Closed Loop Conformance Control Methods - LBCG · Injection/Production data No. of wells 4 injectors and 9 producers PPG concentration 750 ppm Injection/production rate ~ 1500 bbl/day

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Mature Fields North America 2015

Houston, Texas

Aug. 25-26, 2015

Closed Loop Conformance Control Methods

rpsea.org

Mojdeh Delshad

Research Professor, The University of Texas at Austin

President/CEO, Ultimate EOR Services LLC

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Motivation

Excess water production is a major problem leading to early well

abandonment and unrecoverable hydrocarbons in mature wells

Current technology has limitations and results of these treatments have

been sporadic and unpredictable

A recent interest in gel treatments uses microgels to overcome some

distinct drawbacks inherent in in-situ gelation systems

We need a better understanding of recent microgel processes based on

systematic laboratory experiments

Ultimate objective is to predict water influx problems, select wells for

treatment, reduce unwanted fluid production

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Motivation

Overview of Conformance Control methods

Field examples

Produced water treatment for reinjection

Concluding Remarks

Presentation Outline

Numerical models to predict the outcome

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Background

o Conventional polymers are mobility control agents

• Primarily target bypassed oil

• More uniform areal and vertical displacement of oil

• Decrease likelihood of viscous fingering

• Not ideal when significant heterogeneity exists i.e. permeability contrast, thief zone,

fractures

o Polymer bulk gels are conformance control agents

• Presence of crosslinking agents that yield polymer networks

• More significant and long-lasting permeability reduction

• Gel treatments can be surface-produced or in-situ

o New microgel technologies are also conformance control agents

• Lower concentrations of polymer and crosslinker

• More suited for in-depth conformance control

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Causes of High Water Production

Vertical heterogeneity Areal heterogeneity

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CLARIANT OIL SERVICESSelective Water Shut-Off

Background

• Extending life of a well as key objective

• Water production in oil & gas wells – global problem

• Increasing water cut:

- natural maturation of well

- Water flood to increase pressure and sweep

• Problems created:

lifting, disposal, separation, scale, corrosion

Solution

• Bullhead downhole, enters all zones of production

interval

• No expensive well interventions (e.g. wireline,

coiled tubing)

• Reduces water production with minimal effect on oil

production

• Value Added:

• Reduce scale, corrosion, sand

• Maintain water pressure support

• Improve sweep

• Reduce hydrostatic head

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CLARIANT OIL SERVICESSelective Water Shut-Off

Products and Application

• Every single water conformance treatment

should be reservoir, well and problem specific

• Clariant customized treatments to target any

conduit from injector to producer well, thief

intervals of natural fractures and/or high

permeability streaks

• Consist of cross-linkable polymer system that

can be bullheaded into the reservoir to

selectively inhibit water whilst allowing

continued hydrocarbon production

• Cross-linker and buffer solution allows the

optimum water shut-off to be achieved across a

range of reservoir permeability (10mD to 10D)

and from 20 C to 130 C (265F)

Injector and Producer Wells Optimization

• Capability to determine the skin damage

mechanism

• Design injection well remediation through

a combination of chemical treatments to

remove organic and inorganic damage

• Treatment to inhibit future damage

deposition in the near wellbore allowing

maximum injection rates at lower

injection pressures

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Microgel Technologies

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• Microgel lots size 0.3 – 1.0 – 2.0 µm

• Broad permeability range (10 - 10,000 mD)

• Commercially available under emulsion and powder forms

• High temperature stability (up to 165°C)

• High shear stability (20,000 sec-1)

• High chemical stability (CO2, H2S, high salinity)

• Environmentally friendly

• Efficient in WSO and Sand Control applications

• Several products available:

• Brightwater@

• Colloidal dispersion gel (CDG)

• Preformed particle gels (PPG)

• Small calibrated microgels (SMG)

Alain Zaitoun, Poweltec, WorkShop EOR, IAPG, Neuquen, 3-5 November 2010

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Example of successfull WSO treatment:Pelican Lake Horizontal Well 11-15A (Canada)

100

200

300

400

500

600

700

800

900

1000

0 %

10 %

20 %

30 %

40 %

50 %

60 %

70 %

80 %

90 %

100 %Water

Oil

Water Cut

Year 1 Year 2 Year 3 Year 4

Treatment

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Alain Zaitoun, Poweltec, WorkShop EOR, IAPG, Neuquen, 3-5 November 2010

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Swelling Capacity for PPGs

l s

s

M MA

M

:lM Volume after swelling

:sM Volume before swelling

Swelling capacity depends on

Salinity

Temperature

Particle Size

Crosslinker ConcentrationBefore swelling After swelling

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Experiments for Scaleup: Heterogeneous Models

Parallel Flow Model(I) Three- Layer Cross Flow Model (III)

Sandwich Model ( II) Cross Flow Model

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Mathematical Model

The mathematical models for flow and transport of microgel

are developed and implemented in reservoir simulator to

characterize particle gel flow and blocking behavior in different

porous media

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Simulation Model of Sandpack

Diameter and Length 2.54 cm, 50.8 cm

Porosity, Permeability 0.386, 27290 md

Initial oil Saturation 0.88

Irreducible Water Saturation 0.12

Pore Volume 99.4 cm3

Temperature 22.5 0C

Salinity 1 wt% KCl (0.134 meq/ml)

