Wellhead compression - Petroleum Club

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Wellhead compression Multi well – LP gas gathering With screw compressors


General

© Siemens AG 2014. All rights reserved.

What is it ? Compression close to the wellhead lowers the flowing wellhead pressure, which increases production and prevents liquid

loading. Siemens wellhead compressor solution can thereby substantially enhance the recovery rate.

Why do I need it ? Valuable hydrocarbons will not be produced

Expensive field abandonment is needed soon

Production obligations/ambitions can not be met

New explorations necessary (high risk & investment)

Wellhead compression


When do I need wellhead compression?

Xmas tree

Gas

Treatment Facility

Transport pipeline

Reservoir High

Pressure

Phase 1: Free flow, well pressure 100-300 bar. No compression needed

Xmas tree

Gas

Treatment Facility

Transport pipeline

Reservoir Medium Pressure

Central

Compression (Restaging)

Phase 2: Well pressure < 80 bar

Xmas tree

Gas

Treatment Facility

Transport pipeline

Reservoir Low

Pressure

Central

Compression (Restaging)

Wellhead compression

Phase 3: Well pressure < 10 bar


0

Rat

e [M

SC

FD]

2 4 6 8 10 12 14 16 18 20

Time [year]

Dry Well Rate MSCFD

Critical flow rate “Wet” Well Rate MSCFD

Any Gas Well will flow to here…

With Siemens Well head Compression

Declining flow rate, well dies

Extra production potential

Siemens Wellhead Compression

Well life & production rate


Single or multi well ?


Main spec single and multi well compr unit

Single well compr Multi well compr No of wells 1 4 - 15 Min inlet pressure ~ atmospheric ~ atmospheric Max discharge pressure 30 bar 50 bar Capacity control 100%-50% 100%-15% Power ~ 35 kW 400 kW – 3 MW

Capacity @ 4 barg 20.000 m3/d 250.000 to 1.500.000 m3/d Peak liquid 8 m3/d [50 bbl] 50-200 m3/d [330-1300 bbl] Remark Piston compressor

Gas engine “combi” Screw compressor (oi) E-motor


Application single and multi well compression unit

Single well compr Multi well compr Well plot Distributed Centralised (well pad or

cluster) Well size/capacity Small Medium/Large

Availability/reliability Medium High (>98%) Fleet management Complex Simple Transport pressure No Yes Remark Booster station

Electrification


Case study


Customer Gazprom

Location West Siberia

Oil injected screw compressor type

Power electric motor 450 kW

Capacity 8.500 MCF/day @ 60 PSI suction

Discharge pressure 100-150 PSI

Inlet pressure 30-100 PSI

Remote operated

Availability 95-98%

Results 5 wells connected:

2x killed wells produce continuously

3x well immediate boost of production

Customer Gazprom

Location West Siberia

Oil injected screw compressor

Power electric motor 450 kW

Capacity 240.000 mn3/day @ 4bara suction

Discharge pressure 7-10 bara

Inlet pressure 2-7 bara

Remote operated

Availability 95-98%

Results 5 wells connected:

2x killed wells produce continuously

3x well immediate boost of production

TCO based on 7 years of operation:

Added costs 0,01 euro / 1 mn3

Added costs 0,35 USD / 1000 CF


Gazprom – Wellhead compressor for mature gas field

Many of Gazproms natural gas assetsin West Siberia have been producing since the seventies. These depleting assets face severe production decline and liquid loading. For revitalization of their mature wells Gazprom introduced wellhead compression

Multi well compression (5-7 wells hooked up) gives a significant reduction of required units, site preparations and service calls. Condensate, formation water and condensed water. Unit handles slugs and high LTG ratios Package tailored to Russian rules&regulations, Gazproms engineering principles and West Siberian climate (-55°C)

Siemens main contractor Complete functional unit, ready for hook up E-motor driven oil injected screw compressor Installation supervision, commissioning Service

Additional remarks Capacity 225.000 mn3/day @ 4 bara suction Capacity 8 MMSCFD @ 60 PSIa In operation since summer 2011

Customer benefits : Scope of supply: Operational back ground:


Conceptual study


Workflow

1. Production modelling

(sub-surface & surface)

2. Equipment (selection,

sizing, pricing CAPEX/OPEX)

3. TCO Economics (production

profiles, cash flows)


Integrated production modelling

Gas Treatment Facility


Integrated production modelling

Well cluster A consisting of 7 wells. Well inflow individually considered. Compressor in multi well operation simulated.

