Equipment, Systems and Processes

Schlumberger Public

Equipment, Systems and Processes

Mark E. TeelClient-Relations ManagerSRC Schlumberger Rosharon Center

2 Initials

3 Initials5/15/2012

The Life of Oil and Gas Wells and ReservoirsSeismic

ExplorationExploration

DrillingDevelopment

DrillingFormation Evaluation

Well Testing

Casing and Cementing

Complete StimulateWorkover Interventions

Monitor and Manage

Plug and Abandon

4 Initials5/15/2012

Oil and Gas Drilling Rigs

5 CAP

How deep is deep?

500 m (1640 ft)

301 m (988 ft)

6 Initials5/15/2012

7 Initials5/15/2012

8 Initials5/15/2012

9 Initials5/15/2012

10 CAP

Identifying Needs and Challenges

•So, How deep are we going?

Deeper than ever!

Empire State

Building

11 Initials5/15/2012

12 CAP

How deep are we going below the seafloor?


14 CAP

How deep are we going below the seafloor?


Subsea – Intervention and Safety Systems– Offshore fields are increasingly

developed “subsea” with wellheads on the seafloor.

– Anchored rigs or dynamically positioned drillships are used for drilling, testing and well completion activities.

– Safe well access, emergency shut-in and disconnects are a huge challenge.

– SRC develops technology to safely shut-in, disconnect from and reconnect to a subsea wellhead.


Wellbore Architecture

Well Completions

18, Completion Basics15-May-12

Packers• ANCHOR production tubing inside cemented casing

• SEAL to isolate the tubing-casing annulus and act as a pressure barrier between formation, or reservoir pressure, and upper wellbore annulus or between multiple zones

• PROTECT upper steel casing from erosion, corrosion:

H2O, H2S, CO2

Multilateral Wells and Wellbore Junctions

Strength Solids ExclusionHydraulic Pressure IsolationLateral access

Define technique, coiled tubing, wireline, rigSize and type of tools for intervention


What is a well completion?

• Equipment installed and procedures performed in oil or gas wellbores to facilitate flowing from—production—or pumping into—injection—subsurface formations after drilling, running steel casing and cementing the primary casing or liner in place.

• Production tubing and other equipment components of a well completion help transport hydrocarbons to surface in an efficient cost-effective, controlled, measured, and safe manner.

Well Completions• Conveyance, or transport, into and out of …• Data acquisition …• Flow control and flow management …• Communication and data transmission …• SAFETY !

Completion installations can be:

temporary for well testing or

permanent for long-term production

— “life of a well, field, or reservoir”


Oilwell Perforating Perforate

• Wireline conveyed• TCP—Tubing Conveyed perforating

Explosive Shaped-Charges

TCP Tubing-Conveyed Perforating



Shaped Charge Animation (to 30 microseconds)

Shaped Charge Animation (to 140 microseconds)



Cased, Cemented and Perforated

• The most common type of well completion

• Selective production, stimulation and zonal isolation

• Pressure control and safety

• Multiple individual zones completed in a single wellbore


PERF Lab Testing CapabilitiesPV-93 Test (2008) PV-94 Test#001 (2009)


Well Classifications• Wellbore and reservoir interaction

– Steel cased, cemented and perforated

– Openhole, or barefoot

– Standalone screens, gravel and frac packs

– Vertical, high-angle, and horizontal

• Flowing method– Natural flow

– Artificial lift

• Number of completed zones– Single

– Multiple

Completions tubulars and equipment-plumbing




Wellbore Architecture

Well Completions


Packers• ANCHOR production tubing inside cemented casing

• SEAL to isolate the tubing-casing annulus and act as a pressure barrier between formation, or reservoir pressure, and the upper wellbore annulus or between multiple zones

• PROTECT upper steel casing from erosion, corrosion:

H2O, H2S, CO2

• Available in different types:

– Permanent

– Retrievable

Single, dual or triple string, multi-ported, sealbore

X-Series Retrievable Production Packers

XHP

XMP


Openhole Sandface Completions

• Advantages

– Maximizes area open to flow

– Decreases pressure drop, or pressure drawdown

– Minimizes formation damage from cementing, perforating and completion fluids and operations

• Disadvantages

– Lack of pressure containment and selective control

– Possible borehole instability and risk of hole collapse

Mechanical Screens and ICD Inflow Control Devices


Swellable Openhole Packers



Sand-Control Completions and Pumping

Well Completions


Zones to be completed

• When more than one zone will be producing at the same time

• When zones are prepared to produce at different periods of time without need of major intervention (workover)

