Jeff Saponja, President, TriAxon Oil

Enhancing Horizontal Well Production
Regulate Flow to Optimize Rod Pump Controllers
presented by…
TriAxon Oil Corp.
© 2015 TriAxon Oil Corp. All rights reserved.
1
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 / attention
© 2015 TriAxon Oil Corp. All rights reserved.
2/
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)
© 2015 TriAxon Oil Corp. All rights reserved.
3/
Background
Harmattan East Viking Unit
• Large light oil OOIP (~110 mmbbl, 37o
API), ~7,200 ftTVD depth, partially
waterflooded pool, RF < 12%
Edm onton
Calgary
Regina
• 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
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
© 2015 TriAxon Oil Corp. All rights reserved.
Solids consist of
frac sand and
produced fines
Expectations reflected in operating cost
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
© 2015 TriAxon Oil Corp. All rights reserved.
=
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
Symptoms of a root problem
Why sump the pump?
We cannot sump the pump in a horizontal well !!
• Maximize drawdown
• Gas separation
• Solids separation
Tubing
Spool
Wellhead
Tubing
Spool
Annulus Gas and back pressure to well caused by
surface production handling systems
Surface
9-5/8” Surface Casing
7” Intermediate Casing
2-7/8” Production Tubing
1” Sucker Rods
Drawdown
Drawdown
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.
Sucker Rod Pump
Sucker Rod
Pump Sumped
Fluid Level Below Reservoir
© 2015 TriAxon Oil Corp. All rights reserved.
Fluid Level Above Reservoir
Why maximize drawdown?
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
© 2015 TriAxon Oil Corp. All rights reserved.
7/
Root Cause: hz wellbore flow is inconsistent
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?
© 2015 TriAxon Oil Corp. All rights reserved.
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)
Short interruption from
fluid shot causes large
inconsistent flow surge
PRODUCTION ANNULUS GAS RATES
• Produced fluid rates rapidly fluctuating
over 100% of their mean value
• Interruptions greatly exacerbate the
situation
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
© 2015 TriAxon Oil Corp. All rights reserved.
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
© 2015 TriAxon Oil Corp. All rights reserved.
Discovery: Inconsistent flow related to solids
Inconsistent flow along a Hz wellbore promotes proppant flowback
and transports solids along wellbore that accumulate at heel
Solids are transported
in dunes along
horizontal due to wave
mechanics associated
with inconsistent flow
Solids dunes
in horizontal
caused by
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
© 2015 TriAxon Oil Corp. All rights reserved.
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
© 2015 TriAxon Oil Corp. All rights reserved.
Significant Findings: horizontal flow behaviour
Pressure drop is not material from hz
toe to heel at production rates
typically encountered as indicated by:
heel
toe
Normalized Chemical Frac Tracer Concentration, ppb
• Long term ProTechnics SpectraChem
frac stage tracer data
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
21
24
26
23
28
30
21
23
27
19
27
27
6.4%
7.3%
8.0%
7.0%
8.6%
9.2%
6.4%
7.0%
8.3%
5.8%
8.3%
8.3%
36.9
422.6
26.5
11.5
11.8
11.9
0.0
8.9
11.2
7.8
8.9
10.8
11.6
6.9
2.0
1.7
2.9
3.2
1.3
1.7
2.5
1.0
Time
0.0
4.0
73.4
43.8
35.2
40.9
2.4
20.9
25.3
24.4
24.2
25.4
15.3
18.1
18.5
1.1
5.0
6.4
4.3
4.8
5.9
1.4
0.0
2.7
64.8
51.9
54.2
28.6
2.3
27.1
32.3
27.2
31.8
33.9
17.6
16.9
17.2
0.5
1.2
1.6
2.3
2.5
4.5
1.7
0.0
0.0
22.8
26.4
28.7
48.3
0.5
5.7
9.6
6.1
6.3
5.4
6.7
3.5
2.9
1.4
3.6
2.5
1.4
1.7
1.7
1.6
0.0
0.0
29.5
29.6
39.3
13.4
3.2
22.3
28.6
24.1
26.8
24.5
32.9
18.3
14.3
0.2
3.0
2.0
4.6
6.4
5.5
1.1
16
11/10/12 11/10/12 11/10/12 11/10/12
32
46
31
42
13
11
10
9
7
6
5
4
2
1
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
36
36
39
72
25
37
32
34
29
73
46
64
46
55
50
73
18
43
41
34
32
34
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
0.0
82.0
21.1
42.1
0.0
3.9
12.2
10.6
11.3
11.4
11.1
14.6
14.6
2.4
0.0
80.4
52.1
51.6
25.4
34.7
10.3
8.4
10.6
11.1
15.8
12.9
13.0
0.8
0.0
11.5
14.9
17.6
1.7
3.4
4.5
2.4
3.3
3.1
2.8
2.6
2.4
2.4
0.0
26.9
22.6
22.6
2.1
6.4
6.9
5.4
7.1
6.5
5.5
5.5
4.9
0.8
0.0
8.1
16.2
34.4
0.6
6.8
11.4
8.2
10.2
7.8
5.7
9.9
9.3
0.6
Well #2
© 2015 TriAxon Oil Corp. All rights reserved.
