presented by… triaxon oil corp. - lbcg · © 2015 triaxon oil corp. all rights reserved....

© 2015 TriAxon Oil Corp. All rights reserved.

Enhancing Horizontal Well ProductionRegulate Flow to Optimize Rod Pump Controllers

1

presented by…

TriAxon Oil Corp.


Challenges with horizontal well artificial lift

Artificial lifting of horizontal wells is challenged by:

• Excessive downtime and operator attention, as downhole pump gas interference reduces runtime and pump efficiencies

• Excessive workovers repairing damaged equipment from gas interference and solids

• Excessive capital costs with multiple artificial lift system types run at various phases to handle rapid declines

• Downhole pumps lose efficiency and reliability when positioned in the well’s bend section or horizontal section

• Rod Pump Controllers (RPC’s) often being switched to manual mode

Operating cost value drivers for an RPC:

• Avoid gas interference and gas locking of the pump

• Avoid fluid pound and associated pump / rod / jack damage

• Reduce operating energy costs

• Avoid stuffing box failures (leak / spill management)

• Maximize production by maximizing drawdown

• Reduce operator visits / attention2 /


Challenges with horizontal well artificial lift

Then why are RPC’s often run in manual mode when their promise and intent are…

• Power savings (20% - 25%)

• Maintenance cost reductions (25%)

• Production increase (1% – 4%)

RPC’s for Horizontal Wells

• RPC’s work great for vertical wells or when a pump is placed in the vertical section

• Pumps placed in bend or in hz challenge the RPC due to rod friction

• It is sub optimal to place the pump in the vertical section of a horizontal well, as drawdown (thus production rate and reserves) will be compromised

• RPC’s can cause intentional interruptions to production, which has turned out to be directly related to increased operating costs and excessive workovers

• Until the root cause of the challenges with artificially lifting hz wells was discovered, a solution could not be effectively resolved (i.e., RPC’s were only battling the symptoms of the root cause)

3 /


Hz Well Production Challenges

• Poor runtime – pump gas interference, solids

• Excessive operating costs – frequent workovers and operator attention

• Intelligent RPC’s run in manual mode

• Rate compromised – drawdown not maximized with pumps landed at 20o-40o

Background

Harmattan East Viking Unit

• Large light oil OOIP (~110 mmbbl, 37o

API), ~7,200 ftTVD depth, partially waterflooded pool, RF < 12%

• Sandstone (Viking), perm 3-60 mD, porosity 10-15%

• Low reservoir pressure ~1,500 psi (half of a water gradient)

• Initially developed with vt wells (mid 80’s); hz multi-stage fracced well development initiated in 2012

Calgary

Edmonton

Regina

Solids consist of

frac sand and

produced fines


Expectations reflected in operating cost

Hz Well Artificial

Lift Expectations

• Pump off horizontal

• 100% runtime

• High reliability (3+yrs)

• Handle variable flow

• High turn down ratio

• Solids tolerance

• Intelligent RPC reduces operator visits

Operating Cost = Production Costs / Production Volume

Artificial Lift

Production Costs

• Operator attention requirements

• Lift expenses (power, chemicals)

• Reliability (frequency of workovers)

• Efficiency (pump, rod load)

• others

Production Volume

• Drawdown

• Runtime per month


We cannot sump the pump in a horizontal well !!

Drawdown

Tubing

Spool

Sucker Rod Pump Sumped

Fluid Level Below Reservoir

Symptoms of a root problem

Drawdown

Tubing

Spool

9-5/8” Surface Casing

7” Intermediate Casing

2-7/8” Production Tubing

1” Sucker Rods

Wellhead

Sucker Rod Pump

Surface

Fluid Level Above Reservoir

Annulus Gas and back pressure to well caused by surface production handling systems

Any accumulation of liquid (fluid level) above the reservoir depth imposes a hydrostatic pressure. This hydrostatic pressure reduces the wellbore draw down pressure and therefore limits production and reserves recovery.

Why sump the pump?• Maximize drawdown

• Gas separation

• Solids separation


Why maximize drawdown?

7 /

Gas expansion in an oil reservoir is exponential below 300 psi• Maximizing volumetric gas expansion within reservoir maximizes production rate

and reserves

• Extends the economic production limit


Inconsistent “messy” flow

from the horizontal as

indicated by production

annulus gas rate

Inconsistent flow surges

occurring every 45 minutes

• How can any

downhole pump,

downhole separator

or RPC manage this?

