Lecture+#1 Well+Completion+Objectives+and+Design

8/13/2019 Lecture+#1 Well+Completion+Objectives+and+Design

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WELL COMPLETIONOBJECTIVES AND DESIGN

Lecture #1



Learning Objectives

• Define completion objectives and constraints

• Identify key data requirements

• Define functional capabilities of well

• Create completion sketch and identify key components

2



Agenda

• Completion objectives

• Discussion of key design decisions

• Conceptual well design

Bottomhole completionSelection of production/injection conduit

Well functionality definition

Preliminary location of components

Well performance consideration

• Generic completion review

• Interface between Drilling and Completion

• Review example completions

3



Completion Objectives

• Effective reservoir exploitation

Control fluid entry/exit, rates & recovery

Manage pressure depletion

Control zonal contributions• Minimize total cost over the life of the well

• Ensure safe operation/well control

• Incorporate flexibility to adapt to changing conditions

• Facilitate intended workover strategy

• Document strategies/decisions/experiences

4



Economic drivers for Design

• Optimal combination of

Initial capital investment

Operating Costs

Intervention Costs Abandonment Costs

• Life of well/field?

Can be a significant driver

Normally intended as 12-30 years in the firstinstance, but it varies from <1 to >50 years!

5



Constraints on Design/Completion

• Data – usually incomplete and of variable quality

• Logistics

Location/environment/topology – access issues

• ProcurementDelivery/supply dates

Inventory – availability & stock control

Bulk discounts

Preferred vendor?

• Availability of service centre support

• Contractual obligations with vendor

6



The Design Process evolves over the life

of well

7

Establish Design Criteria

Preparation of Production Zone

The mechanical Completion Design and

installation of completion String

Production Initiation and Remedial

Measures

Monitoring Well and Completion

Performance

Update

Design

Criteria

Workover

INTEGRATION OF THE WELL COMPLETION PHASES



Phased development of completion strategy

8

Budget Costing

Internal AFE approval

Partner Approvals

Regulatory approvals

Conceptual

Design

Design Phase Objectives/use Key outputs Constraints

Lift decisions

Flowrates / nominal tubing

size(s)

Bottomhole completion

Tubing/casing/annular flow

Identify operational ricks

Limited well data

Understanding of

heterogeneity?

Resource constraints

Final

Design

Rigorous and optimised

design

Optimised - technically

and economically

Offload and cleanup

proceduresWell integrity assurance

Safety case(s)

Running procedures

Test and verification

Contingencies

Equipment procurement –

specifications & sourcing

Running procedures and

programme

Fluids and additivesContingencies

Documentation and testing

requirements

Data limitations –

quantity and reliability

Future forecasts

Vendor performance

Alternative

investments?

Oil price uncertainties?

Equipment longevity

and reliability

Continuous

validation,

enhancement and

modification



Conceptual design – influential issues and decisions

9

Context of well

Conceptual Design Considerations

Specification of Design

Geographical

location

Land or

offshore based

Fluid type &

contaminants

Artificial lift

requirements

Well trajectory

or orientation

No. / thickness

of zones

Geo-political risks,

accesses, services

Physical access, subsea

or platform

GOR/LGR

H2S/CO2 content

Timing

Gas/power availability

Reliability

Flow capacity/stability

Reservoir management

Intervention

Relative depletion

Crossflow

Complexity/cost

Bottomhole

completion

Production

conduit

Preliminary

flow capacity

Completion

functionality

Barrier and

Integrity

requirements

Openhole

Uncemented liner

Cemented Casing

Casing flow, tubing

and/ or annular flow

IPR & TPR

Initial tubing size

recommendation

Retrievability,Monitoring

Circulation

Well closure

capability

Backups

Number of barriers



Open Hole – “Barefoot completion”

• Advantages

Low cost

Faster getting well online

Easily deepened retrospectively

PI? – maximum r w

• DisadvantagesWellbore stability?

Reservoir management?

Poor isolation of water and gas

Minimal production/injectionselectivity

• Applications

Low cost area

High well count

Naturally Fractured reservoirs

Geometrically complex wells

10



Uncemented Liner/Screen completion

• Advantages

Lower cost

Supports borehole stability

Sand exclusion – either with astandalone screen or gravel pack

• Disadvantages

Non-selective hydraulic access toreservoir

Remedial options

Reservoir management?