0.0
15.9
8.0
19.0
0.0
1.8
3.6
2.8
3.4
4.1
4.1
5.8
7.0
0.7
0.0
3.3
8.3
32.4
0.0
7.7
13.8
8.3
11.7
11.8
10.4
42.2
31.8
2.2
0.0
2.0
83.7
23.7
0.0
1.9
37.9
21.0
27.5
21.5
16.5
14.3
14.4
2.4
0.0
0.0
50.3
61.6
51.7
29.8
0.0
26.8
44.4
30.7
32.9
16.8
12.4
11.9
27.5
5.2
8.6
8.5
6.3
6.8
4.7
1.6
0.0
0.0
36.6
48.8
50.2
14.4
4.5
29.3
41.5
33.5
39.0
18.6
13.8
14.4
24.9
3.9
9.8
6.0
5.5
7.6
4.5
1.9
0.0
0.0
68.3
73.2
59.5
43.9
1.1
33.8
44.9
28.5
31.8
30.2
27.3
26.1
28.0
4.1
14.1
12.2
7.4
5.5
3.8
1.8
0.0
0.0
47.2
47.5
38.3
34.4
0.0
19.1
15.6
10.7
6.9
14.5
13.1
11.5
11.1
14.9
11.6
11.1
2.1
2.2
4.7
0.7
1.4
0.4
21.2
13.7
12.1
8.7
0.0
13.4
11.0
10.0
8.7
10.2
10.7
9.7
14.5
4.9
5.4
4.6
1.3
1.3
1.7
0.6
0.0
0.0
0.0
0.0
0.0
0.0
0.0
3.1
3.5
4.4
8.9
8.6
11.0
9.6
15.7
9.1
9.5
6.4
5.3
6.2
5.9
1.7
Normalized Chemical Frac Tracer Concentration, ppb
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
1.8
97.4
29.0
32.5
0.1
2.2
2.6
2.3
3.3
3.3
2.6
1.4
1.3
1.1
0.0
0.0
8.6
22.0
49.3
23.9
0.0
19.3
44.2
55.3
42.8
29.6
23.3
15.1
14.8
0.3
8.0
9.8
6.2
5.9
3.1
3.7
31
46
7.0%
218.6
48.9
35.9
21.5
2.8
6.2
5.5
5.6
6.0
8.9
7.9
7.7
7.9
4.3
0.0
0.0
41.5
16.6
18.5
16.7
0.7
7.5
17.3
13.9
15.3
12.6
9.7
9.8
5.2
1.3
7.6
5.6
3.5
4.0
3.2
1.0
Well #1
Normalized Chemical Frac Tracer Concentration, ppb
18
0.0
0.0
110.8
30.9
0.3
0.8
40.3
26.2
39.1
35.1
32.1
30.7
29.5
2.8
0.0
0.0
95.0
4.8
0.0
0.0
13.6
17.9
13.2
11.9
8.4
6.5
7.3
0.4
0.0
0.0
0.0
0.0
0.0
0.0
0.0
84.1
34.6
28.6
20.7
19.6
17.8
2.5
150 to 200
100 to 150
• Pressures recorded at toe and heel
during multi-phase flow underbalanced
drilling operations
20
>200
31
9.5%
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
• Flow modelling
21
Key
18
0.0
0.0
0.0
0.0
0.0
0.0
0.0
38.2
26.3
29.7
22.8
21.6
21.3
3.2
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
231.0
1.1
1.3
1.2
2.1
1.2
0.7
0.5
66.5
4.2
5.8
8.2
3.1
2.6
1.6
0.0
0.6
4.5
8.9
8.9
2.1
2.9
2.2
0.0
0.0
20.0
4.5
5.4
26.4
2.1
2.0
0.0
0.0
18.1
16.1
12.0
9.9
5.1
3.9
0.0
0.0
13.3
3.1
9.2
24.0
1.8
1.4
0.0
0.0
24.1
9.8
8.9
7.6
6.0
3.6
0.0
0.0
22.6
4.4
19.1
13.6
8.0
4.2
0.0
0.0
4.3
7.4
17.9
28.7
7.0
3.3
0.0
0.0
3.3
13.2
14.0
45.6
4.9
3.4
0.0
0.0
0.0
29.4
20.5
15.2
15.5
6.7
Well #3
13
0.0
0.0
0.0
49.2
23.7
18.0
7.3
4.0
0.0
0.0
0.0
52.6
15.7
17.1
9.5
4.8
0.0
0.0
0.0
1.7
22.8
12.8
6.2
5.1
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
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
© 2015 TriAxon Oil Corp. All rights reserved.
