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Offshore Drilling Challenges and Opportunities
© 2012 Chevron U.S.A. Inc.
J. Keith CouvillionChevron U.S.A. Inc.
October 18, 2012
Cautionary StatementCAUTIONARY STATEMENTS RELEVANT TO FORWARD-LOOKING INFORMATION FOR THE PURPOSE OF
“SAFE HARBOR” PROVISIONS OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995
This presentation of Chevron Corporation contains forward-looking statements relating to Chevron’s operations that are based on management’s current expectations, estimates and projections about the petroleum, chemicals and other energy-related industries. Words such as “anticipates,” “expects,” “intends,” “plans,” “targets,” “forecasts,” “projects,” “believes,” “seeks,” “schedules,” “estimates,” “budgets,” “outlook” and similar expressions are intended to identify such forward-looking statements. These statements are not guarantees of future performance and are subject to certain risks, uncertainties and other factors, some of which are beyond the company’s control and are difficult to predict. Therefore, actual outcomes and results may differ materially from what is expressed or forecasted in such forward-looking statements. The reader should not place undue reliance on these forward-looking statements, which speak only as of the date of this presentation. Unless legally required, Chevron undertakes no obligation to update publicly any forward-looking statements, whether as a result of new information, future events or otherwise.
Among the important factors that could cause actual results to differ materially from those in the forward-looking statements are: changing crude oil and natural gas prices; changing refining marketing and chemical margins; actions of competitors or regulators; timing of exploration
© 2012 Chevron U.S.A. Inc.
oil and natural gas prices; changing refining, marketing and chemical margins; actions of competitors or regulators; timing of exploration expenses; timing of crude oil liftings; the competitiveness of alternate-energy sources or product substitutes; technological developments; the results of operations and financial condition of equity affiliates; the inability or failure of the company’s joint-venture partners to fund their share of operations and development activities; the potential failure to achieve expected net production from existing and future crude oil and natural gas development projects; potential delays in the development, construction or start-up of planned projects; the potential disruption or interruption of the company’s net production or manufacturing facilities or delivery/transportation networks due to war, accidents, political events, civil unrest, severe weather or crude oil production quotas that might be imposed by the Organization of Petroleum Exporting Countries; the potential liability for remedial actions or assessments under existing or future environmental regulations and litigation; significant investment or product changes under existing or future environmental statutes, regulations and litigation; the potential liability resulting from other pending or future litigation; the company’s future acquisition or disposition of assets and gains and losses from asset dispositions or impairments; government-mandated sales, divestitures, recapitalizations, industry-specific taxes, changes in fiscal terms or restrictions on scope of company operations; foreign currency movements compared with the U.S. dollar; the effects of changed accounting rules under generally accepted accounting principles promulgated by rule-setting bodies; and the factors set forth under the heading “Risk Factors” on pages 29 through 31 of the company’s 2011 Annual Report on Form 10-K. In addition, such statements could be affected by general domestic and international economic and political conditions. Other unpredictable or unknown factors not discussed in this presentation could also have material adverse effects on forward-looking statements.
Certain terms, such as “unrisked resources,” “unrisked resource base,” “recoverable resources,” and “oil in place,” among others, may be used in this presentation to describe certain aspects of the company’s portfolio and oil and gas properties beyond the proved reserves. For definitions of, and further information regarding, these and other terms, see the “Glossary of Energy and Financial Terms” on pages 58 and 59 of the company’s 2011 Supplement to the Annual Report and available at Chevron.com.
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Outline
Offshore Defined
Drilling Vessels
Drilling Challenges
Permitting
New Technology Opportunities
© 2012 Chevron U.S.A. Inc. 3
New Technology Opportunities
The Future
Questions
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Offshore Defined
© 2012 Chevron U.S.A. Inc. 4
Government Controlled Offshore Lands United States - Exclusive Economic Zone(3 Billion Acres – 4.1 Million Sq. Miles)
© 2012 Chevron U.S.A. Inc. 5
Source: DOI
Gulf of Mexico Seafloor Bathometry --Shelf, Deepwater and Ultra Deepwater
Texas
Louisiana
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3
Deepwater Gulf of Mexico Bathymetry
Atwater ValleyGreen Canyon
Salt Province
TexasLouisiana
Continental Shelf
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Green Canyon
Salt Province
Abyssal Plain
30 Miles
48 km
Walker Ridge
Walker Ridge Area Map
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Deepwater Gulf of MexicoTechnically Challenging Environment
Much of the prospective Gulf of Mexico deepwater area is covered by layers of massive salt.
