Technology Oil Potential with DHOWS

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Conventional Technology Oil

Downhole Oil/Water Separation

Background Basic Operation Development Project Initial Results Economics What Has Already Been Done What Can Be Done What Might Be Done in Future

Background

Why was it needed? What was the concept? When did it happen? Where could it be used? How was it turned into action? Who got it started?

Water and Oil Production in Western Canada

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500

1000

1500

2000

2500

Ann

ual P

rodu

ctio

n -

Mill

ions

of b

bls

Water Production

Oil Production

Downhole Oil/Water Separation (DHOWS)

Problem - Wells being shut-in• Still producing oil• Producing too much water• Most wells shut-in @ WOR<20

Solution - In Well Separation Downhole• Mechanical solution more reliable than shut-offs• Evaluated membranes, gravity separation, selective

filtration, and hydrocyclones• Re-Inject water into producing formation

Basic Downhole Separation

New Paradigm – 1991“Commercial” - 1996

Oil to Surfac

e

Separator & Pump(s)

Water to Injection

C-FER/NPEL

DHOWS Applications

Onshore Mature Operations• Water handing one of the highest costs• A large number of mature fields with high WOR• Small volumes and small wellbores

Offshore• Reduce volumes to platforms• Reduce produced water dumping to ocean• Avoid adding to existing platforms

Middle East• Even a small amount of water a problem

Project Development Concept

Look at all options for Feasibility Work with appropriate vendors to develop

prototypes Move directly to field testing at selected sites Expand testing to develop “commercial” products Follow-up to expand applications

Downhole Oil/Water Separation (DHOWS) New Paradigm Engineering Ltd.

• Project Initiator/Inventor - Bruce Peachey• Concept Development & Project Leader

Centre For Engineering Research Inc., C-FER• Contracting & Development Support• Technology Licensing

Oil Industry Participants• Funding, prioritization & test wells

Pump and Hydrocyclone Vendors• Prototype Design and Initial Prototypes• Equipment Marketing

Basic Operation

Typical DHOWS Configuration Hydrocyclone Operation Design Constraints

Typical DHOWS Configuration

Hydrocyclone(s)

Concentrate Pump (P2)

Emulsion Pump (P1)

Back Pressure Valve

Producing Zone(s)

Disposal Zone(s)

C-FER/NPEL

Hydrocyclones (De-Oilers)

Tangential Inlet

Disposal Water Outlet

OilConcentrate

Outlet

DHOWS Process Design Constraints Equipment O.D. < 4.5 inches @ 3,600 bfpd Equipment O.D. < 6 inches @ 9,000+ bfpd No access for maintenance for 1-12 years Little or no downhole control or instrumentation Low cost and reliable Water/Oil Ratio to surface = 1-2

Development Project

C-FER/NPEL

Phase I - $20k – Feasibility Study 1992 Phase II – $100k - Prototype Development 1993-94 Phase III – $450k - Field Testing 1994-96 Offshore Study - $360k – North Sea/Sub Sea

Applications On-going Support to Trials - $1.5M – 16 trials

Timeline of NPEL/C-FER DHOWS JIP

1991 1992 1993 1994 1995 1996

Phase I: Concept Generation and Feasibility Study

Phase II: Prototype Development

Phase III: Prototype Field Trials

Commercial Development and Field Installations

Phase I: Off Shore Feasibility Study

Investment in DHOWS Technology

$0

$1

$2

$3

$4

$5

$6

$7

$8

1992 1993 1994 1995 1996

Year

CumulativeInvestment

(Can$Million)

C-FER/NPEL

DHOWS Prototypes

ESP - Electric Submersible Pump - 1800 bfpd• Reduced water to surface by 97%• Oil Rate went up 10-20% at same bottom-hole rates• Ran 8 months 1994-95

PCP - Progressing Cavity Pump - 1800 bfpd• Reduced water to surface by 85%• Well previously in sporadic operation for about 3 yrs.• Ran 17 months 1994-1996

