SPE 165059

Successful Installation of a Dual Concentric Completion System on 9 5/8" Casing ESP-ESP type in Colombia H. Mata, K. Aristizabal, G. Rincon, J.A. Duran, F. Pinto, Allange Energy Corp, Adrialpetro, Zenith Oilfield

Copyright 2013, Society of Petroleum Engineers

This paper was prepared for presentation at the SPE Artificial Lift Conference-Americas held in Cartagena, Colombia, 21-22 May 2013.

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 Oil and Gas industry is always looking for methods that reduce costs associated with the drilling process and, over the last decade, eliminate the environmental impact of well preparation. One new technology provides an option for oil and gas producers to achieve that goal allowing installation of two sets of electrical submersible pumps (ESP) on the same well bore but producing two sands separated by a packer.

The purpose of the following paper is to to present a real example of the successful installation of a Dual Concentric Completion System in COPA ASUR3 , allowing two ESP systems to produce two different sands on the same well bore separated by a packer, and to demonstrate the economic effects of its use, reducing by 38% the costs associated with the drilling process, 14% on the total drill/completion investment and 50% on the environmental impact in COPA field (Colombia). The design and installation of the system were carried out taking into consideration Local Governmental regulations requiring both production zones remain insulated from each other.

Evidence explained on this paper helps to conclude that Dual Concentric Systems are proven to be applicable for specific fields with adequate sand distribution and fluid characteristics, also the use of Dual Concentric Systems complies with Government regulations keeping production from both zones isolated when applying the right integrity test procedure and that the use of Dual Concentric Systems significantly reduces costs and environmental impact associated with the drilling process and surface facilities configuration requirements.

Keywords: Dual concentric completion, Electric submersible pumps, ESP, Artificial Lift.

Introduction

Increasing demands from the Oil and Gas industry for economic and viable ways to reduce costs on hydrocarbon extraction processes have, since the 1950s, pushed the industry to consider dual concentric completions for multiple applicationsi. In cases where multiple stratified oil reservoirs are present and the general downhole conditions (formation characteristics, downhole pressure, fluid properties, etc) demand the development of each reservoir separately by local regulations, the traditional solution was to increase the number of wells to be drilled in order to recover fluid from all zones simultaneously, or produce different zones from the same well bore by single zone selection using sleeve/valve methods to allow the selective production.

Multiple drilling processes increases CAPEX figures considerably and is commonly considered as the only solution for multiple zones production, and important financial effect is add by the deferred production consequence of the drilling and completion period invested until fluid is obtained and the safety and environmental footprint caused by each wells preparation. On the other hand, selective zone production using SSD forces a production delay or reservoir production slow down, which has a negative impact on the operators extraction expectations, always sacrificing the input from the less productive zone.ii

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Along with completion methods and technology improvements, Dual Concentric Systems for artificial lift applications have been confirmed and considered as an alternative an economic and safe option to complete well bores with two identified production zones. This option has proven to speed up the reserves extraction process, reducing operational cost and providing major benefits on the QHSE aspect of the operation.

This paper outlines the design and successful installation process of a dual concentric system on 9 5/8 casing in COPA field well COPA ASUR3 including the installation procedure, lessons learned, economic and QHSE impact of the implementation of this method for the first time in the field.

Methods

Dual concentric completion: refers to the configuration of dual string tubing, accessories and tools that allows producing two different zones, at the same time on separated flow paths.iii

The system considered and designed for COPA A3SUR project consists of an arrangement of a Packer, POD (lower ESP inside) and By Pass system with the upper ESP system attached (bottom to top) connected to Production Tubing all the way to the surface. An inner string, inside the production tubing is adapted to a special connection on the top of the Bypass system allowing separation of two different sands and the production fluid paths on the same well bore. (Figure 1).

Country: Colombia Location: COPA field, Well CopaASUR3 (Figure 2) Operator: Allange Energy Corp. Installation Date: 28th Jan 2013 Artificial Lift Type: ESP-ESP (Both Zones).

