SPE 156189

ESP Retrievable Technology: A Solution to Enhance ESP Production While Minimizing Costs W. E. Szemat Vielma, SPE, SPT Group Norway AS, D. Drablier, SPE, ZEiTECS Inc. and M. L. Petry, SPE, Weatherford International.

Copyright 2012, Society of Petroleum Engineers This paper was prepared for presentation at the SPE International Production and Operations Conference and Exhibition held in Doha Qatar, 1416 May 2012. This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of SPE copyright.

Abstract The easy oil production is gone and current field developments require new approaches to produce oil and gas reserves in the

most effective, economic and safe ways. Around the world, more than half of the wells are assisted by an Artificial Lift (AL)

system. The use of these AL methods opens a range of opportunities to produce from low pressure reservoirs, low GOR, high

water cuts and many others constrains that operation & production engineers are facing nowadays. Electro Submersible Pumps

(ESPs) are widely used around the world as one of the most common solution for the current field development conditions.

However, ESPs represents a challenge itself in terms of production management, intervention cost and run life cycle.

Eventually, all ESPs will fail and the need of a workover will be present repeated times during the well life; and many causes

of failure are beyond the control of either manufacturer or operator.

To solve this issue, several types of ESPs deployment systems were designed and are currently in use around the globe (e.g.:

standard tubing deployed, thru tubing conveyed, CTU deployed), but each one of them has its own limitations.

In order to enhance ESPs installation conditions, capabilities and run life management, a new approach resulted on the design

of an ESP Retrievable system that will complement current major ESP providers equipment portfolio. This technology gives

the operator the opportunity to retrieve and rerun the ESP without a rig intervention by only using WL, sucker rods or CTU

equipment.

The technology can be used either onshore or offshore to manage and optimize oil production by taking aside the rig need to

change the ESP. This improves the oil recovery, minimizes environmental impact and increases the field safety management

while reducing the overall well cost.

This paper will explore the technology design, capability and constrain, cost analysis and will conclude with installation

experiences and results.

Introduction The Artificial Lift engineers are becoming more important nowadays than ever and it is not by chance that all major E&P

companies are investing and carefully looking among themselves to review the results of the several R&D projects related to

ESP wells.

An important fact to be considered is that ESPs are expected to perform in increasingly challenging applications and

environments. Mature fields and non standard reservoir conditions (e.g.: heavy oil reservoirs) are requiring more than ever

technology and investments to keep as long as possible the production profiles and improve the reservoirs recovery factors.

Currently, major ESP manufacturers innovations and design improvements focus mainly on increasing run life, expanding

range and diversity of application and advancing monitoring technology. While some smaller companies focused in the past

2 SPE 156189

years in the development of a technology that allows retrieving the ESP failed system from the well without the need of a

workover.

The ability of this retrievable system to expedite pump changes on WL, CTU or sucker rods, presents to all the E&P

companies the opportunity to maintain production and significantly reduce the disruption and cost associated with ESP

management.

Robust retrievable system design Considering the current industry needs, a robust design was developed, included different sizes to match the majority of the

wells in the world. At the same time, the system is flexible enough to be run in already existing wells or new (to be) drilled

wells.

Three different sizes are currently available to run and retrieve the ESPs with the completion string: 7, 5 and 4 as

shown on table I, allowing a wide open production range up to ESP maximum flow rate. One of the main benefits of this

system is that can be run with any ESP available in the market, no matter who the provider might be as it was designed to be

considered as an extra equipment to the standard ESP and completion tools, allowing enough flexibility to the E&P companies

for the installation. The modifications required to the standard ESP motor are very simple and can be done in a field service

center where the ESP equipment is generally prepared before shipping to the location.

This Rigless ESP retrievable system has two (2) main parts: the permanent and the retrievable components. The permanent

components section is composed of two (2) main pieces: the docking station, and the Landing nipple (figure I), while the

retrievable system is composed of three (3) main pieces: the motor connectors with the three wet mate connectors, the

expansion joint and the sealing assembly (figure II).

The docking station main function is to self align the two sets of wet mate connectors and at the same time carry the weight of

the ESP assembly and control the reactive torque when starting and/or stopping the ESP. Great care has been taken to shelter

the wet mate connectors from any kind of mechanical stress / loads. The male wet mate connectors in the docking station are

the simplest and most rugged part of the wet mating system; they are expected to last much longer than the female side of the

wet mate connectors. The female connectors are an integral part of the motor connector and will be retrieved and changed

every time the ESP is pulled. They can be redressed and re-used.

