Application of Bright WaterTM Technologyiea-eor.ptrc.ca/2010/assets/B5_Slides.pdfApplication of Bright Water™ Technology Dave Thrasher, BP October 2010 Bright Water™ is a Trade

Application of Bright Water™TechnologyDave Thrasher, BPOctober 2010

Bright Water™ is a Trade Mark of Nalco Energy Services LP used by BP under licence© BP plc, September 2010

© BP plc, September 2010 2

Introduction

• Waterflood Conformance EOR Targets

• Bright Water™ Technology Development

• First Commercial Trials

• Widespread Application and Treatment Characteristics

• Track Record of Success

• Future Possibilities

• Particular acknowledgements to Harry Frampton, Paul Denyer and previous paper authors/co-authors

• Presentation is a follow-up to Frampton et al, EAGE, Paris 2009


Waterflood Conformance EOR Targets

• Bright Water™ is a chemical technology for improving waterflood sweep

• Vertical conformance

− high permeability streaks or thief zones

• Areal conformance

− improving sweep of channel margins

• Direct communication with lower permeability sands

− no shale or other barrier to help with isolation

• Improve sweep with in-depth chemical block (identified by simulation)

• Wanted technology that could be bullheaded into injection well with no injectivity loss

• Also wanted a low-adsorbing single chemical species to avoid impacts from precipitation or chromatographic effects

− Lessons from Deep Diverting Gel field trial in Alaska in 1991


Simulation of Block Requirements

• Simulation studies showed that an in-depth block was more effective than a near-wellbore block for an unconfined thief zone

− In these cases, an in-depth block always produced more oil

1

Reservoir Temperature (°C) 70

Average Injection Rate (m3/day) 569

Pre-Treatment Waterflood Duration (days) 2000

Distance to Producer (m) 805

Thief Block Location in Structure Low Low High and Low High High High Low Low

Near-Well Block Placement Injector ProducerInjector

and Producer

Injector ProducerInjector

and Producer

Injector Producer

%OOIP Incremental at Abandonment for Near-Well Block 2.7 2.9 6.0 0.8 2.1 2.9 -0.9 1.7

%OOIP Incremental at Abandonment for Deep Block 8.5 6.5 6.5 4.4 4.4 4.4 5.6 5.6

%OOIP Incremental of Deep Block Relative to Near-Well Block 5.8 3.6 0.5 3.6 2.3 1.5 6.5 3.9

927

Reservoir Structure

4

154

350

700

805

3

70

397

2000

805

70

397

2000

2

After Frampton et al (2009)


Bright Water™ Technology Development

• BP had original idea for a time-delayed, temperature-activated, highly expandable particulate material

• Product developed by industry consortium MoBPTeCh from 1997

− BP, Chevron (Mobil and Texaco also initially)

− Nalco was selected for co-development

• Sub-micron particles in mineral oil suspension

• Surfactant co-injected to aid contact of particles with water

• Unaffected by shear, and relatively robust over a range of pH (7-8.5), salinity and water chemistry

− Not suitable for carbonates, high calcium

• Injects with no injectivity loss

• Stable up to 95°C and can take advantage of thermal fronts for hotter reservoirs


Bright Water™ Mechanism – Pore Scale

Reversible crosslinks

Heat and time

The particle conformation expands as the crosslinks reverse. Low levels of permanent crosslinker keep the particle from “decomposing”

0.1 to 1 micron diameter 1 to 10 micron diameter

Representation of 5 micron particles in a pore throat

Reversible crosslinks

Heat and time

The particle conformation expands as the crosslinks reverse. Low levels of permanent crosslinker keep the particle from “decomposing”

0.1 to 1 micron diameter 1 to 10 micron diameter1 to 10 micron diameter

Representation of 5 micron particles in a pore throat

(months)