Mineral Oil Viscosity 37 cp

Residual Oil Saturation 0.265

Duration of Experiment 268 min

PPG flood Pore volumes injected

1 wt% KCl flood 2.5 PV

2000 ppm PPG in 1 wt% KCl 1.2 PV

1 wt% KCl post flush 1.7 PV

Water Flood

1.7 PV

PPG Injection

1.2 PV

Water Flood

2.5 PVInjection Production

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Simulation of Sandpack Experiment

0

10

20

30

40

50

60

70

80

90

100

0 0.5 1 1.5 2 2.5 3 3.5 4 4.5 5 5.5 6

Reco

very

(%

OO

IP)

PV Injected

Water FloodPPG InjectionWater Flood

UTGEL

Lab Data

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0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

0.9

1

0 0.5 1 1.5 2 2.5 3 3.5 4 4.5 5 5.5 6

Wate

r C

ut

PV Injected

Water FloodPPG InjectionWater Flood

UTGEL

Lab Data

Total Oil Recovery

Water Cut

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Field-Scale Simulation

No. of grids 19×19×3

Dx = Dy 32.8 ft

Dz (ft) 10, 20, 10

Porosity 0.3

Salinity 3411 ppm

Ratio of Kv/Kh 0.1

Simulation time 1000 days

Fluid Properties

Residual water saturation 0.25

Residual oil saturation 0.15

Oil viscosity 37 cp

Water viscosity 1 cp

Injection/Production data

No. of wells 4 injectors and 9 producers

PPG concentration 750 ppm

Injection/production rate ~ 1500 bbl/day

Injection design

Base case: 100 d waterflood

PPG:

100 d waterflood

300 d PPG injection

600 d waterflood

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PPG Field Simulation

Permeability Distribution

Initial Water Saturation

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PPG Field Simulation

PPG concentration at 200 days

Oil saturation at 200 days

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PPG Field Simulation

PPG RRF (end of PPG flood)

RRF (end of post water flood)

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PPG Field Simulation

0%

20%

40%

60%

80%

100%

0 200 400 600 800 1000 1200

Wa

ter

Cu

t

Time (Days)

PPG flood vs. Waterflood

Base Case: Waterflood

PPG flood

0

20

40

60

80

100

0 200 400 600 800 1000 1200

Oil

Re

co

very

(%

OO

IP)

Time (Days)

PPG flood vs. Waterflood

Base Case: Waterflood (26 % Oil Recovery)

PPG flood (60 % Oil Recovery)

Water Cut

Oil Recovery

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PPG Evaluation with Conduits

A synthetic case was generated to simulate PPG’s propagation

through a long reservoir conduit

PPG was capable of propagating through the conduit, reducing its

permeability, and subsequently improving the sweep efficiency -

this was observed by the change of water saturation profile

through the reservoir with time

Required studies and matching attempts ongoing to further

validate the simulator

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PPG Evaluation with Conduits

PPG treatment simulated in a scenario where there is a conduit aligned

in the middle of a waterflood injection pattern

PPG was capable of diverting injected water to producers located off

conduit’s direction - this was observed by the change of water

saturation profile throughout the reservoir with time

Optimization attempts ongoing to further understand how to optimize

PPG treatment in different waterflood scenarios

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Water Treatment Solutions

o Goals:

• Determine if CEOR chemical recovery is desired for reinjection or if CEOR chemical should be

removed/destroyed

• Identify technologies which can treat PW to the specification required for PWRI

• Maximize treatment efficiency and address weight, footprint, and other unique aspects of ASP

projects

o If downstream treatment is necessary to meet CEOR salinity/hardness requirements, PWRI

treatment also dictated by downstream unit operations:

• Reverse osmosis (RO) desalination of nanofiltration (NF) softening

• Ion exchange

• Alternative technology (forward osmosis, electrodialysis, membrane distillation)

Parameter Units RO and NF Ion Exchange Alternatives

Turbidity NTU 1 5 5

Oil mg/L <1 <1 <5-20

Temperature °C 45 100 45-100

SDI15 3-5 3-5 NA

Upstream Requirements

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Summary and Conclusions

Microgels have great applications in WSO/Conformance with higher stability

than conventional polymers

Experiments were performed in both fracture and sandpack to rank the effectof PPG on improving conformance and reducing water cut

Mathematical models were developed for rheology, adsorption, swelling ratio,resistance factor, and residual resistance factors

Gel transport models were implemented in a reservoir simulator and validatedagainst laboratory experiments

Framework provides guidance for better design and optimization of microgelwater shutoff process

Water production can significantly be reduced

Produced water reinjection should be seriously considered for conformancemethods

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• Water Management in Mature Oil Fields using Advanced Particle Gels, RPSEA Contract #11123-32

• Lisa Henthorne, SVP & Chief Technology Officer, Water Standard

• Clariant

rpsea.org

Acknowledgement

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Microgels Injection Experiments

Objectives

o Obtain recovery factor and

water cut during water injection

and gel injection processes

o Obtain the gel concentration

effect on RF, RRFw, RRFo, and

injectivity index

o Determine thermal effect on

microgel propagation

o Study permeability effect on

microgel propagations

Experiment Model

Five Pressure taps Heater