Root Cause: hz wellbore flow is inconsistent


Consequences of inconsistent flow

Multiphase fluid flows become highly variable and unpredictable

• Recorded 10 minutes of straight gas, 10minutes of straight liquid and then 10 minutes of no flow at all (causes gas interference)

• Produced fluid rates rapidly fluctuating over 100% of their mean value

• Interruptions greatly exacerbate the situation

PRODUCTION ANNULUS GAS RATES

Fluid level in production annulus is not constant (fluctuates up and down)

• Rod loads continuously changing

• RPC becomes confused (shuts down, can’t respond, operator switches to manual mode)

• Operator shooting a single fluid level is subject to significant interpretation error

• Fluid column below fluid level has variable fluid densities

Short interruption from

fluid shot causes large

inconsistent flow surge


Consequences of existing RPC practices

Sizing of the pumping system to have surplus capacity and planning for frequent shut downs or interruptions results in:

• Greatly exacerbating the inconsistent flow situation (massive surges from hz)

• Stopping / starting accelerates mechanical wear

• Accelerates the propagation of solids along hz

• Encourages proppant flowback from the fracs

• Increases risk of gas interference, gas locking of pump and damaging fluid pound

• Average drawdown is higher, so not maximizing production and reserves

• Surplus capacity (over sizing pump and jack) reduces turn down ratio, which leads to more frequent shut downs

• Increases operator visits and attention


Inconsistent flow along a Hz wellbore promotes proppant flowback and transports solids along wellbore that accumulate at heel

Solids dunes

in horizontal

caused by

inconsistent

flow

Solids are transported

in dunes along

horizontal due to wave

mechanics associated

with inconsistent flow

Transported solids

accumulate at the heel

of the horizontal well,

where pumps are

commonly positioned –

high risk of solids

damage to pumps

Source: www.evcam.com

Discovery: Inconsistent flow related to solids

http://www.evcam.com/


Significant Findings: wellbore trajectory

Wellbore trajectory directly affects the severity of inconsistent flow

• The more a horizontal wellbore trajectory undulates the greater the severity of inconsistent flow

• A “toe-up” trajectory has more severe inconsistent flow

Wellbore trajectory

undulations


Significant Findings: horizontal flow behaviour

Pressure drop is not material from hz toe to heel at production rates typically encountered as indicated by:

• Long term ProTechnics SpectraChem frac stage tracer data

• Flow modelling

• Pressures recorded at toe and heel during multi-phase flow underbalanced drilling operations

13

18 17 16 15 14 13 11 9 8 7 6 2 1

1/6/12 1/6/12 1/6/12 1/6/12 1/6/12 1/6/12 1/6/12 1/6/12 1/6/12 1/6/12 1/6/12 1/5/12 1/2/12