Figure 2 Cubiro block, COPA field Figure 1 - Generic Dual Concentric Completion

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Field History: On 26th Jun 2012 Copa 5 well was completed with the first dual concentric system in Cubiro field, aiming to produce two different zones on the same well bore. The installation was successfully achieved, however production tests afterstart up showed unsatisfactory results on tsystem leaving only the upper ESP assembly in production. (Figure 3)

Figure 3 DHG Data from both ESP

This successful first installation experience with dual concentric systems provided the operator and all service companies involved with a full understanding of the potential that this technology represents for the future development of the field athe positive impact on the operators financial and QHSE figures.

General System Design: COPA ASUR3 is an exploration well which is expeted to provide information to and determine the existing reserves for this carbonated area (C5 and C7), reason why is necessary to flow both reservoirs on different paths.

COPA A3SUR was drilled on 15th Jan 2013for a dual completion design. The system order to confirm and prove this insulation, specific integrity tests were planned for the installation process to guarantee sconditions.

Using previous experience in COPA5 and worldwide recommendations and information, the criteria used for this application to select and design the system configuration and installation procedure were based on the following aspects

1. Mechanical considerationsv

Well Survey (Dog legs, depth) Perforation Information Casing characteristics. Weights to be handled.

o ESP o Production Tubing o Dual Accesories.

5 well was completed with the first dual concentric system in Cubiro field, aiming to produce two different zones on the same well bore. The installation was successfully achieved, however production tests afterstart up showed unsatisfactory results on the fluid composition of the lower sand (C7) leading to a shutdown of the lower system leaving only the upper ESP assembly in production. (Figure 3)

DHG Data from both ESP system during start up in COPA

experience with dual concentric systems provided the operator and all service companies involved with a full understanding of the potential that this technology represents for the future development of the field a

nancial and QHSE figures.

COPA ASUR3 is an exploration well which is expeted to provide information to termine the existing reserves for this carbonated area (C5 and C7), reason why is necessary to flow both reservoirs on

Jan 2013 and zones tested confirming C5 and C7 as the productive zones to be consideredThe system needed to be designed to produce C5 & C7 zones with adequate insulation. In

order to confirm and prove this insulation, specific integrity tests were planned for the installation process to guarantee s

Using previous experience in COPA5 and worldwide recommendations and information, the criteria used for this application to select and design the system configuration and installation procedure were based on the following aspects

Well Survey (Dog legs, depth) Perforation Information Casing characteristics.

to be handled.

Tubing Dual Accesories.

3

5 well was completed with the first dual concentric system in Cubiro field, aiming to produce two different zones on the same well bore. The installation was successfully achieved, however production tests after

he fluid composition of the lower sand (C7) leading to a shutdown of the lower

system during start up in COPA

experience with dual concentric systems provided the operator and all service companies involved with a full understanding of the potential that this technology represents for the future development of the field and

COPA ASUR3 is an exploration well which is expeted to provide information to define, characterize termine the existing reserves for this carbonated area (C5 and C7), reason why is necessary to flow both reservoirs on

and zones tested confirming C5 and C7 as the productive zones to be considered C5 & C7 zones with adequate insulation. In

order to confirm and prove this insulation, specific integrity tests were planned for the installation process to guarantee such

Using previous experience in COPA5 and worldwide recommendations and information, the criteria used for this application to select and design the system configuration and installation procedure were based on the following aspectsiv

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Figure 4 - Well Survey Graph

Casing Information 9 5/8

ID 8.755 Drift 8.599

Weight 43.5 lbs/ft TOP Hanger

Bottom 5615 ft Table 1 Casing characteristics

Weight Table Qty Item Weight Pounds

ESP System 3083 1 Sensor Discharge Sub E7 65 1 AFV 75 1 Crossover 3 1/2" EUE x 2 7/8" EUE 25 1 HEAD,PUMP BO TR4 2-7/8 8RD 23 1 PUMPs,TD2200 CMP 49/11B #06 350 1 PUMP,TD2200 CMP 100/21B #12 350 1 INTAKE,PUMP BO TD AR STL 25 2 SEAL,TR4 DBG PFDB AR HL-HT 110 2 SEAL,TR4 DBG PFDB AR HL-HT 110 1 MOTOR,TR4-92 120\1625\ 46 UT 750 2 Motor base crossover 25 2 E7 Sensor with Discharge Pressure 20 1 GAS,SEPARATOR TR4 MAGS-3 30 1 MOTOR,TR4-92 80\1085\ 46 UT 750 1 PUMP,TD1250 AR CMP 87/11B 320 1 CENTRALIZER 4.65 OD TR4 55

Tubing 777 2 3 1/2" EUE #12.95 777

Dual 3170 1 POD Assembly+tail pipe 3412 1 Saddle Assembly 261 7 By pass tubing THS blue + Crossover 274.16

Total 7870 Table 2 Weight Table

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2. Location Back up System Pre-shipment installation checks. Flexibility

Considering the distance between the ESP and Dual system providesystem was requested to overcome any design change or component failure during the installation.

