Water Quality and Conformance Issues in Tight Oil Plays Using HMSF

Injection Wells

SPE Tight Oil Workshop – April 29, 2015

2

Agenda

• How important is waterflooding to us?

• Defining the discussion

• Common knowledge (?)

• Does/did waterflooding work in Canadian conventional tight oil plays?

• The Importance of Water Quality

• What determines the required water quality – Setting the Spec

• The Typical Outcome of Poor Water Quality - Examples

• What potentially makes HMSF water-flooding different than our previous experiences

• An Example of Poor Water Quality in a HMSF Well

• A Discussion on Frac Gradients – Simpleton Style

• Sample Water Treatment System

3

Waterflooding and the Future of the Canadian Oil Industry

• For wells with no means of pressure support - After the first 6 to 12 months

our typical well spacing produces an exponential decline…. not harmonic or

hyperbolic as is frequently promised. With decreases in pressure comes an

increase in Sg, a decrease in Ko, and an increase in viscosity so why should

production stabilize? In some fields the economic limit on primary production

is reached in 3 to 4 years.

• If you believe that statement, the only obvious way to provide the booked

reserves, and improve the RLI is to prevent the decline in pressure and ko.

Waterflooding seems like the obvious answer.

A typical Scenario?

High decline rates with a

rapidly increasing GOR

followed by an attempt to

waterflood followed by an

almost instantaneous leap in

watercut. $30 to $50 F&D?

4

Defining the Discussion

- We are discussing the poor end of conventional – the “almost able to

waterflood” reservoirs such as the L. Amaranth, Viking, and

Cardium. Others can ponder how to flood source rock.

- The answers to all questions won’t/can’t be provided here and not

all statements will be substantiated but the hope is that creative

questioning will result.

- Vertical waterflooding in these reservoirs will be discussed before we

determine how anything we may already know (and perhaps

forgotten) can be applied to the HMSF well paradigm

5

Waterflooding – Common Knowledge? – Common Questions?

- Water quality directly affects injectivity and conformance. Setting the

specifications is important. How?

- What should you monitor/interpret the data and what can you do about it?

- Can water quality can be controlled economically in the context of a long

term project?

- Pressure response will not been seen until the free gas saturation (Sg) is

displaced. Fill-up time affects the economics of the projects. When to

start?

- Can high gas saturations adversely affect the flood?

- Most water floods inject above frac pressure!? Sharma et al SPE 52731. Is

this true? Can it be avoided? Does it matter?

- “We have been pumping water for years and the water-cut is low so it is

obvious the water went somewhere else”

6

Did Waskada, Lower Amaranth Vertical Waterflood Work? Irrefutably! But… There is no More Injection!

Primary recovery

factor 2-3%

Waskada: Recovery factor vs Vd on vertical waterfloods

Sec 25 (Swc=39%)

16.00

4.00

6.00

8.00

10.00

12.00

14.00

Rec

over

y F

acto

r %

1.40 1.20 1.00 0.80 0.60 0.40 0.20

Vd (Injected Vol / Moveable Oil Pore Vol)

2.00

Most sections honor

theoretical waterflood

performance

Sw

Avg Swor Vd

Max

RF% RF%

0.42 0.65 0.2 39.7 7.0

0.42 0.65 0.4 39.7 14.0

0.42 0.65 0.6 39.7 20.9

0.55 0.65 0.2 22.2 1.7

0.55 0.65 0.4 22.2 3.4

0.55 0.65 0.6 22.2 5.1

Symbol represents land Section Rf

Note that the PV

noted here is final,

the flood was

discontinued due to

lack of injectivity.

7

Why is Water Quality Important?

• In low permeability formations the pore throats are often sub-

micron in size – typically small compared to the particle sizes

contained in our water – Plugging at the formation face should be

expected.

• Any oil found in the injection water can reduce the relative

permeability of the formation to water and thereby reduce the

injection rate. This “reverse emulsion” is often stabilized by solids

thereby increasing the total TSS content of the water

• Waterflood performance and profit is directly related to the rate at

which water is injected.