33 27 27 27 29 29 29 29 29 26 27 33 34

31 21 24 26 23 28 30 21 23 27 19 27 27

9.5% 6.4% 7.3% 8.0% 7.0% 8.6% 9.2% 6.4% 7.0% 8.3% 5.8% 8.3% 8.3%

CFT 2500 CFT 2400 CFT 1200 CFT 2200 CFT 2100 CFT 2000 CFT 1900 CFT 1700 CFT 1300 CFT 1500 CFT 1400 CFT 1100 CFT 1000

36.9 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 1.4 0.0

422.6 4.0 2.7 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.4 0.0

26.5 73.4 64.8 22.8 29.5 41.5 8.6 50.3 36.6 68.3 47.2 21.2 0.0

11.5 43.8 51.9 26.4 29.6 16.6 22.0 61.6 48.8 73.2 47.5 13.7 0.0

11.8 35.2 54.2 28.7 39.3 18.5 49.3 51.7 50.2 59.5 38.3 12.1 0.0

11.9 40.9 28.6 48.3 13.4 16.7 23.9 29.8 14.4 43.9 34.4 8.7 0.0

0.0 2.4 2.3 0.5 3.2 0.7 0.0 0.0 4.5 1.1 0.0 0.0 0.0

8.9 20.9 27.1 5.7 22.3 7.5 19.3 26.8 29.3 33.8 19.1 13.4 3.1

11.2 25.3 32.3 9.6 28.6 17.3 44.2 44.4 41.5 44.9 15.6 11.0 3.5

7.8 24.4 27.2 6.1 24.1 13.9 55.3 30.7 33.5 28.5 10.7 10.0 4.4

8.9 24.2 31.8 6.3 26.8 15.3 42.8 32.9 39.0 31.8 6.9 8.7 8.9

10.8 25.4 33.9 5.4 24.5 12.6 29.6 16.8 18.6 30.2 14.5 10.2 8.6

11.6 15.3 17.6 6.7 32.9 9.7 23.3 12.4 13.8 27.3 13.1 10.7 11.0

6.9 18.1 16.9 3.5 18.3 9.8 15.1 11.9 14.4 26.1 11.5 9.7 9.6

2.0 18.5 17.2 2.9 14.3 5.2 14.8 27.5 24.9 28.0 11.1 14.5 15.7

1.7 1.1 0.5 1.4 0.2 1.3 0.3 5.2 3.9 4.1 14.9 4.9 9.1

2.9 5.0 1.2 3.6 3.0 7.6 8.0 8.6 9.8 14.1 11.6 5.4 9.5

3.2 6.4 1.6 2.5 2.0 5.6 9.8 8.5 6.0 12.2 11.1 4.6 6.4

1.3 4.3 2.3 1.4 4.6 3.5 6.2 6.3 5.5 7.4 2.1 1.3 5.3

1.7 4.8 2.5 1.7 6.4 4.0 5.9 6.8 7.6 5.5 2.2 1.3 6.2

2.5 5.9 4.5 1.7 5.5 3.2 3.1 4.7 4.5 3.8 4.7 1.7 5.9

1.0 1.4 1.7 1.6 1.1 1.0 3.7 1.6 1.9 1.8 0.7 0.6 1.7

Normalized Chemical Frac Tracer Concentration, ppb

21 20 18 16 13 11 10 9 7 6 5 4 2 1

11/10/12 11/10/12 11/10/12 11/10/12 11/9/12 11/9/12 11/9/12 11/8/12 11/8/12 11/8/12 11/8/12 11/8/12 11/8/12 11/8/12

32 46 31 42 36 36 39 72 25 37 32 34 29 31

46 73 46 64 46 55 50 73 18 43 41 34 32 34

7.0% 11.1% 7.0% 9.8% 7.0% 8.4% 7.7% 11.1% 2.8% 6.6% 6.3% 5.2% 4.9% 5.2%

CFT 2100 CFT 2400 CFT 2200 CFT 2500 CFT 2000 CFT 1900 CFT 1700 CFT 1600 CFT 1500 CFT 1400 CFT 1300 CFT 1200 CFT 1100 CFT 1000

218.6 1.8 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

48.9 97.4 82.0 80.4 11.5 26.9 8.1 15.9 3.3 2.0 0.0 0.0 0.0 0.0

35.9 29.0 21.1 52.1 14.9 22.6 16.2 8.0 8.3 83.7 110.8 95.0 0.0 0.0

21.5 32.5 42.1 51.6 17.6 22.6 34.4 19.0 32.4 23.7 30.9 4.8 0.0 0.0

2.8 0.1 0.0 25.4 1.7 2.1 0.6 0.0 0.0 0.0 0.3 0.0 0.0 0.0

6.2 2.2 3.9 34.7 3.4 6.4 6.8 1.8 7.7 1.9 0.8 0.0 0.0 0.0

5.5 2.6 12.2 10.3 4.5 6.9 11.4 3.6 13.8 37.9 40.3 13.6 0.0 0.0

5.6 2.3 10.6 8.4 2.4 5.4 8.2 2.8 8.3 21.0 26.2 17.9 84.1 38.2

6.0 3.3 11.3 10.6 3.3 7.1 10.2 3.4 11.7 27.5 39.1 13.2 34.6 26.3

8.9 3.3 11.4 11.1 3.1 6.5 7.8 4.1 11.8 21.5 35.1 11.9 28.6 29.7

7.9 2.6 11.1 15.8 2.8 5.5 5.7 4.1 10.4 16.5 32.1 8.4 20.7 22.8

7.7 1.4 14.6 12.9 2.6 5.5 9.9 5.8 42.2 14.3 30.7 6.5 19.6 21.6

7.9 1.3 14.6 13.0 2.4 4.9 9.3 7.0 31.8 14.4 29.5 7.3 17.8 21.3

4.3 1.1 2.4 0.8 2.4 0.8 0.6 0.7 2.2 2.4 2.8 0.4 2.5 3.2


21 20 17 14 12 11 10 8 7 6 5 4 3 1

4/3/12 4/3/12 4/3/12 4/3/12 4/2/12 4/2/12 4/2/12 4/2/12 4/2/12 4/2/12 4/2/12 4/2/12 4/2/12 4/2/12