© 2012 Chevron U.S.A. Inc. 9
US
Mexico
10000’ (3000 m)10000’ (3000 m)
7,500’ (2300 m)7,500’ (2300 m)
6,000’ (1800 m)6,000’ (1800 m)
Salt Canopy
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Gulf of Mexico Region
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Drilling Vessels
© 2012 Chevron U.S.A. Inc. 11
Jack-up Drilling Rig
© 2012 Chevron U.S.A. Inc. 12
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Semi-Submersible Drilling RigMoored/Anchored
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Semi-Submersible Drilling Rig -Dynamically Positioned
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Drill Ship - Dynamically Positioned
Length - 835 Ft.Breadth - 125 Ft.Max. Drill Depth – 35,000 Ft.Max. Water Depth – 10,000 Ft.
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6
Platform Rig
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Drilling Challenges
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0
5000
Pre 1
950
50-5
4
55-5
9
60-6
4
65-6
9
70-7
4
75-7
9
80-8
4
85-8
9
90-9
4
95-9
9
00-0
4
05-0
9
Futur
e
Water Depth
Water Depth Record (’03) 10,011 ftWater Depth Record (’03) 10,011 ft
Land Rig Platform Rig Jack-up Rig Semi-Submersible Rig Dynamic Positioned Drill Ship
To
da
y
Industry Deep Water Gulf of Mexico Drilling Records
© 2012 Chevron U.S.A. Inc.
10000
15000
20000
25000
30000
35000
40000
Dep
th (
ft)
Offshore Exploration Drilling TDOffshore Exploration Drilling TD
Total Drilled Depth
Drilling Depth Record (’09) 35,955 ftDrilling Depth Record (’09) 35,955 ft
In the middle of last century the industry started exploring below the worlds oceans. Since then new technology has consistently pushed the industry into deeper water depths and total drilled depths.
Records continue to be broken with current 6th
Generation drill ships able to drill in 12,000 ft water depth and to 40,000 ft total depth.
Current Rig Capability 12,000 ftCurrent Rig Capability 12,000 ft
Current Rig Capability 40,000 ftCurrent Rig Capability 40,000 ft
Water Depth Record (’08) 10,139 ftWater Depth Record (’08) 10,139 ft
18
7
0
5000
Pre 1
950
50-54
55-5
9
60-64
65-69
70-7
4
75-79
80-8
4
85-89
90-94
95-9
9
00-04
05-0
9
Futur
e
tio
ns
of
salt
?T
od
ay
Land Rig Platform Rig Jack-up Rig Semi-Submersible Rig Dynamic Positioned Drill Ship
Industry Deep Water Gulf of Mexico Subsalt Drilling
© 2012 Chevron U.S.A. Inc.
10000
15000
20000
25000
30000
35000
40000
De
pth
(ft
)
It wasn’t until the early 1980’s that explorers started looking for oil below salt. With the advancement of seismic imaging and drilling technology the industry has been successfully pushing these limits deeper.
Most of the Wilcox reserves in DW GOM are covered by a salt canopy, in some cases up to 20,000 ft thick.
Salt drilled
Will
we
co
nti
nu
e t
o f
ind
re
serv
es
be
low
th
ick
er
sec
t19
In 7,000’ of water and five miles below the seabed
Technology is Pushing the Envelope on Water Depths
Transocean Deepseas
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Drilling in depths that only yesterday seemed impossible…
Ultra-deep Water Gulf of MexicoDrilling Technical Challenges
Storms and hurricanes
Loop and eddy currents cause vortex induced vibrations and motions to drill strings
Unpredictable high pressure gas charged stringers and faults near surface
Mobile/flow-able/dissolvable 10 000’ thick salt canopy with
Sea Level
8,000’
Allochthonous Sigsbee
Suprasalt Sediment
Gulf of Mexico
Empire State Building ~500 Meters
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10,000 thick salt canopy with unpredictable layers of highly variable trapped sediments
Unpredictable base of salt –rapid pressure differentials
“Thief zones” of significantly lower pressure which cause lost circulation – fluid loss
Ultra-deep reservoir with high temperatures, high pressures and low natural flow-ability
40,000’
16,000’
24,000’
32,000’
Allochthonous Sigsbee Salt Canopy
Cretaceous
Upper Tertiary Sediments
Autochthonous Salt
Basement
Lower Tertiary
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Permitting
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Offshore Event(BP’s Macondo Prospect)
An explosion and fire occurred on the Deepwater Horizon on April 20, 2010 in the US Gulf of Mexico, about 52 miles southeast of Venice, LA. The Horizon was engaged in drilling activity on behalf of BP at Mississippi Canyon Block 252. Eleven people were lost. The Deepwater Horizon sank on April 22, 2010 in nearly 5,000 ft of water.
