downhole flow conditioning to improve well …wbpc.ca/pub/documents/2017/wall - slug flow...

How Slug Flow Mitigation Can Simultaneously Increase Production and Improve Well Production Economics in the Williston Basin

2017 Williston Basin Petroleum Conference

May 3, 2017

© Production Plus Energy Services Inc., 2016

Multiple Patents Pending

Agenda 1. Challenges Producing Horizontal Wells

2. HEAL System Functionality

3. Case Histories

4. Development of the HEAL Slickline System

© Production Plus Energy Services Inc. 2016 | 3

Why Do Horizontal Wells Have Slug Flow?

Slug Flow Mechanisms: 1. Hydrodynamic Based – flow regime

(rates, GLR and pressure)

2. Terrain Based – well geometry (undulations and toe-up trajectory)

3. Operational Based – interruptions, stops/starts, pump on timer = bad plan, pump over-stroking practices

Reference: Artificial Lift Applications in Unconventional & Tight Reservoirs, R Choksi, Accutant, SPE DL Presentation


Toe-up • Large gas bubble forms at toe • Gas bubble eventually becomes unstable

and releases in violent manner • Large, extended gas flow periods

How a well is drilled impacts slug flow Terrain based slugging

Wellbore Undulations • Liquid traps compound slugging • Liquid traps do not create material pressure

drops, rather they exacerbate slugging • As wells get longer, impact more pronounced


Solution: Mitigate Slug Flow Flow conditioning prior to separator and pump


Slug Flow Mitigation: HEAL System Installs Long-term case histories in multiple basins

200 installs

30+

formations


HEAL

Nat

ural

Flo

w

HEAL

Sys

tem

+ E

SP

HEAL

Sys

tem

+ Ro

d P

ump

HEAL System™

Time

Prod

uctio

n R

ate

(bbl

/d)

3000+

HEA

L Sy

stem

+ E

SP

HEA

L Sy

stem

™ +

Rod

Pum

p

Nat

ural

Flo

w th

ru H

EAL

0

Reduce CAPEX and OPEX: Fewer, less expensive system transitions

Dep

th 3

Time

Prod

uctio

n R

ate

(bbl

/d)

0

ESP

3000+

Gas

Lift

Rod

Pum

p Dep

th 1

Dep

th 2

Dep

th 3

Conventional Strategy

Nat

ural

Flo

w

Nat

ural

Flo

w

ESP

Gas

Lift

Rod

Pum

p D

epth

1

Dep

th 2


1. Seal • Forces flow into SRS • Creates large solids sump

2. Sized Regulating String (SRS) • Variable internal diameter • Smooths flow • Reduces fluid density to lift build section of well

3. HEAL Vortex Separator • Separates solids • Separates gas • Avoids generation of foam

Mitigate slug flows with the HEAL SystemTM


Make Artificial Lift Systems “Think” Vertical Well

Separated gas

Separated oil / water / solids

Solids to sump

Fluid level

HEAL Vortex Separator

Sized Regulating String HEAL Seal

Conventional Artificial Lift

Conditioned flow Fluids turn the

corner

Large solids sump

Place traditional artificial lift systems in vertical

• Place moving parts (pump) in vertical for reliability

• Smaller lift equipment or more capacity out of existing equipment

Solids control • Control solids transport

mechanism in hz • Solids separator with large

sump for collection of solids (to protect pump)


Bot

tom

hole

Pre

ssur

e

Tubing ID

Bubble Flow Slug Flow Annular Transition Mist

Source: Purdue University http://bit.ly/1OxEjm3

Sized Regulating String and Flow Conditioning

http://bit.ly/1OxEjm3


HEAL System: How is Production Increased? • Improved separation

lowers fluid level above the pump

• Flow regime with lower fluid gradient below the pump

Conventional

With HEAL


Symptoms your well may benefit from the HEAL System™

High Total Well Capital Expenditure • Large artificial lift equipment due to production rate, depth and low efficiency • Multiple lift systems required after natural flow period • Complex directional profile to achieve production and geological objectives