Three compressor configurations considered:

1. Actual capacity 4300 ma3/h – Max power 300kW



Assumptions:

• Start compression winter 2015

• End compression spring 2022

• Availability wells 95%

• Vertical wells

• Low intermediate/discharge pressure selected

• Flow data for a time window of 8 years


Production modelling Multi-well; Concept 600kW

Killed well End of time frame

Time frame

= No Compression

= WH Compression

First day of operation Well no 1 Well no 2 Well no 3

Well no 4 Well no 5 Well no 6

Well no 7


Economics

Three compressor configurations considered:




Three compressor drives considered:

A. Gas engine = reciprocating motor [ = Gas ]

B. E-motor; external power @ given MW/h price [ = E ]

C. E-motor; independent power generation 5 MW gas turbine [ = GT ]. Pro ratio usage.

10 concepts = 9 compression concepts + “do nothing scenario”


Economics

1st killed well


Economics

First day of

operation

Purchase

Do nothing


Economics Cum AT cash flow

900kW PG

600kW PG

900 kW gas

300kW PG

600kW gas

600kW E

300kW E

300kW gas

900kW E


Economics Economic indicators

Compression Scenario

300 kW Electrical

300 kW Elec Pgen 300 kW Gas 600 kW

Electrical 600 kW Elec

Pgen 600 kW Gas 900 kW Electrical

900 kW Elec Pgen 900 kW Gas

Gas Reserves (e6m3) 512,73 512,73 437,86 628,66 628,66 536,28 682,33 681,16 573,09

Total Capital (MRUB) 158,76 184,16 203,21 190,51 234,96 247,67 209,56 279,42 266,72

BT NPV at 0% (MRUB) 587,92 653,63 546,45 593,56 768,96 646,41 549,29 795,98 673,69

BT NPV at 10% (MRUB) 272,03 307,68 232,51 249,41 359,48 276,23 204,42 361,41 283,56

BT NPV at 15% (MRUB) 182,42 208,91 143,98 152,8 242,33 171,51 108,65 237,32 173,29

AT NPV at 0% (MRUB) 463,27 514,71 425,81 466,36 604,72 503,3 430,1 624,37 524,06

AT NPV at 10% (MRUB) 204,97 231,47 168,8 184,34 268,87 200 146,84 266,87 204,25

AT NPV at 15% (MRUB) 131,96 150,92 96,6 105,47 173,19 114,56 68,48 165,28 114,24

Payout BT (months) 51,4 49,26 56,14 57,35 49,18 55,35 62,43 51,2 55,99

Payout AT (months) 54,04 52,19 58,78 59,66 52,36 58,15 64,3 54,37 58,8

ROR BT (%) 39,4 40,98 30,98 30,39 39,55 31,08 24,42 35,99 30,02

ROR AT (%) 34,33 35,37 26,79 26,87 34 26,78 21,71 30,81 25,88

DPI BT at 0% 3,7 3,55 2,69 3,12 3,27 2,61 2,62 2,85 2,53

DPI BT at 10% 1,93 1,88 1,29 1,47 1,72 1,26 1,1 1,46 1,2

DPI BT at 15% 1,37 1,35 0,84 0,95 1,23 0,82 0,62 1,01 0,77

DPI AT at 0% 2,92 2,79 2,1 2,45 2,57 2,03 2,05 2,23 1,96

DPI AT at 10% 1,45 1,41 0,93 1,09 1,29 0,91 0,79 1,07 0,86

DPI AT at 15% 0,99 0,97 0,56 0,66 0,88 0,55 0,39 0,7 0,51

Legend BT = Before Tax AT = After Tax NPV = Net Present Value ROR = Rate Of Return DPI = Discounted Profit Index

CONFIDENTIAL


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Wellhead compression - Petroleum Club

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