All the equipment was physically checked by the ESP Company and the dual completion system provider prior to installation in order to confirm measurements and neck sizes for clamp installation. This process highlighted neck size differences between nominal and real value. This was rectified prior to installation.

For this project a Bypass System with saddle assembly option was selected which allows flexiprocedure when connecting the Y-Block. This was suggested in order to avoid delays matching by pass tubing and pump ends on the top connections during the RIH

Figure 5

shipment installation checks.

Considering the distance between the ESP and Dual system providers warehouse and the field location, a complete system was requested to overcome any design change or component failure during the installation.

All the equipment was physically checked by the ESP Company and the dual completion system provider prior to installation nts and neck sizes for clamp installation. This process highlighted neck size differences

between nominal and real value. This was rectified prior to installation.

For this project a Bypass System with saddle assembly option was selected which allows flexiBlock. This was suggested in order to avoid delays matching by pass tubing and pump

ends on the top connections during the RIH

Figure 5 By pass System Installation with Saddle

5

rs warehouse and the field location, a complete backup system was requested to overcome any design change or component failure during the installation.

All the equipment was physically checked by the ESP Company and the dual completion system provider prior to installation nts and neck sizes for clamp installation. This process highlighted neck size differences

For this project a Bypass System with saddle assembly option was selected which allows flexibility in the space out Block. This was suggested in order to avoid delays matching by pass tubing and pump

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3. Fluid Properties Material

Ranges Maximun Temperature 180 F Max Differential Pressure 800 psi CO2 N/A H2S N/A N2 N./A

Table 3 Material evaluation table

Considering fluid properties, Carbon Steel material was chosen for the application. Viton Elastomer was chosen for the plug systems this V-packing works up to 204 C.

4. ESP design information Length Size (Series) MLE & Power Cable specs Necks size

Figure 6 - Lower ESP Design Information

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Figure 7 Upper ESP desing Information

Figure 8 - ESP Neck Sizes Information

TR4 ESP Neck Information (inch) Section 1 2 L1

Sensor - Motor 2.87 4.56 2.56 Motor - Seal 2.875 4.5 2.26 Seal - Seal 2.875 4.5 3.05

Seal - Intake 2.25 3.75 1.463 Intake Pump 2.63 4 1.125

Pump Discharge 2.63 4 1.125

Table 4 ESP Neck Information

7

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Clamping the ESP neck to the By Pass tubing will be done by using adjustable clamps type 1 which offers a range of adjustment from 2.250 up to 3250 1, covering all necks to be installed specified on table 5. The use of Adjustable clamps is a method which simplifies the preparation of the system allowing quick changes in design without affecting delivery times or installation duration of the system

Figure 9 Type 1 Adjustable clamp from 2.250 to 3.250 Neck diameter

5. Operative scenarios Tools required (lifting, work tables) Procedure review for specific project.

Dual Completion ESP-ESP Type on 9 5/8 Casing Final Design: Only after a thorough review of the system requirements and consideration between all parties involved, the final design was approved and the dual completion tools and accessories were moved to the location to be installed in COPA A3SUR Bottom Assembly:

Figure 10 Bottom Assembly Diagram

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Primary Purpose: To provide a seal between C5 and C7 Zone and Stinger connection port for the upper assembly to be connected.