High Operating Expenses • Excessive workover frequency due to poor reliability and downhole equipment failures • Excessive energy consumption due to pump depth and low pump efficiency • Excessive gas interference and poor runtimes

Production and Reserves Not Maximized • Inadequate drawdown due to lift system limitations (gas lift, “pump limited”) • Pump placement limiting ability to pump off well to very low bottomhole pressures • Persistent high annular fluid levels or pump inlet pressure


Case Study: Reduce Capital Investment Cardium, Alberta • HEAL System allowed PSN to be

raised (212mTVD) from the 60 degree tangent to KOP

• Surface unit savings of $21k to $29k (one or two sizes smaller)

• 250m less production tubing and rods ($10k)

• Same or better BHP and production as conventional pump depth

• Improved pump workover frequency and system wear

• No need to conventionally lower pump over time

Conventional PSN: • 1570m (1524mTVD) • 60 deg inclination • 640-168” Surface

Unit

HEAL PSN: • 1320m (1312mTVD) • 0 deg inclination • 456-144” Surface

Unit


Case Study: Reduce Operating Expense (Reliability) Viking, Alberta

• Ran pumps deep to maximize drawdown o multiple pump failures

• Ran pumps shallow for reliability o poor drawdown, rod

breaks from gas interference

• Pre-HEAL o 9 pump changes over

2 years costing $600k

• Post-HEAL o Zero changes in 2.5+

years


• Slug flow mitigation solves the root cause of erratic pump fillage and gas interference

• Mitigating slug flows improves both downhole separation and pump performance

• Increase in pump efficiency and a shallower pump placement reduces energy consumption up to 40%

Case Study: Reduce Operating Expense (Efficiency) Niobrara, DJ Basin


• 23 neighboring wells and 140 readings over seven months

• Slug flow mitigation improves downhole separation, HEAL system fillage is higher and more consistent

• Additional benefit of lowered BHP

• Less stress on rods by avoiding erratic pump fillage

• Stable fluid level allows for effective pump jack balancing

Case Study: Improve Production Performance (1/2) Wolfcamp, Permian


• Of the prior 23 wells included in the separator comparison, 10 were converted to HEAL systems

• Over 100% improvement in total fluid production rates

• Significant, as historical experience shows a drop in production when transitioning to conventional rod pumping from gas lift due to the difficulty in effective pumping.

Case Study: Improve Production Performance (2/2) Wolfcamp, Permian

HEA

L Sy

stem

Inst

alle

d


Case Study: Improve Production Performance Bakken, North Dakota

• Typical Bakken casing configuration results in high pump placement and high BHP’s (drawdown limited)

• 30% to 40% increase in production and reserves opportunity

• HEAL System highly suited for such casing configurations for maximizing drawdown

• > 9,200 existing well candidates identified

HEA

L Sy

stem

Inst

alle

d

Initial Flush Production


Case Study: Improve Production Performance Montney, Alberta

• Montney suffers major rod pumping challenges: deep, high GOR, some areas have very high initial rates and decline rates

• HEAL System installed in 25 wells with multiple operating companies

• Long term (>12 months) average result is +100% increase in production over previous trend

• Moving towards installing immediately after initial completion, full cycle


Case Study: Improve Production Performance Wolfcamp, Permian Basin

• Gas lift to Rod Pump transition, lower BHP.