The sealing assembly will land into the landing nipple and will create a seal between the intake and discharge of the ESP. The

integrity of this seal can be tested up to 3000 psi when the new ESP is landed.

When landed in the production tubing the ESP system has two fixed points the docking station and the landing nipple, an

expansion is required above the ESP discharge head to allow some tolerance in the space out and also to allow differential

thermal expansion and contraction of the ESP string when operating.

Design with a non standard approach

Completion string for optimum well control during Rigless ESP change out.

Safety is always a major concern to all E&P companies around the world. Due to this, one of the first questions asked in the

presentation of this technology is how to keep the barriers policy after the installation of the retrievable system and there are as

many safety policies as they are oil companies.

One example of the different possibilities for the installation is described as follows (figure III), showing one (1) mechanical

barriers plus one the standard hydraulic barrier (hydrostatic column) and full access (circulation capable) below the ESP at any

moment for well control.

As standard, the mechanical barrier is the TR-SCSSV. However, because this cannot be installed on the top of the completion,

below the tubing hanger as any standard completion design, the selected valve is to be placed below the retrievable system

itself and because of the ESP setting depth, in some cases would be mandatory to have a deep set TR-SCSSV. Because of all

the mentioned conditions, the safety valve is preferably to be a fail-safe type and redundancy class 2 (two CL: principal and

back-up, allowing maneuvering the valve in the case of failure of the main CL). A secondary objective of this valve would be

to protect the docking station from production fluids after the ESP is retrieved to surface, minimizing the possibility of failure

of the wet connectors due to sediments deposition. In addition, the fact that the safety valve is placed below the ESP docking

station allows it to be designed in a smaller size than the tubing above the ESP, thus ensuring to keep its cost as low as in any

other conventional installation.

SPE 156189 3

A hydraulic controlled circulation valve is commonly located one joint above the TR-SCSSV allowing full access to

circulation operations for well control or well conditioning after re-running the ESP and setting in the docking station.

In the top of the completion, an oversized landing nipple can be placed in the case of future interventions requires the setting

of a WL retrievable safety vale. This will increase the safety features of this completion design for future rigless interventions

without compromising the integrity of the well itself and also to shut down mechanically the well in the case of temporary

abandon.

Considering all the CLs that will be permanently allocated in the exterior of the completion string, special clamp design (fit for

purpose) has to be considered. The use of joint clamps (Lassalle type) and middle joint clamps helps minimizing the

possibility of damaging any of the CLs while RIH the completion and landing the tubing hanger.

The following items to be modified or ordered with the fit for purpose philosophy are the TH, bonnet & WH. All these items

must allocate the CLs considered on the completion design (in this particular case, four [4] different passages: two [2] for the

TR-SCSSV, one [1] for the circulation valve and the last one [1] for the ESP cable [flat type cable is an advantage]).

Many other completion tools can be used with this retrievable equipment (e.g.: DHPG, On-Off tools) depending on the

specific needs and well conditions where this system will be installed. Some of these are shown on the figure V, VI, VII and

VIII.

The ultimate well control completion can be seen on figure IV It will provide two mechanical barriers that can be tested

downhole and one hydraulic barrier with kill fluid in the production tubing and the annulus.

Well architecture and conditions

From the well point of view, some aspects have to be considered before moving forward with the installation. The production

rates to be lifted by the ESP will determine the ESP model and size (OD) and therefore, the retrievable system series (as per

details shown on table I). As a rule of thumb for all factors such as gas, sand, corrosion look at past experience in the proposed

well is ESP have been used successfully, then a SHUTTLE could be used , size permitting of course.

The 700 series is to be installed in a 9 5/8 casing using flush joint 7 production tubing or in a 10 casing with conventional

couplings. In the other hand, the 550 series is to be installed in a 7 5/8 or the 9 5/8 casing with regular completion tools and

last but not less important or useful, the 450 series can be installed on any well where the ESP setting depth is inside the 7

casing or liner.