© 2012 Chevron U.S.A. Inc.
y ,
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Transocean HorizonResponse Fleet
Subsea BOP
LMRP –Lower Marine
Riser Package
Control PODAnnular
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Ram Bodies
60 feet tall620,000 lbs
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Ram BOPs
Blind Shear Ramshears smaller tubulars and then seals wellbore (or seals wellbore with no pipe)
Insert Photo
Casing Shear Ram
© 2012 Chevron U.S.A. Inc.
Pipe Ramseals annulus around various drill pipe sizes
Casing Shear Ramshears large tubulars – does not sealInsert
Photo
Insert Photo
Management Committee May 2010 2525
BOP Emergency Systems
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22 44
1. Emergency Disconnect
2. Deadman
3. Autoshear
4 Remotely Operated
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Primary Methods to Secure the Well:
• Emergency Disconnect System (EDS)
• Autoshear/Deadman Backup
• ROV Tertiary Intervention
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4. Remotely Operated Vehicle (ROV)
New Regulations – Worst Case Discharge (WCD) Casing Design
SW
Gas
Pre-Macondo Post-Macondo
© 2012 Chevron U.S.A. Inc.
Oil G
radien
t
Mu
d
s
27
10
GOM Deepwater Well ComplexityA Bird’s Eye View
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Gulf of Mexico DeepwaterCasing Program:
36” – 7 3/4”
Conventional Deepwater Casing Program:
30” – 7”
WCD Casing Design - Challenges
OS
W
Dynamic Drilling Casing Loads
• Thermal Annular Pressure Build-Up from WCD
• Deep Collapse from WCD
• Thermal induced upward forces on hanger from WCD
• Approach load limits of most rigs due to heavier wall pipe
Extreme Cement Hydraulics
© 2012 Chevron U.S.A. Inc.
Oil G
radien
t
Extreme Cement Hydraulics
• Tight annulus for circulation
• Centralization near impossible
• Approach limit of software
Casing Points
• WCD flow - causing deep collapse and formation broaching
Hole size
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Well Containment
Marine Well Containment Company
10 Members (Chevron, ExxonMobil, Shell, ConocoPhillips, etc…)
Rapid response system available to capture and contain oil in the event of a potential underwater well blowout
The system will be flexible and able to
© 2012 Chevron U.S.A. Inc.
begin mobilization within 24 hours and can be used on a wide range of well designs and equipment, oil and natural gas flow rates and weather conditions.
The interim system (15,000 psig capping stack) is engineered to be used in deepwater depths up to 10,000’ and have initial capacity to contain 60,000 barrels & 120 MMCFG per day with potential for expansion.
Helix Well Containment Group22 Members
Operate in up to 8,000 feet of water
10,000 & 15,000 psig capping stacks
Intervention equipment to cap and contain a well
Capture and process 55,000 BOPD & 95 MMCFPD
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Well Construction Impacts
Extended time required for internal well planning
Was ~21-27 weeks
Now ~27-36 weeks = New Norm
© 2012 Chevron U.S.A. Inc.
Extended time required to receive permit approvals
Was ~14-21 days
Now ~30-45 days or more = New Norm
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Optimistic PermittingTimeline Estimates
1 2 3 4 5 6 7 8 9 10 11 12
Pre-incident Plan Approval/Permit Approval
DevelopedApplication
• Usually CE or EA-FONSI• State consistency review
duration <30 daysMMS EPApproval
APD
App 4.5 Months
Resume Suspended Well
Develop EP Amendment
• Requires EP Amendment• State scrutiny increased:Less certainty of approval timelineMMS & State
Review & APD
© 2012 Chevron U.S.A. Inc.
APDApp 6 Months
New DeepwaterEP/APD
Develop APPPackage
• Requires new NEPA Analysis (EA or similar)
• No site specific EIS• Increased state – 3rd
Party scrutinyMMS Review, State Consistency
APDR&A 10 Months
“Exempt” APD
Apply • Key uncertainties− Submittal requirements− Oil spill requirementsApprove 3 Months
Shallow water APD
Apply • Assumes clear guidance and limited recycle
• Assumes BOEM/BSEE OCsufficient to process
Appr
ove
1.5 Months
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Permitting Challenges
Exploration Plans
Development Operations Coordination Documents● Deepwater Operating Plans
● Conservation Information D t
© 2012 Chevron U.S.A. Inc.