• Even if a portion of the formation is permeable enough to accept

the oil and solids it is likely that the tighter portions will plug and

be missed

• Plugging can lead to frac extension which could affect conformance

– Arguably more serious with HMSF wells than vertical

8

But We Get the Water Away!!

- The Cardium has a long history of injection well stimulations –

they worked – Temporarily

- In most floods, the injectivity is typically improved and

extended by injecting above the frac gradient

- Many tight floods have been abandoned due to low injectivity

but theoretically worked based on the volumes that were

injected. Consider the L. Amaranth in Manitoba and the eastern

portion of the Dodsland Viking field.

9

Setting the Spec Typical Waskada Pore Throat

Distribution

ROT - Pore

throats will

bridge off with

solids as small

as 1/3 to 1/7th

the pore throat

size. (Bennion et

al JCPT June 1998

Vol 37 No. 6)

10

Setting The Spec – Waskada Example

Conventional filtration is expensive - Typical Total Suspended Solids in

Produced Water – 150 – 450 ppm by weight. Cost to conventionally filter

1000 bpd to 90 ppm TSS estimated to be $850 k per year based on

manufacturer design loading. Estimated IGF system op cost ~ $0.05/bbl

oil depending on power, chemical requirements, disposal costs. PW has

recently started operation of an IGF/Deep bed system and is currently

determining the actual costs. Capital cost ~ $1.00/bbl of oil depending

on scale.

Calculations based on filter theory for vertical wells in Waskada

indicated that plugging would occur on an average of 130,000 bbls

before frac extention would occur (Verfied by the records).

Those same calculations suggest that at 5 ppm TSS there would be no

frac extension during the life of the flood. 30 ppm would provide 7

years before frac extension starts. With the tight well spacing used in

many tight plays the flood would be essentially complete by this time.

PWT Tight Oil Spec < 5 ppm TSS < 5 ppm – Maximum allowed – 30 ppm

11

Fracture Plugging and Growth Can Be Predicted

- See SPE 52731 Role of Fracture

Face and Formation Plugging in

Injection Well Fracturing and

Injectivity Decline – Sharma et al U

of Texas

From Bennion et al JCPT 1998

Damage Mechanisms: 1 - Mechanically induced

- Injection of solids

- Fines migration

2 – Water/Rock Interactions

- Clay swelling

- Clay deflocculation

- Formation dissolution

- Chemical adsorption/wettability alterations

3 – Rel Perm effects

- Skim oil entrainment

- Free gas entrainment

4 – Biologically induced impairment

- Bacterial entrainmnent and growth

5- Injection water/in-situ fluid interactions

- Formation of insoluble scales

- Emulsification and emulsion blocks

- Precipitation

- Wax/asphaltene deposition

A Large List of Potential

Dangers!

12

Frac Extension Rate and Intersection with Producers

PPM

Suspended

Solids

Est Density

of solids

(kg/m3)

Inj Rate

Per Frac

(m3/d)

Net Pay

(m)

Frac

Length Porosity Depth (cm)

Porosity

Vol (m3)

Monthly

Solids Vol

(m3)

Time to

Plug

Existing

Time

(months)

Time to

Plug

Existing

Frac

(years)

Cum Inj Vol

(m3)

Cum Inj Vol

(bbls)

Frac

Extension

speed at Q

(m/mo)

Time to 75 m

length (yrs)