Well shape is not a key player on the well selection but it is important to be considered on the planned time to RIH the

permanent completion string as the major complexity of the well type, the slower will be the RIH of the string to avoid

damages on the lines and cable, ensuring the perfect functionality of the equipment once finally installed. The hole angle at

pump deployment depth must be taken into account when deciding the running system that will be used due to limitations

inherent to these systems (e.g. WL cant be used for hole angles higher than 60deg but this issue can be avoid with the

combined use of a tractor system).

Historically, the cable, MLE and pothead represent a substantial number of all the ESP failures. This system eliminates the

MLE and the pothead. It is also strongly recommended to use a deep set packer in order to isolate the annulus between the

production tubing and the casing from the produced well fluid. This will reduce the expose of the ESP cable to the well fluid

and to gas, thus extending the useful life of the ESP cable.

Technology capabilities, constraints and other applications Clearly, the main objective of this technology is to avoid the need of a rig to retrieve the failed or sub/over optimal designed

ESP. It is a general engineering design axiom that all the ESPs will eventually fail and consequently will have to be retrieved

from the wells in order to keep them open to production, resulting on an increase of the OPEX of the well during productive

life.

Although well architecture is not of specific concern to the system, due to the restricted diameter inside the tubing in

comparison to the ID of the casing which is the reference for a conventional ESP installation pump sizes and consequently

flow rates achievable in each application of the retrievable ESP may be lower than those of a regular ESP in the same well.

Also, annular space between tubing and casing must be carefully considered during design to prevent issues during RIH,

operation or POOH of the system. Due to the oversized tubing the annulus tends to be very tight for accommodating ESP

cable, control lines and cross-coupling protectors.

4 SPE 156189

Once the above constraints are addressed, the system can be run in the well without major operational concerns and will then

offer great flexibility for quick pump changes. One highly positive aspect to be considered by production engineers focused on

optimization of artificial lift systems is the possibility of replacing at a very low cost a pump that is running outside of its

optimum operating flow rate or pressure ranges by another one better suited for the application. In conventional ESP

applications the cost for replacing the existing pump by an optimized design may in some cases prove to be non-economic

over the life of the well.

Other consideration:

New wells, free flowing for a few months, the permanent part of the system can be installed when the drilling rig is still on location. The retrievable part with the ESP will be run in hole only when needed.

Well clean-up. Many ESP are designed to be able to off load the kill fluid from a well, requiring more HP and more stages to be able to light that heavy fluid, then when the well is flowing a lighter crude, the ESP is too big and has to

been slowed down with a VSD, very often working outside of its range of best efficiency.

Dual ESP application, are very popular in high intervention cost offshore wells. They tend to work very well but sometimes, when the second ESP is required, it may not start or the reservoir conditions may have changed so much

that the second ESP in the well is not able to produce as much as possible. The SHUTTLE technology illustrated on

figures VI, VII and VIII would allow the E&P companies to run the second ESP when needed making sure it starts

and is sized as per the latest reservoir data. Another benefit is the cash flow (CAPEX/OPEX) as the second pump can

be purchased only when and as needed.

An additional possibility that the technology offers is the combination of a PCP to the downhole electric motor. This means

widening the application envelope for the system to wells producing sandy and/or viscous fluids, which normally are

challenging for centrifugal pumps.

A matter of numbers: cost analysis The higher cost to be considered on the OPEX of the well is usually left aside of the intervention AFE as they are not directly

related to the ESP replacement operations but will impact the well cost in the finance books of the company. This cost is the

non-productive time or deferred production of the well while waiting the intervention and in many cases this can go from a

couple of weeks to several months.

By using the retrievable system, the deferred production is reduced from weeks to hours, allowing flexibility to the monitoring

& intervention team and opening a window of possibilities to all the E&P companies that have small producer wells that arent

to be considered economical with the standard ESP intervention costs due in time.

Assuming as example the previously described completion design, the cost of using the retrievable system will be increased by

70% on the original installation cost (all needed equipment included) with respects to a standard ESP completion design and

installation (extra RIH time was also considered for the calculation of the rig time). However, on the first ESP replacement, the

costs will be reduced by 80% of the standard intervention cost as the heavy duty WL equipment or CTU will cost only a

fraction of the rig rate and the time required to POOH & re-RIH the new ESP will be significantly lower (only a few hours

depending on the ESP setting depth compared with a few days from rig move to location).