Consists of the following items:

Qty Description Length Depth

2 Production Tubing joints (30.5ft) 61.02 5,390.02

1 Safety Joint 1.04 5451.04

1 Tubing Joint 3-1/2" EUE 31.00 5,452.08

2 BLAST JOINT 2.7/8 EUE (PERFORDOS A 5492 - 5497)

21.62 5483.08

2 Pup Joint 3-1/2 EUE 16.20 5504.70

1 Landing Nipple 2.75" F - 3.1/2 EUE 1.09 5520.90

1 Xover 5.5 LTC PIN x 3.1/2 EUE Box 1.02 5521.99

1 Snap Latch 6" w/t Seal Unit 5.5"LTC Box (LONGITUD TOTAL 4,74)

0.27 5523.01

1 BlackCat Packer 43.5 - 53.5 # 9.5/8"x6" 5.12 5523.28

1 Model G2 closing sleeve 19.10 5528.40

1 Crossover 7in StudAcme Pin x 5.5 LTC Pin 0.54 5547.50

1 Shear Sub 5-1/2" LTC Box Pin 1.82 5548.04

1 Crossover 5-1/2" LTC Box x 5.5" BTC Pin 0.70 5549.86

1 Blank Pipe 5-1/2" BTC B X P 36.10 5550.56

1 5.5" 17#L80,BTC,316L (PremiumNet) 37.70 5586.66

1 Crossover 5-1/2" BTC Box x 5.5" LTC Pin 0.73 5624.36

1 Snap Latch 6" w/t Seal Unit 5.5"LTC Box 0.91 5625.09

1 9.5/8 ARROWPAK 40-47#x6.0in 3.24 5626.00

Table 5 Bottom Assembly Components.

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Lower Assembly Diagram:

Figure 11 Lower ESP assembly (POD)

Primary Purpose: To provide a direct path from C7 fluid to the lower ESP assembly intake, keeping isolated the upper and lower zone. Has bottom and top nipple profiles installed in order to set Standing valve / Blanking plugs to pressure test the system while installed on the well bore.

Special equipment is required in order to assemble the POD assembly (Work Table 20 tons & Lifting Sub for Casing joints)

General Specifications: Diameter: 7 Min Internal diameter: 2.750 Upper Connection: 3 9.2 VTop Torque (ft.lbs): 2610 2900 3190 Lower Connection: 3 EUE Pin Torque (ft.lbs): 2400 3200 4000 Tensile Strength: 207000 lbs Material: API 5 CT L80 Type 1

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Consists of the following items:

Qty Description Length Dept

h

1 Crossover 11450041201 4.65 7,405.12

1 POD Hanger with penetrator Crossover Pump Sub

1.44 7,406.56

9.65 7,416.21

1

5.00 7,421.21

Auto Flow Assembly (With Crossovers) Auto Flow Valve 2 7/8" EUE 2 x 2 7/8 EUE - 3 1/2" Xover

1

0.50 7,421.71

Long. BES = 56.42 ft PUMP DISCHARGE - 513 Series

1

CENTURION 538 P-23 SSD H6 / 139 stg 18.90

7,440.61

1 INTAKE - 513 Series / GXPINTSSDH6 1.10 7,441

.71

1 TANDEM SEAL 513 Series GST3DBXH6HLPFS 12.60 7,454

.31

1

MOTOR 562 Series 165HP / 2133 V / 46 A / KMHA-X

19.70 7,474.01

1 Motor base Cross Over - Zenith E6 Sensor 3.62 7,477

.63

1 Upper POD assembly 13.00 7,406.56

3 Casing Joint Qty to be confirmed based on the Pump Lenght

20.00 7,426.56

40.00 7,466.56

1

11.00 7,477.56

Bottom POD assembly with Bottom nipple Free space inside shroud = 6.93

ft distance to 7in linner =78.44 ft

Table 6 Lower Assembly components

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Upper Assembly Diagram:

Figure 12 Upper ESP assembly (Bypass)

Primary Purpose: To provide a direct path from the lower assembly to the inner string connection for the fluid produced from C7 through the Bypass tubing. Redirect PODs weight away from the upper ESP using the bypass tubing.