• As the temperature rises, reversible cross-links start to break by hydrolysis

• Swelling of the particles occurs and they associate to block pore throat

‘Popcorn’ analogy


Example Lab Sandpack Results

• First samples of chemical received early in 1998

• Evaluated in bottle tests, slimtube tests and sandpack tests

• Example resistance factors generated by slowest-reacting grade of Bright Water™ in 800md sandpacks at 90°C

Res

ista

nce

Fac

tor

Time (days)

Main resistance generated in 10-20ft and 20-30ft sections


Flow Direction

0 – 10ft 10 – 20ft 20 – 30ft 30 – 40ft

P P P P P

0-10ft

10-20ft

20-30ft

30-40ft


Cool injection water

Cold transition warm

Selection of the polymer popping temperature is critical to achieve good placement – four grades of product

Once a block is created, flow is diverted to other layers

Diversion to recover oil in channel margins

Bright Water Mechanism – Field Scale


First Field Trials

• First field trial pumped in Minas Field, Indonesia in November 2001

− SPE 84897 (Pritchett et al) and SPE 89391 (Frampton et al)

− Demonstration of incremental oil not expected due to flood maturity, but some observed

− Proved logistics of supply and application

− Unequivocal evidence of in-depth blocking at a distance up to 38m from injector

− Encouragement to take forward to commercial field trials

• First offshore field trial pumped in UK North Sea in 2002

− SPE 84897 (Pritchett et al) and IOR Paris 2009 paper 5035 (Frampton et al)

− Proved treatment could be injected offshore, even on minimum facility platforms

− Proved injection into ~400md sandstone without loss of injectivity

− Field divested before any producer results available


First Commercial Field Trials

• First commercial field trial started at the Milne Point Field, Alaska in June 2004

− SPE 121761 (Ohms et al)

− Incremental oil produced over 2005-7 at costs competitive with traditional wellwork and lower than sidetracking

• Further set of 3 wells treated at Prudhoe Bay between November 2004 and February 2005

− SPE129967 (Husband et al)

− Learnings from undertaking winter treatments in the Arctic

− Again incremental oil produced

− One well was re-treated in 2009

• First field trial in Argentina pumped in 2006

− SPE 129732 (Mustoni et al) and SPE 107923 (Yanez et al)

• Widespread application started when these showed commercial oil


Alaska Application – in Summer!

After SPE121761 (Ohms et al)


Example injectivity data pre- and post-treatment

• After ~8 months, the injectivity is reduced due to Bright Water popping deep in the reservoir and generating a resistanceto flow in the highest permeability rock

After Ohms et al (2009)

Pre and Post Treatment Injectivity Trends

1900

2000

2100

2200

2300

2400

2500

2600

2700

600 1000 1400 1800 2200 2600Injection Rate (bwpd)

WH

Inj.

Pres

sure

(psi

)

Pre Treatment InjDuring Treatment Inj9-12 mo. Post Treatment2 yr Post Treatment3 yr Post TreatmentLinear (Pre Treatment Inj)Linear (During Treatment Inj)Linear (9-12 mo. Post Treatment)


Widespread Application

• Treated wells in a number of fields with a range of conditions

Field Reservoir Character

Injection Water

Temperature (°C)

Reservoir Temperature

(°C)

Injection Water

Salinity (mg/l TDS)

A Layered with thief zone 50-60 64-88 16,000

B Layered channel sand 49-55 71-80 12,000

C Layered with thief zone 56-60 66-71 16,000

D Layered with thief zone 60 71 16,000

E Layered channel sand 49 80 12,000

F Compartmentalised, layered with thief zone 40-53 77-82 16,000

G Layered with thief zone 52 99 121,000



Treatment Characteristics

• All wells cased, cemented and perforated

• Some had injection control mandrels on each zone

• Thief porosity range 19-26%

• Thief zone thicknesses up to 75ft successfully treated

• Ratio of thief to pay thickness up to 50%

• Thief zone average permeabilities range from ~250md up to ~1400md

• Permeability contrast of thief to zone average range 2-7

− Permeability contrast between thief and bulk estimated from coreand/or log-derived values