Documents
Development and Production Plans
Application for Permit to Drill
Application for Permit to Modify
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Permitting Challenges
Notices to Lessees
New Rules
New Legislation
Higher Level of Scrutiny
© 2012 Chevron U.S.A. Inc.
Oil Pollution Act
National Environmental Policy Act
Coastal Zone Management Act
Endangered Species Act
Marine Mammal Protection Act
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New Technology Opportunities
© 2012 Chevron U.S.A. Inc. 35
Identify technologies that can be developed and applied which will have a reasonable opportunity to:
reduce the ranges of key uncertainties
enhance safe operations and
Technology Enhancement Objectives
© 2012 Chevron U.S.A. Inc. 36
enhance safe operations and environmental protection
increase rig efficiency
lower non-productive rig time
The goal of implementing new technologies is to ensure the successful execution of offshore well operation
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New Deep Water Drillships
Most advanced drillingcapabilities
Dynamically positioned,with double-hull
Two drilling systemsin a single derrick
© 2012 Chevron U.S.A. Inc. 37
Stronger and more efficienttop drive so wells can bedrilled deeper
Other unique features willtarget drilling wells up to40,000 feet of total depth
Variable deck load of over 20,000 metric tons; capableof drilling in water depths of up to 12,000 feet
Transocean’s Discoverer Clear Leader
Effective Drilling and Completions Optimizing Performance
Drilling and Completions Technology Today
Integrated technology solution
Seismic imaging
Reservoir modeling
© 2012 Chevron U.S.A. Inc. 38
Reservoir modeling
Rock mechanics
Drilling operations
Real-time monitoring
(Live video camera and feed from rig)
Drilling and Completion Technology Enhancement (near term)
• Risers (esp. High Pressure and High Temperature)
• Managed pressure drilling
• Dual gradient drilling
© 2012 Chevron U.S.A. Inc. 39
• Sonic Bit Monitoring
• High strength light weight cements
• Single trip multi-zone frac packs completions
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Dual Gradient Drilling
Dual Gradient Drilling (DGD) is a step-change deepwater drilling technology that should enhance safety and environmental performance, as well as drilling performance.
© 2012 Chevron U.S.A. Inc.
Awareness of these potential benefits led to the technology’s development in the late 1990’s by a consortium of industry operators, drilling contractors and service companies.
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Definitions
Managed Pressure Drilling (MPD) is an adaptive drilling process used to precisely control the annular pressure profile throughout the wellbore. The objectives are to ascertain the downhole pressure environment limits and to manage the annular hydraulic pressure profile accordingly. It is the intention of MPD to avoid continuous influx of formation fluids to the surface. Any influx incidental to the operation will be safely contained using an appropriate process.
D l G di t D illi (DGD) i f th 4 i ti f MPD It i th
© 2012 Chevron U.S.A. Inc.
Dual Gradient Drilling (DGD) is one of the 4 variations of MPD. It is the creation of multiple pressure gradients within select sections of the annulus to manage the annular pressure profile. Methods include use of pumps, fluids of varying densities, or combination of these.
SubSea MudLift Drilling is the method of DGD developed by the SubSea MudLift Drilling Joint Industry Project from 1996 until 2001. The project resulted in Industry’s first successful DGD well. The core technology is the MudLift Pump (MLP). Now made by GE Oil and Gas, this pump has been renamed the MaxLift 1800 Pump (still MLP).
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Dual Gradient
Heavier Mud w/ Seawater
Density Above Mudline
SingleMud
Conventional
Dual Gradient Drilling - Comparison
With DGD, we Literally replace the mud in the drilling riser with a seawater-density fluid and use a denser mud below the mudline.
© 2012 Chevron U.S.A. Inc.
Mudline
Same Bottom Hole
Pressure
Mud Weight
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DGD - Production Benefits
36 3626 20
22
SWF Zone
Fewer strings of casing can lead to larger casing at TD. Higher rate, designer completions, for example, horizontal or multi-lateral wells, may then become
© 2012 Chevron U.S.A. Inc. 43
13-3/8
(Conventional)5-1/2" Tubing
(SubSea MudLift)
9-5/8
7-5/8
7" Tubing
5-1/2
11-3/4
9-5/8
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13-3/8
(Dual Gradient Drilling)
, ypossible.
This can lead to higher rate wells and higher recovery factors in deepwater reservoirs.
Conventional (Single Gradient) vs. Dual-Gradient Drilling
• Formation Pressures (FP) and Formation Strengths (FS) are functions of the weight of the water and sediments above them.
• In deepwater, the lower density seawater can dominate FP and FS.
Surface
© 2012 Chevron U.S.A. Inc. 44
• Conventional drilling uses a single density fluid to manage FP and FS.