39 39 36 32 32 32 32 35 33 33 34 35 30 23

68 50 50 50 50 50 50 45 45 45 45 45 45 34

10.1% 7.4% 7.4% 7.4% 7.4% 7.4% 7.4% 6.7% 6.7% 6.7% 6.7% 6.7% 6.7% 5.1%

CFT 1600 CFT 2500 CFT 2400 CFT 2200 CFT 2100 CFT 2000 CFT 1900 CFT 1700 CFT 1500 CFT 1400 CFT 1300 CFT 1200 CFT 1100 CFT 1000

41.9 0.5 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

231.0 66.5 0.6 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

1.1 4.2 4.5 20.0 18.1 13.3 24.1 22.6 4.3 3.3 0.0 0.0 0.0 0.0

1.3 5.8 8.9 4.5 16.1 3.1 9.8 4.4 7.4 13.2 29.4 49.2 52.6 1.7

1.2 8.2 8.9 5.4 12.0 9.2 8.9 19.1 17.9 14.0 20.5 23.7 15.7 22.8

2.1 3.1 2.1 26.4 9.9 24.0 7.6 13.6 28.7 45.6 15.2 18.0 17.1 12.8

1.2 2.6 2.9 2.1 5.1 1.8 6.0 8.0 7.0 4.9 15.5 7.3 9.5 6.2

0.7 1.6 2.2 2.0 3.9 1.4 3.6 4.2 3.3 3.4 6.7 4.0 4.8 5.1


Key

>200

150 to 200

100 to 150

70 to 100

50 to 70

35 to 50

25 to 35

17 to 25

12 to 17

8 to 12

5 to 8

3 to 5

2 to 3

1 to 2

0.05 to 1

Time

heel toe

Well #1

Well #2 Well #3


Significant Findings: operational risk reduction

Placement of tubulars/equipment out in horizontal adds unnecessary risk

• Identified more risks (stuck in hole, loss of wellbore access, costly maintenance) than benefits

No moving parts in horizontal or bend section offers reliability and runtime

• Moving parts more reliable at vertical inclinations

• Moving parts more reliable under consistent flow conditions

Traditional methods for controlling solids have not provided a long term reliable solution

• Sand screens plugged forcing costly workovers

• Poor-boy and packer style gas anchors have limited solids tolerance

• Any packers or sealing element placed shallower than the Boycott angle (65o inc) resulting in stuck downhole equipment (risky and costly workovers)

A continuous, 24/7 uninterrupted operation is best practice


Regulate flow from the horizontal wellbore making it consistent

Hypothesis: regulate flow

PRODUCTION ANNULUS GAS RATES


Two Key Questions

1. How can we regulate flow to make it consistent, but with minimal pressure drops?

• Downhole chokes not effective (need 500 psi or more)

• Any increase in pressure drop will limit drawdown

• Any abrupt pressure drops cause paraffin and scale deposition

• Need to be solids tolerant, erosion resistant and highly reliable for the long term (life of the well)

2. Downhole pumps work optimally and reliably in the vertical section, so how to get produced fluids to the vertical section?

• Industry paradigm


HEAL SystemTM

Complement and protect existing artificial lift systems and RPC’s

• Protect the pump by delivering it smooth and consistent de-gassed and de-solids liquid

• Position existing artificial lift systems in the vertical section where they are most efficient, reliable and cost effective in the vertical section

Regulate flow from hz prior to the pump using underbalanced drilling methods

• Multiphase flow conditioning methods “borrowed” from UBD drill string connection practices

• Flow not choked or restricted, but instead “conditioned” to suppress inconsistent flows at minimal pressure drop (20 – 30 psi)

• No moving parts; low complexity and high reliability

• Control of solids achieved by suppressing inconsistent flow mechanical wave action in hz

Breakthrough Innovation: HEAL System™ The horizontal “thinks” it’s a sump-ed vertical


