technology oil potential with dhows downhole oil/water separation background basic operation ...
TRANSCRIPT
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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Ann
ual P
rodu
ctio
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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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450
6 Months Before 8 Months During DHOWS 10 Months After
TotalRate
(m3/d)
SurfaceWaterRate
(m3/d)
InjectionRate
(m3/d)
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0.5
1
1.5
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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
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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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1995 1996 1997 1998
Year
Numberof
Installations
C-FER/NPEL
DHOWS Installations: System Type
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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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4
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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
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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
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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
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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
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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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Cumulative Oil (Thousands of m3)
WOR
Produced WOR
DHOWS Equivalent WOR @25% of surface handling cost
Impact of DHOWS on Economic WORSimmons Well #109
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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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$1,000
$2,000
$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: [email protected]
web: www.newparadigm.ab.ca