• Pre-treatment watercut from 66-99%

− Most wells greater than 85%


Bright Water - Treatment Success

• High success rate to date, with incremental oil from >80% of treatments that have passed their evaluation window

• 21 (out of 25) treatments have delivered an increase to recoverable volumes of more than 9 million barrels at a development cost of less than $6 per barrel *

Jobs Pumped to end 2009 38

Jobs with >1.5years 25since pumping

Jobs where incremental 21oil measured

• On track to do 19 treatments in 2010

* BP Annual Report and Accounts 2009


Water-Oil Ratio Reduction Example

• Treatments by PAE in Argentina - SPE129732 (Mustoni et al)• Overall WOR reduced from ~55 to ~40 each barrel of oil produced with

15 less barrels of water

• Corresponds to an oil cut increase of 37%

PAE Pattern Water Oil Ratio - Weighted Average

PAE ONLY

0

20

40

60

80

100

-36.0 -24.0 -12.0 0.0 12.0 24.0 36.0Month Since Treatment Pumpped

Wat

er O

il R

atio

(%)

Treatments date Response Start-up

MONTHS SINCE TREATMENT PUMPED

PATTERN WATER-OIL RATIO – WEIGHTED AVERAGE

WA

TE

R-O

IL R

AT

IO

-36 -24 -12 0 12 24 36

After Mustoni et al (2009)


Incremental Oil Recovery Example

• Wells respond at different rates• Some wells may not respond to treatment or be difficult to interpret

• Lack of clear response in Wells 2 & 4 attributed to extensive well shut-ins that impeded treatment evaluation

After Mustoni et al (2009)

Well 6

Well 1

Well 2

Well 3

Well 4

Well 5

0.0

0.5

1.0

1.5

2.0

2.5

0 4 8 12 16 20 24 28 32 36 40 44Months Since Treatment

Incr

emen

tal R

ecov

ery,

%O

OIP

0.00%

0.5 0%

1 .00%

1 .5 0%

2 .00%

2 .5 0%

Well 6


Multi-Well Application Trial

• Trial of 5 injectors pumped simultaneously with chemical injection into water injection header

• Operational Benefits− Less HSE exposure with fewer rig-ups & rig-downs− Cost savings – 20% lower than doing individual treatments− Time savings – 75% less time than treating each well sequentially

• Other Issues− Other wells may need to be shut-in if do not want to treat them− May need to make some rate adjustments in some injectors to ensure

correct treatment volume to each well

− More extensive flow line pre-flush with surfactant


Future Possibilities

• Expand geography of application

• Broaden operational settings

− Including lower temperature reservoirs with new grades of Bright Water™

• More intensive use of manifold treatments


Bright Water™ Application Conclusions

• Delayed-swelling particulate concept proved

− Reagents developed, commercialized and proved in the field

− Field trials carried out in multiple locations

• Technology track record developed with wider application (>80% success)

− Successful treatments of wells across range of fields with:

− Injection water salinities of up to 121,000ppm TDS

− Reservoir temperatures up to ~100°C

− Thief permeabilities up to ~1400md

− Of 25 treatments started more than 1.5 years ago, 21 have produced incremental oil at less than $6/bbl

• Future deployment

− Expanding opportunities

Application of Bright Water™ TechnologyIntroductionWaterflood Conformance EOR TargetsSimulation of Block RequirementsBright Water™ Technology DevelopmentBright Water™ Mechanism – Pore ScaleExample Lab Sandpack ResultsFirst Field TrialsFirst Commercial Field TrialsExample injectivity data pre- and post-treatmentWidespread ApplicationTreatment CharacteristicsBright Water - Treatment SuccessMulti-Well Application TrialFuture PossibilitiesBright Water™ Application Conclusions

Documents

Application of Bright WaterTM Technologyiea-eor.ptrc.ca/2010/assets/B5_Slides.pdfApplication of Bright Water™ Technology Dave Thrasher, BP October 2010 Bright Water™ is a Trade