Special equipment is required in order to assemble the bypass assembly (Work Table 20 tons & Lifting Sub for Bypass tubing joints)

General Specifications: Diameter: 8.250 Min Internal diameter: 1.9 Upper Connection: 5 17.0# Buttress Torque (ft.lbs): to base of Triangle Lower Connection: 3 EUE Pin Torque (ft.lbs): 2400 3200 4000 Tensile Strength: 104340 lbs Material: API 5 CT L80 Type 1

Bypass tubing tread: 2 3/8 VTop

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Consists of the following items:

Qty Description Length Depth

1 Coupling and Cross overs

0.77 7,240.04

1

3.48 7,251.14

9-5/8" By Pass Assembly Top Nipple

2 Crossover Pump sub 11450048201 9.53 7,260.67

1 Swivel Nipple Assembly 3.555" Seal Bore 4.85 7,263.97

4 Bypass Tubing Joint 10360011201 60.00 7,323.97

3 Cable Protector Clamp 10380119201 To Accommodate:- 2-3/8" Bypass Tubing

n/a n/a

1

5.00 7,261.67

AFV 2 7/8"EUE BOX BOX + Pup Joint (Pin Pin)

1

0.50 7,262.17 Long. BES = 53.1 ft

PUMP DISCHARGE - 513 Series

1

CENTURION 538 P-23 SSD H6 / 104 stg 14.40 7,276.57

1 GAS SEPARATOR - 513 Series GRSXH6BAR2H6

3.10 7,279.67

1 TANDEM SEAL SECTION - 513 Series GST3DBXH6HLPFS

12.60 7,292.27

1

MOTOR SECTION - 562 Series 165HP / 2133 V / 46 A / KMHA-X

19.70 7,311.97

1 E7 DHG Sensor 2.80 7,314.77

1 Spare Sadlle assembly (with motor base plug) 9.20 7,323.97

1

15.50 7,339.47 Saddle assembly

Table 7 Upper Assembly components

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Operational guidelines. The following section contains a detailed installation procedure and pressure test guidelines in order to understand and consider all operational aspects of a Dual concentric installation.

On surface and before starting to run completion A. Manual set 2.750 Blanking Plug in Pod bottom crossover B. Manual set 1.875 Standing Valve in Pod Hanger Run completion tailpipe assembly: 1. Build Zenith Pod assembly 2. Pressure test pod assembly against 2.75 plug Test to 3600psi max 3. Rig up wire line 4. RIH and pull 2.75 plug 5. Rig down 2.75 Blanking Plug Redress Blanking Plug 6. Rig down wire line 7. Build Pod ESP 8. Make up pod hanger - Test between pod hanger seals using hand pump 3000psi max 9. Build Intermediate tubing and By-pass system 10. Make up Y tool and run 1 or 2 joints tubing 11. Rig up wire line 12. Make a 1.901 drift run through Y-tool/By-pass/Intermediate tubing - Drift to Pod Hanger nipple/1.875 Standing Valve 13. Rig up Isolation Sleeve/Standing Valve on wire line - RIH and set 3.75 x 3.555 Isolation Sleeve across Y-Tool Top Nipple/Teleswivel Nipple 14. POOH and rig down wire line 15. Pressure test By-pass/Intermediate tubing against 1.875 Standing Valve Test to 3600psi max - (Testing through Isolation Sleeve) 16. Space out by pass Assembly as per procedure

Figure 13 Space out procedure

17. Run in hole with 5 (Outer) production tubing 18. Space out and land off Outer completion string 19. Pressure test 5 (Outer) Production tubing/By-pass/Intermediate tubing against 1.875 Standing Valve Test to 3600psi max (Testing through Isolation Sleeve) 20. Rig up wire line 21. Make a 3.833 drift run to Isolation Sleeve 22. RIH wire line and pull 3.75 x 3.555 Isolation Sleeve 23. Rig down Isolation Sleeve Redress Isolation Sleeve

SPE 165059

24. Make a 1.901 drift run to Standing Valve25. RIH wire line and pull 1.875 Standing Valve26. Rig down Standing Valve Redress Standing Valve27. Rig down wire line 28. Manual set 1.875 Standing Valve in Inner (2 7/8) production string Stinger assembly29. Run in hole with 2 7/8 (Inner) production tubing30. Space out and land off Inner completion string Stinger in Teleswivel nipple31. Pressure test Inner (2 7/8) production tubing ag32. Rig up wire line 33. RIH and pull 1.875 Standing Valve 34. Rig down Standing Valve Redress Standing Valve35. Rig down wire line 36. Set appropriate well barriers Nipple down BOP Head

Results

Operational.