A low density fluid gradient below pump achieved by using gas lift principles

• Engineered cross sectional area in a Sized Regulating String (SRS) conditions flow into a specific flow regime that has a very low fluid gradient (0.04 psi/ft) and makes inconsistent flows consistent

• The relatively short SRS around bend provides broad operating envelope that can reliably handle a wide range of variable flow and production declines (high turn down ratio)

• Increases and/or provides a more controllable drawdown over traditional artificial lift for maximizing production rate and reserves

• Gas re-injection not required to achieve consistent regulated flow and to maximize drawdown (> 20,000 scf/day required)

Breakthrough Innovation: HEAL System™ The horizontal “thinks” it’s a sump-ed vertical


Maximized Drawdown with HEAL SystemTM

19 /

Bottomhole Pressure ~

250 kPa (36 psi) at

2300 mTVD (7500 feet)

Normal practice

chemical batch

treatment for

paraffin control


HEAL SystemTM Results

Results ExpectationsCommercial Results

• Low cost and operational risk addition to a completion

• Reduced GHG emissions when pump is positioned shallower (approx 40% less hp or 50 tonnes CO2e/yr)

• Designed for life of well; adds value from day 1

• Capital efficient production adds $5000 -$10,000 per boe/day

• Over 60 installs to date in 15 different reservoir horizons, including the US


Innovation value add results

Drawdown Maximization (achieves pressure at hz depth 200 kPa or 30 psi)

Runtime Maximization (materially reduce operating costs and workover frequency)

Incremental

Value adds:

NPV $1.2 million

Reserves 36%

Rod pump failures

due to solids

Reduced

7 workovers

within 1 year

HEAL SystemTM

Install

HEAL SystemTM

Install


0

2

4

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8

10

12

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22

24

0

5

10

15

20

25

30

35

Dai

ly P

rod

uci

ng

Ho

urs

Pro

du

ctio

n R

ate

(m3

/d)

Post-HEAL Install

Hours On Total Fluid (m3/d) Average Total Fluid (m3/d) Average Hours


Combined Increased Drawdown and Runtime Maximization

Runtime

improved from

50% to 95%

0

5

10

15

20

25

30

35

40

45

Pro

du

ctio

n R

ate

(O

il: m

3/d

; Gas

: e3

m3

/d)

sample

Calendar Daily Avg Gas

Calendar Daily Avg Oil

HEAL SystemTM

Install

Production

improved 30%

0

2

4

6

8

10

12

14

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18

20

22

24

0

10

20

30

40

50

60

41

94

4

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94

5

41

94

6

41

94

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41

94

8

41

94

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41

95

0

41

95

1

41

95

2

41

95

3

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1

41

97

2

Dai

ly P

rod

uci

ng

Ho

urs

Pro

du

ctio

n R

ate

(m3

/d)

Pre-HEAL Install

Hours On Total Fluid (m3/d) Average Total Fluid Average Hours



Runtime Maximization and Increased Frac Load Water Recovery

Drawdown Maximization - Increased Frac Load Water Recovery

Improved

frac fluid

flowback

Downtime due to

gas interference

and solids

HEAL SystemTM

Install

Production

Value Adds:

+69% over

Aug-Dec ‘14

+22% over

Jun-Jul ’14

HEAL

SystemTM

Install

Frac load water

recovery increases

materially

Frac load water

recovery increases

materially


Enhancing Horizontal Well Production Summary

Excessive operating cost and sub optimal RPC performance is a direct result of inconsistent “messy” flow from a horizontal wellbore

• RPC’s challenged to handle such chaotic conditions

• Gas interference leads to poor runtime

• Inconsistent flow propagates solids which accumulate in heel section

• Excessive downhole pump failures and workovers (rod wear, etc.)

• Under-booked reserves (well not fully drawn-down and reduced well economic life)

Regulated consistent flow from a horizontal wellbore prior to a downhole pump offers:

• A happy place for RPC’s

• Lower operating costs

• Enhanced artificial lift system flexibility and utility, at a lower capital cost.

• Resolution to runtime challenges related to gas interference

• Resolution to excessive workovers due to solids

• Increased drawdown to maximize production rate and reserves


CONTACT

403-536-0642

www.triaxonoilcorp.com

CONTACT

403-536-8311

[email protected]

www.pdnplus.com

presented by… triaxon oil corp. - lbcg · © 2015 triaxon oil corp. all rights reserved....

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