Combining the costs of an original installation with standard completion design (ESP tubing deployed) plus one (1) ESP

standard rig substitution and comparing the total with the combined costs of the retrievable system original installation plus

only one (1) ESP substitution, the E&P company will be saving 30-35% only in intervention costs. Clearly, this percentage

will be different from region to region and will only be valid with standard service contractors contracts neither frameworks

agreements nor special rate contracts).

Case history: installations and results Since this technology was available in the market back in 2009 (July), there have been seven (7) installations including the

demo runs done as per the E&Ps request.

From those seven installations, four of them were with the 700 series and three were with the 550 series. The first worldwide

commercial installation with the 500/450 series will be done in early 2012.

Each installation has been different from each other one, making a fantastic start point for comparison and analysis. On the

700 series, only one of the installations failed due to equipment failure. Two of the systems were pulled due to the excessive

sand production, locking the ESP and subsequently, the SHUTTLE system.

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One of the 550 series system got stuck while RIH into a 7 casing with extremely tight tolerances, not because of the

retrievable system itself but because of the well configuration and therefore, cannot be accrued as a system failure.

A second system failed after the connectors where mechanically damaged while retrieving a failed ESP (full of sand and

broken shaft). After numerous successful reconnection of the failed unit into the docking station, the wet mate connector

became packed with some of the produce sand and consequently was damaged. Requiring to pull the unit out of the well. The

standard operating procedure of this system clearly specify that reconnection into the docking station should not be attempted

before the system is pulled to the surface to be inspected and well needs to be clean of all foreign material.

Clearly, lessons learned were applied where possible, making the retrievable system robust and efficient the way it is

nowadays. In addition, these lessons learned were applied also on the RIH and disconnection/POOH procedures, allowing the

needed flexibility required for this technology.

The latest installation is currently on going and could not be included in this paper; the presentation will reflect the latest

information available at the time.

Acknowledgements The authors would like to thank all the individuals at the various companies (ZEiTECS Inc, Weatherford International, SPT

Group Norway AS and the E&P end users) who have been involve with this technology from the design phases to the actual

installation in the different locations around the world, sharing their unique ideas and advices in artificial lift & completion

technology, to face the new challenges of the modern oil business. Without their valuable input and constant support, these

developments would not have been possible.

Nomenclature C = Degrees Celsius

F = Degrees Fahrenheit

AL = Artificial Lift

bpd = Barrels per day

cP = Centipoises

CTU = Coiled Tubing Unit

CL = Control line

ESP = Electro Submersible Pump

ft = Feet

GOR = Gas Oil Ratio

ID = Internal diameter

kg = Kilograms

kW = Kilowatts

MD = Measured depth

M = Meters

mm = Millimeters

OD = Outside diameter

PCP = Progressing Cavity Pump

POOH = Pull out of hole

ppf = Pounds per foot

psi = Pressure unit (lb/in2)

RIH = Run in hole

R&D = Research and Development

SL = Slick-line

TD = Total depth

TH = Tubing hanger

TR-SCSSV = Tubing retrievable surface controlled sub-surface safety valve

TVD = True vertical depth

VSD = Variable Speed Drive

WH = Well head

WL = Wire-line

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References 1. Neil Griffiths, Shell International Exploration and Production B.V., Iqbal Sipra, Petroleum Development Oman, Vishal Gahlot, Steve

Sakamoto, Peter Moulsdale and Steve Breit, Wood Group ESP Inc.. The Worlds First Wireline Retrievable ESP System, SPE

Workshop, Houston, Texas USA, 25-27 April, 2007.

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Tables

SPECIFICATIONS UNITS 700 SERIES 550 SERIES 450 SERIES

Maximum ESP / Motor Size series 562 400 / 450 / 456 338 / 375

Maximum Prod. Rate bfpd Limited by the ESP maximum flow rate

Min Casing Size/ max. weight inches/ppf 9 5/8 / 53.5 7 / 32 7 / 35

Required Tubing Size/max. weight inches/ppf 7 / 29 5 / 17 4 / 11.6

Max OD of Permanent Components inches 8.571 5.875 5.875

Max OD of Retrievable Components inches 6.055 4.750 3.875

Max Cable Size type AWG#2 (flat) AWG#4 (flat) AWG#4 (flat)