Installation Start Date/Time: 26-Jan-13 01:00Installation End Date/Time: 29-Jan-13 06:00Total entitle time: 77 Hrs (3 days) Pressure integrity Test: successful 1500psi (10 min)C7 Fluid in surface: Yes 30-01-13 04:53C7 Production rate: 600 BPPD C7 Reading @36 HZ, Im 21 A,Ivsd 79A,

C5 Fluid in surface: Yes 30-01-13 04:25C5 Production rate: 500BPPD C5 Reading @ 43 HZ, Im 19A, Ivsd 52A, Volt 932

Figure 14 shows the data from the DHG installed on the well, Pi & Pd behaivor during the start up with fluid in surface confirms the sucess of the installation and the

Lower Reservoir

. Make a 1.901 drift run to Standing Valve

. RIH wire line and pull 1.875 Standing Valve Redress Standing Valve

Standing Valve in Inner (2 7/8) production string Stinger assembly . Run in hole with 2 7/8 (Inner) production tubing . Space out and land off Inner completion string Stinger in Teleswivel nipple . Pressure test Inner (2 7/8) production tubing against 1.875 Standing Valve Test to 3600psi max

Redress Standing Valve

Nipple down BOP Nipple up Dual Concentric well

13 01:00 13 06:00

Pressure integrity Test: successful 1500psi (10 min) 13 04:53

C7 Reading @36 HZ, Im 21 A,Ivsd 79A,Volt 1101

Pi Pd Ti Tm

Psi Psi Deg C Deg C

1581.0 2086.0 171.9 177.4

13 04:25

52A, Volt 932

Pi Pd Ti Tm

Psi Psi Deg C Deg C

1560.9 1998.5 180.0 185.0

Figure 14 shows the data from the DHG installed on the well, Pi & Pd behaivor during the start up with fluid in surface confirms the sucess of the installation and the integrity of the system.

Upper Reservoir

Figure 14 DHG Readings during Start up

Start Up

15

3600psi max

Figure 14 shows the data from the DHG installed on the well, Pi & Pd behaivor during the start up with fluid in surface

Upper Reservoir

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QHSE Results

Duration of the project: 20 days (drilling completion) Persons involved: 25 permament on site. Man Hrs worked during the project: 12000 hrs aprox LTI / NPT N/A Permanent Area affected: 45m2

Financia Results.

Total Project Cost: 4.5M$ Preliminary and Mobilization 138K$

Drilling Surface Hole 483K$

Drilling Production Hole 1371K$

Completion Material and activities 2560K$

DISCUSSION

Operational. Dual concentric system installation meets the project expectation. Having tested both strings for leaks and having fluid to surface from each system it can be considered a successful installation. The installation added an efective 25 hrs compared with a traditional installation of a BES on 7 Casing with By-pass System.

QHSE. Man hr worked reduction affects directly the likelihood of having a incident/accident while performing oil field operations. On COPA ASUR3 the 12000 Hrs required to achieve two zones production (drilling&completion) could be compared with the human resource investment necessary to drill and complete two different wells and obtain the same production results.

Standard drilling/completion process takes around 11000 hrs (on average) on each 7 well completed in Copa Field, suggesting that the use of this type of system could reduce the exposure of field personnel by almost 50%.(46%)

Financial. Efective cost associated with the project is compared with the previous standardized and accepted option which consist on the drilling of two 7 casing separated wells being completed with one ESP system per hole. The analisys is carried out taking in consideration the following aspects:

- Preliminary and Mobilization: Location preparation for the intervention, well area adecuation, surface equipment, personnel involved, surface facilities and Rig mobilization.

- Drilling Surface Hole: First stage on the drilling process including material and personel involved. - Drilling Production Hole: Second stage on the drilling process, consisting on the 9 5/8 hole perforation, casing

installation, material used and the personnel involved on the operation. - Completion: Include Rig time used during the installation of the completion on the well, completion elements and

material, personnel.