Beam Pump - 600 bfpd• Reduced water to surface by 85%• Demonstrated Gravity Separation• Ran for 2 months - rod failure

ESP Prototype Field Trial

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50

100

150

200

250

300

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450

6 Months Before 8 Months During DHOWS 10 Months After

TotalRate

(m3/d)

SurfaceWaterRate

(m3/d)

InjectionRate

(m3/d)

0

0.5

1

1.5

2

2.5

3

3.5

4

4.5

OilRate

(m3/d)

Total Rate

Oil Rate

Surface Water RateInjection Water Rate

C-FER/NPEL

ESP Prototype Field Trial

1

10

100

1000

Dec-93 Mar-94 Jul-94 Oct-94 Jan-95 May-95 Aug-95 Nov-95

Date

SurfaceWaterRate

(m3/d)

OilRate

(m3/d)

WOR

Oil Rate

WOR

Water Rate

INS

TA

LL

ED

DH

OW

S

PU

LL

ED

DH

OW

S

DHOWS Installations: Number

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45

50

1995 1996 1997 1998

Year

Numberof

Installations

C-FER/NPEL

DHOWS Installations: System Type

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2

4

6

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12

14

16

ESP PCP Beam SingleLiner

TwoLiner

ThreeLiner

SinglePump

DualPump

System Variants

Numberof

Installations

C-FER/NPEL

Breakdown of DHOWS Applications

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2

4

6

8

10

12

14

Formation Type

Numberof

Installations

Casing OD (mm) Well Type

C-FER/NPEL

Basic “DHOWS” Installation - PanCanadian

1

10

100

Jun 95 Aug 95 Oct 95 Dec 95 Feb 96 Apr 96 Jun 96 Aug 96 Oct 96 Dec 96

Date

OilRate

(m3/d)

SurfaceWOR

CO

MP

LE

TE

D I

NJE

CT

ION

ZO

NE

INS

TA

LL

ED

DH

OW

SSurface WOR

Oil Rate

C-FER/NPEL

ESP DHOWS Anderson Exploration Ltd., Swan Hills, AB

0.1

1

10

100

Jan96

Jan96

Mar96

Apr96

May96

Jun96

Jul96

Aug96

Aug96

Sep96

Oct96

Nov96

Dec96

Date

OilRate

(m3/d)

SurfaceWOR

Iso

late

Pro

du

ctio

n &

Inje

ctio

n Z

on

es

Ins

tall

ES

P D

HO

WS

Sys

tem Oil Rate

Surface WOR

Alliance Field Overall Results: ESP

Oil Rate

Surface WOR

1

10

100

1000

Jan95

Feb95

Mar95

Apr95

May95

Jun95

Jul95

Aug95

Sep95

Oct95

Nov95

Dec95

Jan96

Date

Oil Rate

(m3/d)

SurfaceWOR

3 DHOWS InstallationsCompletedSept. 1995

C-FER/NPEL

1

10

100

1000

Dec-94 Jul-95 Jan-96 Aug-96 Mar-97 Sep-97

Date

Surface Water Rate

(m3/d)

Oil Rate

(m3/d)

WOR

INS

TA

LL

ED

DH

OW

S

Water

Oil

WOR

ESP DHOWS Results - Talisman

DHOWS Application Requirements

Suitable disposal zone accessible from the production wellbore

Competent casing/cement for disposal zone isolation

Water cuts above 80% Accurate estimate of productivity and injectivity Relatively stable production Favourable Economics

Critical Success Factors

Disposal Zone Selection• location, isolation, injectivity characterization

Completion• integrity testing• disposal zone preparation and testing

Operation• separation optimization• long term injection behavior• changes in inflow conditions

Typical Installation Steps

Prepare well for installation Pull existing lift system Recomplete injection zone

• perforating, install screen, treat zone Install injection packer and on/off assembly Perform injectivity test Adjust system configuration if necessary Install system Produce kill fluids, then start production