Hypothesis: regulate flow
Regulate flow from the horizontal wellbore making it consistent
PRODUCTION ANNULUS GAS RATES
© 2015 TriAxon Oil Corp. All rights reserved.
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
© 2015 TriAxon Oil Corp. All rights reserved.
Breakthrough Innovation: HEAL System™
The horizontal “thinks” it’s a sump-ed vertical
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
© 2015 TriAxon Oil Corp. All rights reserved.
HEAL SystemTM
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)
© 2015 TriAxon Oil Corp. All rights reserved.
Maximized Drawdown with HEAL SystemTM
Bottomhole Pressure ~
250 kPa (36 psi) at
2300 mTVD (7500 feet)
© 2015 TriAxon Oil Corp. All rights reserved.
Normal practice
chemical batch
treatment for
paraffin control
19 /
HEAL SystemTM Results
Commercial 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
© 2015 TriAxon Oil Corp. All rights reserved.
Results Expectations
Innovation value add results
Drawdown Maximization (achieves pressure at hz depth 200 kPa or 30 psi)
Incremental
Value adds:
HEAL SystemTM
Install
NPV $1.2 million
Reserves 36%
Runtime Maximization (materially reduce operating costs and workover frequency)
Rod pump failures
due to solids
HEAL SystemTM
Install
Reduced
7 workovers
within 1 year
© 2015 TriAxon Oil Corp. All rights reserved.
Innovation value add results
Combined Increased Drawdown and Runtime Maximization
Pre-HEAL Install
sample
60
45
22
HEAL SystemTM
Install
30
20
18
40
16
14
30
12
10
20
8
6
10
Daily Producing Hours
Calendar Daily Avg Oil
4
2
0
41944
41945
41946
41947
41948
41949
41950
41951
41952
41953
41954
41955
41956
41957
41958
41959
41960
41961
41962
41963
41964
41965
41966
41967
41968
41969
41970
41971
41972
0
25
Hours On
Total Fluid (m3/d)
Average Total Fluid
Average Hours
20
Post-HEAL Install
15
35
24
22
30
5
0
20
18
25
16
14
20
12
15
10
8
10
6
4
5
2
0
Production
improved 30%
0
Hours On
Total Fluid (m3/d)
Average Total Fluid (m3/d)
Runtime
improved from
50% to 95%
© 2015 TriAxon Oil Corp. All rights reserved.
Average Hours
Daily Producing Hours
10
Production Rate (m3/d)
Production Rate (Oil: m3/d; Gas: e3m3/d)
40
50
Production Rate (m3/d)
Calendar Daily Avg Gas
35
24
Innovation value add results
Drawdown Maximization - Increased Frac Load Water Recovery
HEAL
SystemTM
Install
Improved
frac fluid
flowback
Frac load water
recovery increases
materially
Runtime Maximization and Increased Frac Load Water Recovery
Downtime due to
gas interference
and solids
© 2015 TriAxon Oil Corp. All rights reserved.
SystemTM
HEAL
Install
Frac load water
recovery increases
materially
Production
Value Adds:
+69% over
Aug-Dec ‘14
+22% over
Jun-Jul ’14
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:
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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
© 2015 TriAxon Oil Corp. All rights reserved.
CONTACT
403-536-0642
www.triaxonoilcorp.com
CONTACT
403-536-8311
[email protected]
www.pdnplus.com
© 2015 TriAxon Oil Corp. All rights reserved.