• May need: dual, triple strings, sliding sleeves, permanent control valves

• Remedial workovers difficult when more than one tubing is used


Sequential Production with a Packer and Single Tubing String

Zone 2: 1000 psi

Zone 1: 1500 psi


Sequential Production with a Packer and Single Tubing String

Zone 2: 1000 psi

Zone 1: 1500 psi


Commingled Production with a Packer and Single Tubing String

Zone 2: 1000 psi

Zone 1: 1500 psi


Packers and Sliding Sleeves or Valves and Single Tubing String

Zone 2: 1000 psi

Zone 1: 1500 psi


Sliding Sleeves

• Provide communication tubing-annulus

• Used to circulate wells

• To produce selectively different zones

• Reduced internal diameters


Flow Management: Two Production Zones

– Dual producing zones, formations or reservoirs

– Drilling, well-construction and well-completions savings

Flow Management: Accelerated Production and Optimal Reserve Recovery

0.7

0.6

0.5

0.4

0.3

0.2

0.1

100 200 300 400 500 600 700

Days

Intelligent Completions – benefits and history

• Cumulative Oil Production and Flow Strategy Comparison

Sequential

Uncontrolled Commingled

Controlled Commingled

Oseberg

B-38 is the 2nd well drilled exclusively in the Ness formation

Ness target contribution ≈70,000 B/D–350,000 B/D (field)

7 in. QUANTUM isolation packers

Completion string

Subsurface Safety Valve

Flow control valve1 per zone

9-5/8 in. QUANTUM production packer

Flow Management –Permanent Downhole Flow-Control Valves

Schlumberger C

onfidential

-2700

-2600

-2500

Depthm TVD MSL

M iddle Tarbert coal

U N1

30/9-B-39 T3*

T3T4

-2700

-2600

4000 5000 6000

4000 5000 6000

@ 2701.5 m TVD M SL O W C UN1/LN35 G S

0 0.2 0.4 0.6 0.8 1.0

Kilom eter

LN35

T1T2

U N 2 coal

Top LN 35 coa l

LN1 coal

DUNLIN GP.

LN2

LN35

G AMM A M AIN

G AMM A SOU TH

In tra H eather sand, partly cem ented

T5

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B -38 B , plan

B38AT2, p lan*

B -38 AT2, boret*

Ran./E tive Fm

B -38 A, boret *

O seberg Fm

O W C G M U N1

O W C G M LN35

N ess Fm .

SHETLAND GP.

Draupne Fm .

Heather Fm .

Tarbert Fm .

-2500

TD B 38 A

T2

TD B 38

A

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Legend: *the wells are projected onto the cross-section TARGETS: m TVDM SL m TVDR KB m M D

T1 2610.0 2668.0 5616,5 T2 2617.5 2675.5 5836,8 T3 2663.8 2721.8 6180,0 T4 2670.4 2728.4 6559,7 T5 2655.9 2713.9 6781,8

Vertical d isp lacem ent from OFC

Zone 1Zone 1

Zone 3Zone 3

Zone 2Zone 2

Production was declining Require to produce

untapped reserves Not “continuous”

reservoirs Required long reach and

highly deviated Required to control gas

coning and water breakthrough.

Phase 1 – Prove the ValueCase study : Multiple zones selective wells - Norway (2000 – 2001)

SPE 71677 & 107117

Schlumberger C

onfidential

► Long reach & highly deviated Monobore wells■ 9-5/8” Casing with 7” liner though reservoir

► 9-5/8” Production and 7” Isolation packers► TRFC-HN remotely operated flow control valves

■ Hydraulic control lines to surface■ Intervention capability

► Pressure & temperature monitoring

9 5/8” Casing

3 ½” Flow Control Valve

3 ½” Flow Control Valves7” Liner

Production packer

Phase 1 – Prove the ValueCase study : Multiple zones selective wells - Norway (2000 – 2001)

SPE 71677 & 107117



Expansion joints

• Allow thermal expansion and contraction of tubing string between fixed points

• Allows tubing disconnection and reconnection of upper completion with sealing

• Composed of a assembly with elastomer seal and wiper rings, depending on downhole conditions



Pump-Out Plugs• Base component of production tubing

string, many times for hydraulically set packers

• Guide re-entry of intervention tools into tubing once seat and ball are expended

• Allow for easy liner top entry in high-angle wells



Reentry Guide

• Component in the production tubing

• Guide reentry of intervention tools back into tubing

• Allow for easy liner top entry in high-angle wells



Landing Profile Nipples and Locks

• Allow landing and locking of multiple

accessories in the tubing string for:

– Flow control

– Plugging devices

– Many different profiles

– Basic types: No-go and selective


Completion Accessories-Chemical Injection

64 CAP

Schlumberger PrivateDCIN - Features

• New generation of chemical injection mandrels• One piece body (no welds)• Limited leak paths• Internal check system• Proven supplier of check valves• Checks can be tested to full working pressure installed in to the

mandrel• Optional profile



Control-Line Clamps and Protectors

•Purpose

– Protect control line

– Support control line

•Features

– Location on tubing couplings

– Lightly grip control line

– Multiple line capability

– Upset for Large O.D. assemblies.