• Dual Gradient Drilling uses two fluids: seawater density above the seabed, and a higher density fluid below the seabed.
• This is more in harmony with natural pressure profiles.
SubSea MudLift Drilling
A sea-water driven positive displacement pump is located above the BOP/LMRP. It withdraws the mud from the well and pumps it back to the surface through a line attached to the drilling
Choke Line
Kill Line
Mud Return Line
Seawater Power Line
Drill Pipe
Drilling Riser Cross-Section
Subsea Rotating
Pacific Santa Ana
© 2012 Chevron U.S.A. Inc.
attached to the drilling riser.
The riser is filled with a seawater-density fluid.
A Subsea Rotating Device (SRD) sits above the MaxLift Pump which can be used to rapidly change the pressure profile in the well.
Rotating Device (SRD)
Solids Processing Unit
(SPU)
MaxLift Pump (MLP)
Drill String Valve (DSV)
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The Heart of the System: MaxLift 1800 Pump (MLP) Positive Displacement Pump installed above
BOP
Pumps drilling mud from sea floor up mud return line to rig for processing
Driven hydraulically by conventional mud pumps converted for seawater installed on the rig and available for maintenance
Powered by seawater which is returned to
TriplexPump
© 2012 Chevron U.S.A. Inc.
(Specifications)80 gallon chambers1800 gpm max rate10,000’ WD ratingUp to 18.5 ppg mudSize - 18’ x 18’ x 30’Weight - 450,000 lbsMax Cutting Size - 1.5 in
ysea
Two interchangeable mirror image Triplex modules
Pump can be broken into ~ 50 MT lifts for initial lift onto rig
Modules
HPU’s
Valve Manifold
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Dual Gradient Advantages
Dual Gradient Drilling is a step-change deepwater drilling technology that has been under development for over 15 years.
DGD has the ability to enhance drilling safety, efficiency and environmental performance.
© 2012 Chevron U.S.A. Inc.
DGD can lead to improved deepwater production and reservoir recovery.
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Well Construction Sonic Bit Monitoring (Accusound & Inficomm)
Advance preparation for operational changes that mitigate non-productive time (NPT) encountered above, within and below the salt canopy
Capture and transmit high frequency acoustic signatures from the drill bit to the surface in real-time
© 2012 Chevron U.S.A. Inc. 48
g
Sonic signature measures bit/bearing wear, actual weight on bit, and formation changes developed by Accusound
Transmission to surface using a new electromagnetic pulse (EMP) technology commercially developed by Inficomm
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Sonic Bit Monitoring
Gulf of Mexico
Sigsbee Salt
Post-Salt Sediment
High Pressure Gas Stringer
© 2012 Chevron U.S.A. Inc. 49
Sigsbee Salt Canopy
Ultra Deep Reservoir
Pre-Salt Sediment
Trapped Sediments
Thief Zone (loss circulation)
Unpredictable Top and Base
Non-Productive Time (NPT)
Sonic Bit Monitoring
Gulf of Mexico
Sigsbee Salt
Post-Salt Sediment
High Pressure Gas Stringer
Accusound
Inficomm
© 2012 Chevron U.S.A. Inc. 50
Sigsbee Salt Canopy
Ultra Deep Reservoir
Pre-Salt Sediment
Trapped Sediments
Thief Zone (loss circulation)
Unpredictable Top and Base
Well Construction High Strength, Light Weight Cements
Geo-polymer and graphite reinforced light weight cements with very high strengths and very low permeability
New cements could:
© 2012 Chevron U.S.A. Inc. 51
New cements could:
• minimize the effects of lost circulation zones
• drilling mud contamination
• problems associated with placement techniques
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High Strength, Light Weight Cements
© 2012 Chevron U.S.A. Inc. 52
Conventional Cement Job
High Strength, Light Weight Cements
Restricted Clearances
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Drilling Mud Contamination
Conventional Cement Job
Loss Circulation
High Strength, Light Weight Cements
Designer Cements
© 2012 Chevron U.S.A. Inc. 54
g
•Geo-polymer
•Graphite
•Other non-Portland
Polymerizes with temperature or time
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The Future
© 2012 Chevron U.S.A. Inc. 55
Advances in technology have allowed industry to drill and produce offshore resources safely.
Summary
© 2012 Chevron U.S.A. Inc. 56
Many technical challenges remain to be solved, but the industry is focused on finding solutions.
“The Offshore Drilling New Normal”
Rebuilding government confidence
Assurance future incidents will be minimized
© 2012 Chevron U.S.A. Inc.
Greater worker and environmental safety
Enhanced well containment and spill response
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