1 2200 13 7 50 0.15 1 2.1 0.0004 5414 451.1 2,065,574 12,992,459 0.009 676.7

10 2200 13 7 50 0.15 1 2.1 0.0039 541 45.1 206,557 1,299,246 0.092 67.7

20 2200 13 7 50 0.15 1 2.1 0.0078 271 22.6 103,279 649,623 0.185 33.8

30 2200 13 7 50 0.15 1 2.1 0.0116 180 15.0 68,852 433,082 0.277 22.6

40 2200 13 7 50 0.15 1 2.1 0.0155 135 11.3 51,639 324,811 0.369 16.9

50 2200 13 7 50 0.15 1 2.1 0.0194 108 9.0 41,311 259,849 0.462 13.5

60 2200 13 7 50 0.15 1 2.1 0.0233 90 7.5 34,426 216,541 0.554 11.3

70 2200 13 7 50 0.15 1 2.1 0.0272 77 6.4 29,508 185,607 0.647 9.7

80 2200 13 7 50 0.15 1 2.1 0.0310 68 5.6 25,820 162,406 0.739 8.5

90 2200 13 7 50 0.15 1 2.1 0.0349 60 5.0 22,951 144,361 0.831 7.5

100 2200 13 7 50 0.15 1 2.1 0.0388 54 4.5 20,656 129,925 0.924 6.8

125 2200 13 7 50 0.15 1 2.1 0.0485 43 3.6 16,525 103,940 1.155 5.4

150 2200 13 7 50 0.15 1 2.1 0.0582 36 3.0 13,770 86,616 1.385 4.5

175 2200 13 7 50 0.15 1 2.1 0.0679 31 2.6 11,803 74,243 1.616 3.9

200 2200 13 7 50 0.15 1 2.1 0.0776 27 2.3 10,328 64,962 1.847 3.4

Typically in Waskada, frac extension was estimated and verified from injection rate

analysis to occur at ~130,000 bbls of cumulative injection. How to estimate the

potential in a horizontal? If 80% of the injection was to enter 20 % of the fracs and the

injection rate was 300 bpd we could expect to intersect a producer in 3.9 years. We

expect it will take 1 year to fill the reservoir and another 2 years to reach the peak oil

production assuming a steady rate and no plugging.

13

Examples - Waskada Section 25-001-26W1 Pattern Analysis

9-25

3-25

3-25 1-25

9-25

6-25

14

Fill up and

plugging

phase

Frac

Extension

Phase

Loss of

Injectivity

Final Frac

Extension

in Attempt

to Regain

Injection –

Sudden

and Final

Increase

in WC %

Typical WF Behavior – Waskada L. Amaranth – Best in Field Recovery Scenario

15

Typical WF Behavior – Waskada L. Amaranth – Excellent Recovery Scenario

Fill up and

plugging phase

Frac

Extension

Phase

Loss of

Injectivity

Final Frac

Extension

in Attempt

to Regain

Injection –

Sudden

and Final

Increase

in WC %

16

Example – Poor Water Flood Performance – Waskada L. Amaranth

Fill up and

plugging

phase

Frac

Extension

Phase Loss of

Injectivity Final Frac

Extension

in Attempt

to Regain

Injection

17

Is HMSF Waterflooding In Any Way Different Than Conventional Waterflooding?

- Orientation – In Canada, HMSF wells are typically oriented in a N-S or

E-W orientation. Many vertical water-floods were ultimately built as

inverted 5/7/9 spots or line drives.

- Timing – Historically, waterfloods were initiated prior to or close to

reaching bubble point. The enhanced ability of Hz wells to deplete a

reservoir along with the current royalty schemes in Canadian

provinces encourages operators to delay waterflooding until the

reservoir is in an advanced state of depletion.

- Control – Determining where the water is going in a HMSF well is

much more difficult and expensive than in a vertical well. Both with

regard to the distribution amongst the stages but also vertically.

- Remediation – Cleanouts, diversion etc is expensive and difficult.

Preventing the need for workovers is important if not critical.