Table 8 shows a comparative method to determine the benefit of the technology between the perforation and completion of two 7 Casing Well (previous alternative) against the cost associated with the drilling and installation process of one 9 5/8 casing well with a Dual Concentric Completion

Description 2 x 7" WELLS DUAL Difference PRELIMINARY AND MOBILIZATION $ 276,178 $ 138,089 $ 138,089 DRILLING SURFACE HOLE $ 964,445 $ 482,933 $ 481,512 DRILLING PRODUCTION HOLE $ 1,926,003 $ 1,371,245 $ 554,758 COMPLETION $ 2,111,238 $ 2,560,216 -$ 448,978 TOTAL $ 5,277,864 $ 4,552,483 $ 725,381

Table 8 Cost comparation between 2 x 7 Well and 1 x Dual Completion

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Chart1- Comparative figures between 2 x 7 Well and 1 x Dual Concentric in 9 5/8

Saving figures:

Drilling process: 37% (1.17MM$) Overall process: 14% (726K$)

Economic analysis is carried out without tacking in consideration savings on differed production obtained 15 days eaerlier on one of the wells. Also there is a risk incompletion process there is a chance of not obtain

RECOMENDATIONS

To develop a strategy and future recomnedationsrepresent an increment on the saving figures from 37% up to 45% (around 1.5MM$)wells (smallers pump)

To consider the differed production financial implicati To use adjustable systems which accommodate different type of pumps and allows

as consequence of specific well conditions discovered on the drilling process. To install Auto Flow Valves elimin

expected to improve the runlife of the ESP system avoiding early workover manubers. To use discharge pressure gauges in order to identify pump efficiency during the runlife of the

helping to optimize its use.

$ 0

$ 1,000

$ 2,000

$ 3,000

$ 4,000

$ 5,000

$ 6,000

PRELIMINARY AND

MOBILIZATION

DRILLING SURFACE

$ 276$ 138

Th

ou

san

ds

Comparative figures between 2 x 7 Well and 1 x Dual Concentric in 9 5/8

without tacking in consideration savings on differed production obtained 15 days eaerlier on one of the wells. Also there is a risk involved and not considered on this analysis, which is that

of not obtaining good results on a specific reservoir that was pl

evelop a strategy and future recomnedations for Dual Concentric Systems in 7 Casing applications. represent an increment on the saving figures from 37% up to 45% (around 1.5MM$)

To consider the differed production financial implication of the use of this technologyTo use adjustable systems which accommodate different type of pumps and allows reactingas consequence of specific well conditions discovered on the drilling process.

eliminates the requirement for SSD valves when recirculation is requirexpected to improve the runlife of the ESP system avoiding early workover manubers. To use discharge pressure gauges in order to identify pump efficiency during the runlife of the

DRILLING SURFACE

HOLE

DRILLING

PRODUCTION HOLE

COMPLETION

$ 964

$ 1,926$ 2,111

$ 483

$ 1,371

$ 2,560

COST ANALISYS PER PHASE

2 X 7" WELLS Vs 1 DUAL CONCENTRIC 9 5/8"

2 x 7" WELLS

DUAL

17

Comparative figures between 2 x 7 Well and 1 x Dual Concentric in 9 5/8

without tacking in consideration savings on differed production obtained 15 days eaerlier on which is that on standard drilling and

specific reservoir that was planned to flow.

for Dual Concentric Systems in 7 Casing applications. This could to be used on lower flow rate

on of the use of this technology reacting to ESP desing changes

the requirement for SSD valves when recirculation is required, also is expected to improve the runlife of the ESP system avoiding early workover manubers. To use discharge pressure gauges in order to identify pump efficiency during the runlife of the ESP equipment

TOTAL

$ 5,278

$ 2,560

$ 4,552

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REFERENCES

i Concentric copletions of Oil and Gas Wells - 1959 G.M Harper Jr., Union Oil Co. of California

ii Experience with dual completions in TNK-BP 2012 E. Muslimov, P. Medvedev / JSC TNK-BP Managrment

iii Completacion dual Concentrica con Bomba Electrosumergible y Flujo Natural de un pozo en el Oriente

Ecuatoriano para Revestimiento de 9 5-8y liner de 7 2010 E. Peralta, E Baquerizo, H. Roman.

iv Diseno de completacion dual concentric BES-FN para Casing de 9 5/8 2011 J. Soto, C. Salazar

v Completacin Dual Concntrica, Pozo Sacha-165D. Anlisis de Factibilidad. H. Romn, G Echeverra e J. Chiriboga.

PETROPRODUCCION, 2004

* News Release Petromagdalena News http://www.prnewswire.com/news-releases/petromagdalena-announces-exploration-update-147524255.html

* Zenith Oilfield Dual concentric Manual and procedure - Ian McConnachie 2010

* Allange Energy Corp. ESP system design information Production department - 2012