Limited due to complications createdby annulus behind screen

• Applications

Unstable wellbores

Sand Production?

Can use swell packers or ESPs toimprove selectivity/operability ofcompletion

11



Production Conduit Options

13



Casing Flow (Tubingless / no tubing)

• Advantages

Low cost

Shorter completion – accelerated production

Large wellbore – minimum friction

• Disadvantages

Casing integrity?

Corrosion

Erosion

Pressures

Backup or retention?

Slippage leading to slugging/loading – stableproduction over the life of the well?

14



Casing and tubing flow – no annular isolation

• Advantages

Lower cost

Large wellbore – minimum friction

3 optional flow cross sectional areas – improved

stability? – greater ability to handle slippage• Disadvantages

Casing integrity?

Corrosion

Erosion

Pressures

Backup or retention?

Limitations on flow stability/flexibility

Annulus heading when annulus not flowing

15



Tubing Flow with Annular Isolation

• Advantages

Annulus/casing protected – enhanced wellbore

integrity

Hydraulic backup – containmentImproved well and flow control

• Disadvantages

Higher cost

Limitations on wellbore cross-sectionRequires circulation capability

16

17



Well Control – Barrier Policy

• What are barriers?

Capabilities to hydraulically isolate reservoir from

atmosphere/surface

• OptionsHydraulic – column of kill weigh fluid

Mechanical – valves, plugs etc

• Recommendation?

Minimum of two specified for most operationsPrefer minimum of 3 for most situations

17

18



Subsurface Barriers

• Surface Barrier – Pressure and flowContainment – BOPStack or Xmass Tree

• EmergencySubsurface Closure

– SSSV

• Annular isolation –

Packer

• Plug tubing andprotect the reservoir

– Deep-set nipple

18

19



Well Design – Well Functionality/Operability

• Well functionality requirements

Well isolation – barriers?

Well control/offload

Prefer to circulate rather than bullhead

Circulate as deep as possible in order to

Minimize kill fluid density Minimize hydrocarbon inventory in well

Monitoring

How and what is to be monitored?

Value of information?

Interventions?

Strategy/access/costs

Maximize reliability?

Duplicate critical devices?

19



21



IPR for Pwf above the Bubble Point

21

PI = Straight line IPR

Productivity Index (PI also

given as J)

Pwf = Pr – Q/PI

or Q = PI * (Pr -Pwf )

or PI = Q / (Pr – Pwf )

PI is given in units of pbd/psi

22



Pwf below the Pbubble point : Vogel IPR relationship (1968)

22

Vogel developed this

IPR relationship by

best fit fromnumerous reservoir

simulation runs

Vogel has a long

history of use with

good success

23



Gas Well inflow: Steady/Semi Steady State

23

Q = C (Pr

2

-Pwf

2

)n

Bureau of Mines IPR, a.k.a., Back Pressure Equation

(Rawlings & Schellardt 1936)

Exponent ranges from 0.5 to 1.0; should be 0.92 – 0.95

Exponent derived from multiple rates by plotting (Pr 2 - Pwf

2)Versus rate and finding n, the inverse of the slope

Then, “C” found by substituting one test point into the formula

24



Non-Linear IPR (Gas)

• In high rate wells turbulence can occur in the near

wellbore

• Pres2 – Pwf

2 = aq + bq2

Where

- aq = pressure drop due to laminar (Darcy) flow

- bq2 = pressure drop due to turbulent (non-Darcy)

flow

The constants a and b can be derived from multi-rate welltests or alternatively estimated from known reservoir and

gas properties.