• Wolfcamp Formation is challenged by depth, high total fluid rates, high watercuts and severe, high GOR, gas interference

• Installation in 12 Wolfcamp wells resulted in a sustained +33% increase in production

• Lower OPEX and total capital with rod pumping

HEA

L Sy

stem

Inst

alle

d


Production Increase • 12m3/d (72 bbl/day)

• ~$46,200/month incremental Revenue

• ($21.21/bbl netback from Q3 2016) • Flush production can be

significant • Extends economic cut-off

Case Study: Gas Lift to Rod Pump Transition Economics Montney, Alberta

Improved Runtime • Gas interference/locking avoided • Less relevant as gas lift has high

run time • ~$0/month

Lower CAPEX • If central gas lift infrastructure then

$108k savings over pump jack (SPE 18233)

• Likely have to convert to RP post gas lift, deferring cost (and less drawdown)

• Smaller pump jack

Lower OPEX • Reduced power from full pump cards

and shallower PSN • More HP required for Gas lift

compared to pump jack • ~$1,000/month savings (SPE 18233)

$All in $47,200/month (plus capital), payout ~ 2months


Case Study: Improve Production Performance Montney, Alberta


HEAL Slickline System: Offset Well Frac Hit Protection • Infill drilling and downspacing

causing more frac hits • Expensive problem based on

avoidance or remediation • Some operators remove all

downhole completions, including artificial lift systems to install isolation packers

• Is there a method to set a deep well barrier without a tubing move?

Reference: JPT, Oil And Gas Producers Find Frac Hits in Shale Wells a Major Challenge, April 2017


HEAL Slickline System: Offset Well Frac Hit Protection

SRS STRING (tapered ID)

HEAL SEAL

Rod Pump

HEAL SLICKLINE SEPARATOR c/w SEPARATOR PRONG (SRS flow discharged to annulus for gas and solids separation)

• Well is on production with rod pump and HEAL Slickline System

• Slickline HEAL Separator Prong in place

• Casing is open for separated gas

• HEAL System protects pump from gas and solids, as well as maximizes production drawdown

INSERT PUMP

Frac Hit Protection

Separated Gas

Oil / Water

Formation Fluids (Oil, Water, Gas)

HEAL SLICKLINE SEPARATOR c/w BLANKING PLUG / PRONG (horizontal wellbore is isolated from tubing above separator)

• When an offset well is fracced there is a risk of a frac communicating (frac hit) with the wellbore. Frac hit consequences can include severe artificial lift system damage, productivity loss due to wellbore filling with frac sand, and a well control event with excessive pressures being encountered at surface

• Rods and pump are pulled from well

• Slickline unit pulls HEAL Separator Prong and installs a standard X profile Blanking Plug/Prong in Slickline Separator

• With a deep barrier in the well, the frac hit risks and consequences are mitigated

• Post offset well frac, the procedure is reversed and well is placed back on production

SRS STRING (tapered ID)

HEAL SEAL

Separated Solids


Summary Mitigating Slug flow from the horizontal adds value

• Solids control • Efficiency as separators and pumps like smooth flow • Drawdown reliably maximized

HEAL Slickline System offers additional value of reduced CAPEX and OPEX:

• Inter-wellbore communication or frac-hit risk mitigation • Extension of natural flow period • Simpler and lower cost transition to artificial lift • Simpler and lower cost transitions between artificial lift systems


DISCLAIMER This presentation is for use by the HEAL System™ user (User) only. User has sole responsibility for the use of the HEAL System™ and any field operations and installation activities in relation thereto and neither Production Plus Energy Services Inc. nor any of its affiliates or representatives (collectively, Production Plus) shall have any liability to User under any circumstances in relation to any field operations of or installation activities conducted by User. Production Plus does not makes any representations or warranties express, implied, statutory or otherwise as to the HEAL System™ (including as to the merchantability or fitness for a particular purpose thereof) or as to the procedures contained in this guide. No certainty of results is assured by Production Plus and Production Plus makes no warranty concerning the accuracy or completeness of any data, the effectiveness of material used, recommendations given, or results of these procedures or technology. User's use of the HEAL System™ is subject to the terms and conditions of its master sales agreement with Production Plus Energy Services Inc.

TRADEMARK HEAL System is a trademark of Production Plus Energy Services Inc.

CONTACT 403-536-8311 [email protected]

www.pdnplus.com

ADDRESS 2500, 639 - 5 Avenue SW

Calgary, AB | T2P 0M9

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