
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.

30
IADC/SPE 79880

• The End

31
DGD with Seafloor Pumps
32
Speaker Ray Tommy OskarsenCo-authors Jerome
Schubert Serguei Jourine
Recent Advances in Ultra-deepwater Drilling Calls
for New Blowout Intervention Methods
33
Sponsors and Participants

• Phase 1
• Texas AM University
• Cherokee Offshore Engineering
• Global Petroleum Research Institute
• Offshore Technology Research Center
• Minerals Management Service

34
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

35
Deepwater drilling projects

• Dual Gradient Drilling
• Casing Drilling
• Expandable Casing
• SX-riser

36
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

37
DEA-63 Cont.

• Focus on capping measures
• No Dual Gradient Drilling
• Concluded with recommendations for more work

Are We Ready?
38
Safety Pyramid
Fatality
1
29
LTA
300
OSHA Recordable
3000
At-Risk Behaviors
Albert H. Schultz - DuPont
39
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 gt1500
  feet deep

40
Blowout Pyramid
1 Blowout
20 Well Bore Losses
80 Significant Well Control Problems
110 Kicks
? At Risk Operations
200 Wells Drilled
41
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!
42
Deep Water Blowouts

• Proposed practical solutions
• capping,
• injecting solidified reactive fluids,
• dynamic kill/momentum kill,
• inducing bridging

43
Fastest and Least Expensive
Mode of Control Duration
FOR MORE INFO...
SPE 53974, IADC/SPE 19917, http//www.boots-coots
-iwc.com /references/ 02_Ultra-deepwater
20blowouts.htm
44
Bridging Scenarios
45
1. Well is out of Control
46
2. Wellbore Instability
47
3. Solid Production
Concentration
Time, sec
Distance, m
48
4a. Wellbore Collapse
49
4b. Bridge Formation
Bridge
50
5. Bridge Stability
51
Deep Water Tendency
52
Rock Properties
53
Well, if it doesnt 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

54
Dynamic Kill Simulator
SEAFLOOR
55
0.052x20,000x16 16,640
0.052(10,000x8.6 10,000x23,4) 16,640
20,000 ft
16,640 psi
56
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?

57
Dynamic Kill Simulator

• Static Part
• Common User Input
• Static Data During Simulation
• Dynamic Part
• Data that Changes with Time
• Transient Effects
• Computational Part
• Pressure Calculations for Given Moment in Time

58
Static Part

• Reservoir properties
• Formation fluid
• Well geometry
• Number of relief wells
• Blowing well geometry
• Inflow and outflow of kill fluid

59
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 reported to date

FOR MORE INFO...
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
60
Static Part Determine Uncontrolled Flow

• Below Casing Seat

61
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

62
Comparison of Dynamic Kill Simulators Available
Dynamic kill simulator will be a tool for us
to develop kill procedures.
63
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?

64
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?

65
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?

66
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.