– Various types and sizes of lines.

Flow Control: FIV Formation Isolation Valve

● Bi-directional ball valve to provide a Safety Barrier during the well completion program

● Rig time savings via remote actuation● Improve and enhance reliability and

operability

Next Generation FIV

n-Trigger

New Mechanical Section

New Ball Section

Contingency Opening Tool

API Debris Testing

Actuation Module

Mechanical / Ball Module

n-Trigger

S-Trigger

MFIV-IIMechanical Ball

Shifting tool interfaceHolds valve open/close

Barrier- Rotates

open/close Same mechanical and ball sections as FIVSame mechanical and ball sections as FIV--IIII Same shifting tools as FIVSame shifting tools as FIV--IIII Extensions 3ft, 6ft or 9ft, same as for FIVExtensions 3ft, 6ft or 9ft, same as for FIV--IIII

FIV-II

Remote (interventionless) opening feature

3 major sections to an isolation valve:

Mechanical BallTripSaver

Shifting tool interface

Holds valve open/close

Barrier- Rotates

open/close

Flow Control –Surface-Controlled Subsurface Safety Valves

Primary purpose

– Emergency well-control device

– Prevent: (Piper Alpha)

personnel, environmental,

equipment, and reserve losses

Secondary purpose

– Downhole flow control

allow for wellhead maintenance

serve as a secondary barrier

Safety Valve ConstructionSafety Valve Construction

Hydraulic PistonHydraulic Piston Power SpringPower Spring FlapperFlapper

Power SourcePower Source[Opening Force][Opening Force]

Closure MechanismClosure MechanismPower SourcePower Source[Closing Force][Closing Force]

Surface Controlled Subsurface Safety Valve (SCSSV)Surface Controlled Subsurface Safety Valve (SCSSV)

Standard SpringStandard Spring‐‐Type DesignType Design

FlowtubeFlowtubeFlapper ClosureFlapper Closure

Power SpringPower Spring

Hydraulic PistonHydraulic PistonPiston BorePiston Bore

Production Production Tubing PressureTubing Pressure

Flow Tube and Flapper Closure MechanismsFlow Tube and Flapper Closure Mechanisms


Surface-Controlled Subsurface Safety Valves

• SCSSV Applications:

– Government/country regulations

– Offshore and onshore wells

– Environmentally sensitive wells

– H2S /C02 containing wells


Intelligent Completions

Reservoir Monitoring & Control….Real time production optimization

Monitor and Manage


Reservoir Energy—Pressure

Water drive Gas drive Solution-gas drive


Artificial Lift Technologies

Electrical submersible pumpsGas lift valves


Natural Flow or Artificial Lift

• Natural flow: Enough reservoir pressure to bring fluids to surface

• Artificial lift: Add energy to the fluid

– Electrically driven, mechanical positive-displacement beam pumps

– ESP electric submersible pumps

– Gas lift (re-injecting produced gas)

Schlumberger Public


Side-Pocket Mandrels• Annulus-tubing communication

device in an artificial-lift completion

• A valve is located to allow gas to enter the tubing to lift the oil

• More than one are installed in a well

INJECTION GAS

PRODUCED FLUID

PRESSURE (PSI)

DEP

TH (F

T TV

D)

1000

2000

3000

4000

5000

6000

7000

01000 20000

OPERATING GAS LIFTVALVE

CASING PRESSURE WHENWELL IS BEING GAS LIFTED

FBHP

SIB

HP

FLOW

ING TUBING

PRESSUREG

RADIENT

CONSTANT FLOW GAS LIFT WELL

Gas lift valves

High Efficiency Pump

ImpellerDiffuser

Downhole ESP Electrical Submersible Pump

Motor

Intake



Completion Components

• Subsurface safety valves• Packers• Sliding sleeves • Expansion joints• Chemical-injection valves• Flow-control valves• Permanent monitoring gauges• Side-pocket mandrels or ESP• Landing profile nipples• Wireline reentry guide• Formation Isolation Valve

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Stimulation, Pumping Services

Stimulate

Acidizing

Fracturing


Assisting Production From Pressure-Depleted Reservoirs

Water floodingFire Flood –In situ combustion

Workover Interventions


P&A Plug and AbandonAbandonment


Four Life Stages of Reservoir Development

Stage 2Delineation

Determine the reservoir extent

Determine reservoir properties

Determine reservoir model

Further reduce risk

Stage 1Exploration

Starting to reduce the risk

Choose the right point

Locate potential reservoir

Stage 3Development

Achieving full production

Refine reservoir model

Reservoir monitoring

Continue reducing the risk

Stage 4Late Life

Water production

Depleted pressure

Intervention

Stimulation

Flow assistance


Focus on Technology and the Reservoir Life Cycle

Exploration Appraisal Development Production

Reservoir Optimization

Traditional Development

Cash

Flo

w

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0_ Time

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Equipment, Systems and Processes