Control and Monitoring

Control Methods• VFD – Variable Frequency Drive• Surface choke• Surface controlled downhole choke

Minimum Monitoring• Injection and producing pressure and injection rate• Injection water quality • Water cut of intermediate stream

Future Equipment Development of “Basic” DHOWS

Heavy Oil: Solve the problem of sand production Offshore: Already under way. Gas Lift Proposal High Volume: Larger capacity system under

development Lower Water cut to surface: Feasible for offshore

subsea Alternate Lift Systems: Gas Lift, Flowing, Jet Pump Alternate Separation Units: More options at low

rates

C-FER/NPEL

DHOWS Licensing Status Peachey Patents - assigned to C-FER C-FER licenses pump vendors

• ESP - World Wide Licenses» REDA - AQWANOT Systems

» Centrilift (Baker-Hughes) - HydroSep Systems

• PCP/Beam - Canadian only to date» BMW Pump/Quinn Oilfield

Baker-Hughes - preferred Hydrocyclone vendor Pump Vendors Collect Royalties for C-FER

• Once per well.

C-FER/NPEL

“Basic” DHOWS Technical Summary

Positive experience is quickly building with over 30 field trials so far.

Still fewer than 20 people world-wide have been involved in more than one application.

All trials have shown water reductions of 85-97% Application of DHOWS can increase oil production

and increase net returns

Impacts of DHOWS on Economic Recovery

DHOWS is new so we are still learning Impacts vary by pool and by well Individual well costs could go up or down Overall operation costs will usually go down Production increases observed in most applications Analysis will try and relate DHOWS and Conventional

economic limits based on analysis of the WOR vs. Cum Oil plot

Economic Cut-Offs for Typical Well Water Budget = US$5/bbl oil

1

10

100

1000

Cumulative Oil Production (Thousands of Bbls)

WO

R

$0.50/bbl water

$0.05/bbl water

Impact of DHOWS on Economic WOR Simmons Well #106

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10

100

1000

Cumulative Oil (Thousands of m3)

WOR

Produced WOR

DHOWS Equivalent WOR @25% of surface handling cost

Impact of DHOWS on Economic WORSimmons Well #109

1

10

100

Cumulative Oil (Thousands of m3)

WOR

Produced WOR

DHOWS Equivalent WOR @ 25%of surface handling cost

Impacts of DHOWS on Costs

Cost to lift Water to Surface (Could go up or down) Gathering and Facilities Costs (Capital & Operating

down) Disposal System (Capital and Operating down) Well Utilization (#Injectors down; #Producers up) Scale/Corrosion Costs (Capital and Operating down) Environmental Costs (Prevention & Clean-up costs

down)

Disposal Power Consumption

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Injection Rate (Thousands of bwpd)

Dif

fere

nti

al P

ress

ure

to

Inje

ct (

psi

)

Power for Single Disposal Well@ 36,000 bwpd

Power for Ten DHOWS Wells@ 3,600 bwpd each

Fracture Pressure

Wellhead Pressure

Overall Profitability for a Sample Well

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$3,000

$4,000

$5,000

$6,000

Base DHOWS @ 25% DHOWS @ 10%

Profit, Fixed Costs, Taxes etc.Water HandlingRoyaltiesDevelopment CostsFinding Costs

Mid-morning Coffee Break

What Has Already Been Done

“DHOWS” Commercial Systems Developed with C-FER

• ESP Commercial – AQWANOTTM and HydrosepTM

• PCP (Weatherford) and Beam (Quinn) available

New “DHOWS” Versions in Trial Stage• Desanding (PCP and ESP)

Gravity Separation Systems - Beam Pumps• Texaco/Dresser, Quinn (Q-Sep)