24

25



Inflow Performance Relation - IPR

• Defines reservoir deliverability• IPR = Q vs Pwf for Oil well above PBPT

• Straight Line IPRRate ∞ Pressure Draw Down in Reservoir

Constant of Proportionality = Productivity Index, J

J=PI=Q/ΔP

25

26



Radial inflow and pressure drop

Radial convergence results in

acceleration and rapidly

increasing pressure drop as you

approach the sandface

26

27



Components of Tubing pressure Loss

• dPTBG=dPHHD + dPFRICT + dPKE

dPTBG=Total tubing pressure loss between surface and

bottom of tubingdPHHD=Hydrostatic head pressure loss in tubing (“weight

of vertical fluid column”)

dPFRICT=Frictional pressure drop in tubing

(“interaction/drag with tubing wall”) dPKE=Kinetic energy loss (“acceleration and

deceleration”)

27



30



Production Optimization

• Variables affecting Optimum Production Rate

Tubing Head Pressure

Water Cut

GOR

Inflow performance

Tubing Size

Wellhead / choke performance

• IPR-TPR curves assesses sensitivity to the abovevariables to predict optimum production rated under

various conditions

30



34



Effect of changing water cut

35



Generalized Tubing Completion

W.E.G.

Well Head

Xmass Tree

S.S.S.V.

Nipple

Side Pocket

Mandrel

Sliding SideDoor

Seal

Assembly

Packer

Nipple

Perforated

Joint

Upper

Wellbore

Completion

Lower

WellboreCompletion

Flow control and Isolation

Tubing & Casing, Suspension, NippleUp, Xmass Tree, Annulus Access

Safety Isolation

Circulation or Fluid Injection

Circulation

Accommodate Tubing Movement

Annular Isolation

Tubing Isolation

Flow alternative Entry

Landing gauges

Wireline Re-entry

36



Function of the Wellhead

• Suspend casing strings and production tubing as the

well is sequentially constructed

• Allow “nipple up” (physical connection) of upper flow

control / barrier system

BOP stack while drilling and during workovers

Xmass tree for production / injection phases

• Allow hydraulic access to the annulus between the

tubing and casings

37



Basic Spooled Wellhead and Tree

• Xmass Tree

• Adaptor Spool

• Wellhead

38



Subsurface Safety Systems

• Function?

Emergency closure of well if primary barrier fails

• Functional valves types

Tubing safety valves Annular safety valves

Injection safety valves

• Operability

Remotely controlledDirectly controlled

• Retrievability

Tubing, CT or WL retrievable

39



Tubing Subsurface Safety Valves

• Remotely controlled

Failsafe

Hydraulically

operatedTR-tubingretrievable

WL-wireline

retrievableStandard methodsto test operability

• Directly Controlled

Subsurfacecontrolled

Can be set at anydepth

Easily replaced

Design operating

conditions must beroutinely reviewed

Testing?

40



Remotely Controlled SSSV

Surface Controlled

Sub Surface Safety Valve

flapper is held open by hydraulic pressure

valve fails to closed position by spring

a “tubing retrievable” surface controlled

sub surface safety valve (SCSSSV) is run in

well on production tubing

41



Circulation Capability / Devices

• Purpose?

Tubular

displacement

Kill the well

Offload the well

Fluid injection

Gas liftChemical injection

• Options:

Sliding side Door

SSD

Side Pocket MandrelSPM

Ported Nipple

Tubing Punch

42



Type XO Sliding Side Door

• Upper nipple profile

• Inner sleeve slots

Upper

Lower

• Outer sleeve ports

• Packing between

inner and outersleeves

• Lower seal bore

43



Nipple –Lock Mandrel Systems

• System allows:

Installation and retrieval of devices for:

Flow control

Flow regulation Flow monitoring

• Nipple provides location to :

Suspend flow control device in well – profile

Seal device in tubing – seal bore• Lock Mandrel provides:

Ability to suspend flow control in nipple profile

Seals on mandrel engage nipple seal bore



45



Flow Coupling• Flow Coupling assists in

tolerating internal erosioncreated by converging ordiverging flow

• Flow coupling is a short piece

of pipe which has a wallthickness greater than thetubing string. Flow couplingsare used to delay erosionalfailure at points inside acompletion string, where

turbulent flow is expected tooccur

• Downstream location – moresevere erosion location

46



Reasons for using a Packer

• It protects the casing from reservoir pressure andproduced fluid

• Isolates casing leaks or squeezed off perforations

• Isolate between multiple producing horizons – preventcrossflow

• Eliminate or reduce pressure surging or annulus heading

• Hold kill fluid in the annulus

• Preferred for certain artificial lift methods –gas lift



48



Retrievable Packer

• Hydraulic Hold-down

• Packer seals

• Lower slip system

• Slip release system

• Release section

49



Tubing to Packer connection Systems

• Function?

