Technology Oil Potential with DHOWS 600 500 400

Technology Oil Potential with DHOWS 600 500 400

Technology Oil Potential with DHOWS 600 500 400 300 200 Technology Oil Conventional 100 6 4 2 2000 98

96 94 92 90 88 0 86 Average Production BOPD 700 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? Annual Production - Millions of bbls Water and Oil Production in Western Canada 2500 2000 Water Production Oil Production 1500 1000 500 0

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 Oil to Surfac e Separator & Pump(s) Basic Downhole Separation

New Paradigm 1991 Commercial - 1996 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 Concentrate Pump (P2) Producing Zone(s) Emulsion Pump (P1) Hydrocyclone(s) Back Pressure Valve Disposal C-FER/NPEL

Zone(s) Typical DHOWS Configuration Hydrocyclones (De-Oilers) Tangential Inlet Oil Concentrate Outlet Disposal Water 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 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 C-FER/NPEL 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 $8

$7 $6 Cumulative Investment (Can$Million) $5 $4 $3 $2 $1 $0 1992 C-FER/NPEL 1993 1994 Year 1995

1996 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 450 4.5 Total Rate Oil Rate Surface Water Rate Injection Water Rate 400 Total 350 Rate (m3/d) 300 4 3.5 3

Surface 250 Water Rate 200 (m3/d) 2.5 2 Injection 150 Rate (m3/d) 100 1.5 50 0.5 1

0 0 6 Months Before C-FER/NPEL 8 Months During DHOWS 10 Months After Oil Rate (m3/d) ESP Prototype Field Trial 3 100 PULLED DHO W S

Surface Water Rate IN S T A L L E D D H O W S 1000 Water Rate WOR (m /d) Oil Rate 3 (m /d) 10

WOR Oil Rate 1 Dec-93 Mar-94 Jul-94 Oct-94 Jan-95 Da te May-95 Aug-95 Nov-95 DHOWS Installations: Number

50 45 40 35 Number 30 of 25 Installations 20 15 10 5 0 1995 1996 1997 Year C-FER/NPEL 1998

DHOWS Installations: System Type 16 14 12 10 Number of 8 Installations 6 4 2 0 ESP C-FER/NPEL PCP Beam Single Two Three Liner Liner Liner

System Variants Single Dual Pump Pump Breakdown of DHOWS Applications 14 12 10 Number 8 of Installations 6 4 2 0 Formation Type C-FER/NPEL Casing OD (mm)

Well Type Basic DHOWS Installation - PanCanadian 10 Surface WOR INSTALLED DHOWS Oil Rate (m3/d) COMPLETED INJECTION ZONE 100 Oil Rate Surface WOR

1 Jun 95 Aug 95 Oct 95 Dec 95 Feb 96 Apr 96 Jun 96 Aug 96 Oct 96 Dec 96 Date C-FER/NPEL Oil Rate (m 3/d) Surface WOR 10 1 0.1 Jan Jan 96 96 Mar Apr 96 96

Install ESP DHOWS System 100 Isolate Production & Injection Zones ESP DHOWS Anderson Exploration Ltd., Swan Hills, AB May Jun 96 96 Jul 96 Date Oil Rate Surface WOR

Aug Aug Sep 96 96 96 Oct Nov Dec 96 96 96 Alliance Field Overall Results: ESP 1000 Oil Rate (m 3/d) Surface WOR 3 DHOWS Installations Completed Sept. 1995 Oil Rate

100 Surface WOR 10 1 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan 95 95 95 95 95 95 95 95 95 95 95 95 96 Date C-FER/NPEL ESP DHOWS Results - Talisman I N S TA L L E D D H O W S 1000 Water Surface Water100 Rate

3 (m /d) Oil Oil Rate 3 (m /d) 10 WOR WOR 1 Dec-94 Jul-95

Jan-96 Aug-96 Date Mar-97 Sep-97 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 1000 WOR 100 10 $0.05/bbl water $0.50/bbl water 1

Cumulative Oil Production (Thousands of Bbls) Impact of DHOWS on Economic WOR Simmons Well #106 1000 100 Produced WOR DHOWS Equivalent WOR @ 25% of surface handling cost WOR 10 1 Cumulative Oil (Thousands of m 3) Impact of DHOWS on Economic WOR Simmons Well #109 100

Produced WOR DHOWS Equivalent WOR @ 25% of surface handling cost WOR 10 1 Cumulative Oil (Thousands of m 3) 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) Differential Pressure to Inject (psi) Disposal Power Consumption 450 400 350 Fracture Pressure 300 Power for Single Disposal Well @ 36,000 bwpd 250 200

150 100 Power for Ten DHOWS Wells @ 3,600 bwpd each 50 Wellhead Pressure 0 0 3 6 9 12 15

18 21 24 27 30 Injection Rate (Thousands of bwpd) 33 36 Overall Profitability for a Sample Well $6,000 $5,000 Profit, Fixed Costs, Taxes etc.

Water Handling Royalties Development Costs Finding Costs $4,000 $3,000 $2,000 $1,000 $0 Base DHOWS @ 25% DHOWS @ 10% Mid-morning Coffee Break What Has Already Been Done

DHOWS Commercial Systems Developed with CFER 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 Also Installed With Uphole Injection Talisman Energy Inc Uphole Reinjection

Injection zone(s) above the production zone(s) ESP DHOWS Pump System Separator Injection Perforations Producing Zone To Surface Pump(s) - ESP or PCP DHOWS with C-FER

Desander Problem - Heavy Oil Wells Sand Plugs Injection Solution Desanding Sand & Oil to Surface Water to Injection Desander Deoiler Hydrocyclone To Injection What Can Be Done

Reverse Coning with DHOWS Re-Entry Drillout (Single Well) Re-Entry Drilling (Multi-well) Cross-Flooding Between Zones Oil Pump Oil Total Flow Pump Separator Water Injection Zone C-FER/NPEL Coning Control with DHOWS

Re-Entry Drillout 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 Pump (Dual or Single; ESP, PCP, Beam) Separator

Horizontal Re-entry Horizontal Producing Zone Old Producing Zone (Cement or Leave Open) Injection Zone 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 Producing Location New Injection Location Existing Swept Zone Producing Well Injector 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! Oil Oil Water Loop

Horizontal Cross-Flood 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 Production Oil/Water Contact Areal

View Injection 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 Management Same Well Source/Injector/Recycle Lake or River Source Move toward Ideal Cap rock Cap rock Oil Leg Water Leg Underlying Aquifer DHOWS Pump 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 600 500 400

300 200 Technology Oil Decline Conventional Decline 100 6 5 4 3 2 1

2000 99 98 97 96 95 94 93 92 91 90

89 88 87 0 86 Average Production BOPD 700 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: [email protected] web:

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