Reverse Coning Without Separators

DHOWS Horizontal Well - Talisman Energy

Dual Leg Horizontal Well - 2 x 3,000 ft legs

Injection to “Toe” of one leg

Double packer to isolate injection

Produce from second leg and “Heel” of first leg

Dual Horizontal Well “DHOWS”

Talisman Energy Inc

Also Installed With Uphole Injection

Uphole Reinjection

Pump System

Separator

ProducingZone

InjectionPerforations

Injection zone(s) above the production zone(s)

ESP DHOWS

“DHOWS” with C-FER DesanderPump(s)

- ESP or PCP

Desander

Deoiler Hydrocyclone

To Surface

To Injection

Problem - Heavy Oil Wells “Sand” Plugs Injection

Solution – Desanding Sand & Oil to Surface Water to Injection

What Can Be Done

Reverse Coning with DHOWS Re-Entry Drillout (Single Well) Re-Entry Drilling (Multi-well) Cross-Flooding Between Zones

Coning Control with DHOWSSeparator

Injection Zone

Oil Pump

Total Flow Pump

Oil

Water

C-FER/NPEL

Re-Entry Drillout

Pump (Dual or Single;ESP, PCP, Beam)

Separator

Injection Zone

Old Producing Zone(Cement or Leave Open)

Horizontal Re-entry

Horizontal Producing Zone

Create or activate water disposal leg on producing well or producing leg on watered-out or water disposal well

Re-entry drillout or drilled and plugged-off during initial drilling program

Zone cross-flooding between wells

Re-Entry Drilling

Use when zone between injector and producer is swept

Directionally drill to establish new producing or injection location(s)

Producing zone in well provides water for flood

Existing wellbore could be used as producing zone or injection zone

New ProducingLocation

New ProducingLocation

New InjectionLocation

New InjectionLocation

Existing SweptZone

Existing SweptZone

Producing WellProducing Well

InjectorInjector

Cross-Flooding

Multi-layered reservoir application

Some wells produce from lower zone & inject into upper zone

Other wells produce from upper and inject lower

Double the number of injectors or producers without drilling!

WaterLoop

Oil Oil

Horizontal Well Flooding

Use to produce from one horizontal well

Inject into a second horizontal well which is offset lower, higher or going in the opposite direction

Inject into the vertical section of a re-entry horizontal producer.

Top of Formation

Oil/Water Contact

Production

InjectionArealView

Horizontal Cross-Flood

What Might be Done In Future

Offshore: Already under way. Gas Lift Proposal High Volume: Larger capacity system under

development Lower Water cut to surface: Feasible for offshore

subsea Alternate Lift Systems: Flowing, Jet Pump Alternate Separation Units: More options at low

rates Ultimate Vision: No water handling on surface

Oilfield Water ManagementSame Well Source/Injector/Recycle

Lake orRiver Source

Cap rockOil Leg

Water LegCap rock

Underlying Aquifer

DHOWS

Pump

Move toward“Ideal”

The Middle East Water Challenge

Reservoirs contain billions of barrels• Recovery only projected to be 40% due to water

Most wells flowing only oil now• No water handling infrastructure• Wells “die” at 30-40% water cut• Major costs and infrastructure to operate with water

Solution needed:• Install in well and leave for years• No external power• No increase in water

Smart Well Technologies

Building on DHOWS concepts• Modular processes• Few large fixed capital installations• In well if possible and economic• Keep Systems Simple = Reliable

Monitoring and Diagnostics• Benefits of Downhole Monitoring• Real-time Remote Monitoring• Enhanced Analysis

New Technology Production Decline

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Technology OilDecline

Downhole Oil/Water Separation Summary

Positive experience is quickly building. All “DHOWS” wells show water reduced 85-97% Still many applications to try Plenty of potential and opportunity for new concepts

Contact Information

Advanced Technology Centre

9650-20 Avenue

Edmonton, Alberta

Canada T6N 1G1

tel: 780.450.3613

fax: 780.462.7297

email: info@newparadigm.ab.ca

web: www.newparadigm.ab.ca