18

MORE DANGER - Frac Geometry in Hz Project Provides Short Paths Between Fracs

In a 40 acre

spaced vertical

flood you will be

565 m on the

diagonal from Inj

to producer. Hz

patterns are often

100 to 200 m

19

East Dodsland Hz Injection Pilot

19

T31

T20 W3

• 4-11 Well

Drilled For

Injection Only

• 10 x 20 Tonne

Fracs – Packers

Plus System

• Injection

Initiated March

2009

• ~633,000 bbls

Injected to

date

20

4-11 Dodsland Pilot Area

Hz

Production

Apparent Improvement in GOR

Until Initiation of Hz Production

21

Dodsland hz Pilot – Quick Short-circuit

22

Dodsland Hz Pilot – Best Response

23 23

Water BT or Oil Incr. Response Contour Map

1 month

2 months

3 months

4 months

9 months

Author – Jennifer Clee

24

East Dodsland Pilot – Fracture Extension

Fillup and

plugging

phase

Frac

Extension

Phase Frac Extension

Phase

Small Decrease in

Pressure = Loss of

Injectivity = Frac

Extension Required to

Maintain Injection

Current

Injection

Pressure

Gradient ~

23 kPa/m

Pressure

Rate

25 25

2009-0

3-0

4

2009-0

5-0

5

2009-0

7-3

1

2010-0

5-

29

2011-0

3-

10

2011-0

9-1

7

• No workover

since on

injection

• Flattening of

slope is a

probable

indicator of

fracture

extension

• Increase in

slope probable

indicator of

plugging

East Dodsland Hz Injection Pilot – Hall Plot

26

Dodsland Porethroat Size

• 82 % of pore

throats are <

1.5 micron

• To prevent

blocking,

particles

must be less

than 1/3 to

1/5 the pore

throat size

or < 0.5 to

0.3 microns.

27

Dodsland Horizontal Injector Pilot; 4-11-31-

20w3 Particle size distribution upstream of 5 micron sock filter

28

Dodsland Horizontal Injector Pilot; 4-11-31-

20w3 Particle size distribution downstream of 5 micron sock filter

Little Change in TSS

noted

29

After Cleaning the Water – Then What?

We must prevent frac extension by monitoring pressures and adjusting to

prevent injection over the frac gradient

Hall Plots – Fillage, damage, Frac Extension can be identified

Pressure Surveys – Calculate closure / Frac Extension Gradients

Frac data - ISIP, mini frac analysis – Provides a starting point

30

What is the Frac Gradient??

Simplistic Rock Mechanics

Closure Stress – The Pressure required to keep a frac open

Frac extension pressure – Closure Stress Plus Tensile Strength ( Petro?)

Simplified Closure Equation:

Pc = 1/3(OB – PP) +PP

Where OB ~ 1 PSI/ft

PP = Pore Pressure

Complexity –

1 - With an Injector you have

pressure gradients

2 – Injecting cold water will cool

the formation – thermal stresses

31

Does Completion Data Supply Useful Info?

Yes but don’t forget depletion changes the closure – See Closure Stress

Example 1 – Waskada 6-1-1-25W3 Exploration Well - Spearfish

– Assume undepleted. Pr ~ 9000 kPa

- TVD 904 m

- Average ISIP 5700 kPA, Est BHP 14740 kPa 16.3 kPa/m

- Quick Closure Gradient = 14.3 kPa/m

- Add Tensile Strength (est 1100 kPa) Frac Gradient = 15.35 kPa

- Note: The frac may be still growing at ISIP

Example 2 – Otter 8-1

- Original pressure ~15.5 Mpa, Pressure at conversion 1.5 Mpa

- At Orig - Assume 3000 kPa tensile – Frac Gradient = 16.3 kPa/m

- At Conversion – Frac gradient = 10.13 kPa

32

Water Filter System Detailed Schematic Avon Hills 8-34 Battery

Mixed Media filter 1000m3/d

Walnut Shell filter 400m3/d

IGF Filter 400m3/d Capacity

Bakken Source up to 1000m3/d

With 2ppm H2S

Injection Pumps

11-22-030-22W3

Trucked In Volumes

Avon Hills – Mixed salinity, 100m3/d

Dodsland – Mixed salinity, climbing over 400m3/d by end of 2015

Phase 1 ,2,3 Injectors

IGF Filter 400m3/d Capacity

Walnut Shell filter 400m3/d

Water Quality Targets; <10 ppm oil

< 10 ppm TSS

< 1 micron particle size

Gas floatation combined with

flocculants/coagulants now able

to remove 97% of solids and oil.

33

Conclusions

• High decline rates in HMSF plays is a critical

issue

• Waterflooding is becoming critically important

to sustain the industry

• Well spacing, frac design, water quality, and

pressure control are all critical to success QUESTIONS?