Accommodates tubing stress

Allows disconnection/retrieval of the upper completion

from and without pulling the packer

• Options?

On-off tools

Anchor/latchDynamic seal systems



54



The Drilling and Completion Interface

• Well trajectory and configuration

•Critical role of casing/liner cementation

• Avoidance of permanent damage

• Critical opportunities for optimisation/enhancing well“value”

55



Well Configuration

• Influential factors

Costs

Complexity

Standardization of equipmentInventories

Bulk purchasing

Geological uncertainties – contingency

requirements• Impacts

Upper wellbore clearances

Tubular sizes versus pressure loss



57



Casing nomenclature

58



Drill-in fluids

• Objectives is low damage drilling of the pay zone

• Wide choice of fluid options

Low solids OBM

Sized saltSized carbonate pills

HEC pills

Water foams

Base oils- all fresh mixed to drill zone

• Selection is mostly by operator preference and

experience

59



Fluid Loss Control Options

• Base get fluid

Removal by breaker?

• Particulate additives – borehole wall filtercake

Calcium carbonate

Ground salt

Oil soluble particles

Resins

Wax beadsetc

60



Filter Cake Removal

• Controlling factors

Thickness and permeability of cake – depend on

time and overbalance pressure

Ability to apply drawdown? –

vertical/horizontal/multilateral

Avoid flowback through screen if possible

Must be specially designed to facilitate cleanup

•Lift pressures

Dependent on fluid

Contamination with cuttings

Impact of long lateral?



62



Casing Nomenclature and T.O.C.

• TOC?Normally preferred as

high as possible

Prefer to cement backabove previous casing

shoeConstrained by:

Depth

Temperature

Pressure

TimeFormation frac

pressures andpermeability

63



Objectives of Primary Cementing

• Complete Cement Sheath without mud or gas

channels

• Cement bonded to Formations

• Cement bonded to Casing



65



Critical Features of liner Cement Job

• Small Clearances: usually <<3 in.

• Decentralized and often inclined

• Smaller Length: 100-500 ft overlap with previous shoe

• Batch Mix cement to homogenize

• Potential leak into annulus via liner lap: impact on

barrier policy?

• Debris potential in top of liner

66



Liner Cementation

• DP running string

• Single plug released

by dart/inner plug

• Critical to long term

integrity

67



Tubing Completion Configurations

• Casing completions

• Conventional packerless tubing

• Tubing - packer completions

• Monobore

• Tubingless

68



Basic Natural Flow Completion

• Tubing – carries fluid to surface

• Subsurface safety valves – shut in wellin an emergency

• Side Pocket Mandrels – Circulationbetween annulus and tubing (gas or

chemicals)

• Circulation Device (SSD) – communication between tubing andannulus

• Packers – isolate production zones

• Nipples – installation of flow controlcapabilities

• Flow Couplings – protect tubing frominternal erosion



70



Big Bore Producer or Injector

• Big bore

producer or

injector

• Permanent

packer in liner

• Two section

completion

Liner

Casing

Tubing

WL Operated SSD

Extralong Tubing Seal assembly

Permanent Packer Wireline Set

Millout Extension

TailpipeNipple

Perforated flow TubeLanding Nipple

SSSV

71



Monobore Completion

• Monobore

• Facilitates

concentric access

• Big bore – low

pressure los

• Cannot circulatebelow liner hanger

without tubing

(CT)Liner

SSSV

Tubing

SPM (Side Pocket mandrel)

Polished Bore Receptacle

Liner Packer & Hangar Assay

Nipple

Casing

72



“Tubingless” Completion

• Simple, low

cost

completion

• Integrity?

• Intervention

options?

Casing

Wireline Isolation Nipple

Direct Controlled SSSV

Borehole Wall


Lower Zone Perf


Cement

73



Summary

• Start with “basis of Design” statement

• Keep it simple and fit for purpose

• Consider

• Uncertainties

• Costs

• Operating and workover costs

• Longevity requirements

• Learn from the design process - documentation

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