Metallurgy (standard) spec 13Cr 13Cr 13Cr

Wireline passage through penetrator can

(ESP removed) inches 1 11/

16 1.9 1.9

Coiled tubing passage through penetrator can

(ESP removed) inches 1 1 1

Max Well Inclination (without/with tractor) deg ~ 55 / 90+ ~ 40 / 90+ ~ 40 / 90+

Maximum temperature at Pump Setting Depth F / C 250 / 121 250 / 121 250 / 121

Maximum differential pressure at pump setting

depth psi 5000 5000 5000

Impact on ESP performance - None None None

Number of hydraulic control lines - Up to 6 Up to 6 Up to 6

Sand / Solids Content - WL / SL clean-out WL / SL clean-out WL / SL clean-out

Scale / Wax / Asphaltenes - WL or chemical c/o WL or chemical c/o WL or chemical c/o

Emulsions - Chemical injection Chemical injection Chemical injection

Weight of retrievable component (excl. ESP) lbs 2000 950 950

Table I. Retrievable system technical data sheet

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Figures

Figure I. Retrievable system configuration part 1: permanent components

Figure II. Retrievable system configuration part 2: retrievable components

SPE 156189 9

CSG 9 5/8"

CSG 13 3/8"

CSG 18 5/8"

Open Hole 6

3 " TR-SCSSV

WELL TYPEWell Completion Design

with ESP 700 Series Shuttle System

3 " Pup Joint

7" x 4 Packer

LINER 7"

4 " Tubing

4 " X-Over

3 " Pup JointChemical Injection Nipple

3 Permanent Quartz Gauge P&T Sensor3 " Pup Joint

3 " Pup Joint

Seal Assembly + Re-Entry Guide on bottom

ESP Shuttle Penetrator Can700 Shuttle - ESP Motor ConnectorMotorSeal ProtectorGas Handler - Intake

Bolt on Discharge HeadP&T SensorSpace-Out Tubing

Expansion Joint

Pump Isolation Device

Pump

7" x 3 " X-Over

7" Tubing 26#

7" Pup Joint

7" Pup Joint

7" Landing & Sealing Sub

7" Tubing 26#

7" Pup Joint

Tubing Hanger

Electrical Cable for Downhole Gauge (Size )

TR-SCSSV Control Line (Size )

Chemical Injection Line (Size 3/8")

ESP Power Cable (Flat Cable #2 = 0.626x1.626)

4 " Half Mule Shoe

Figure III. Completion design example A

10 SPE 156189

CSG 13 3/8"

4 " TR-SC-SSV with dual SS CL

9 5/8" x 4 Packer

4 " Pup Joint

Seal Assembly

700 Series docking stationSupplied with pup joint / cross over subs on top and bottom

700 Shuttle - ESP Motor Connector

562 Series ESP Motor

Seal Protector

Intake

Bolt on Discharge Head

3 Space-Out Tubing

Pump Isolation DeviceExpansion Joint

538/540 Pump(s) with Gas handler if required

7" Tubing 26#

700 Series Landing & Sealing Sub Supplied with two pump joints/Cross-over subs

7" Pup Joint for space out

Tubing Hanger

1 x SS control line for pressure test

2 x Control line - Deep Set Safety Valve

ESP Power Cable (#2AWG - Flat)

CSG 9 5/8"

Pe

rfo

rati

on

s

4 " Deep Set Lubricator Valve ball type with dual SS CL

4 " Pup Joint

4 " Pup Joint

2 x Control Line - Deep Set Lubricator Valve

4 " re-entry guide

4 " Deep Set Annular Flow Control Valve with dual SS CL to surface

4 " Pup Joint

4 " Pressure test sub with test line to surface

700 Shuttle Retrievable gauge

2 x Control lines Deep set Annular flow control valve

GS tool profile on top of the Isolation devise

4 " Pup Joint

WELL TYPEWell Completion Design

for ULTIMATE Well Controlwith ESP 700 Series Shuttle System

Figure IV. Completion design example B

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Figure V. Completion design example With gas venting option

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Figure VI. Completion design example Used as back-up to primary ESP

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Figure VII. Completion design example - Used as back-up to primary ESP (with annulus control while tripping the ESP rigless)

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Figure VIII. Completion design example - Used as back-up to primary ESP (with Y-tool and annulus control while tripping the ESP rigless)