PMP 600 CVX Pump Manual - Multiphase Pumps

600 Multi ultiph phaase Pumps umps Ab strac st rac t This section covers the four most common types of multiphase pumps that are commercially available, an overview of manufacturers, upstream applications of each type, typical application a pplication opportunities, opportunities, the qualification process, economics to be considered, review of selected selected installations installations (with lessons learned), learned), and new developments as of 2008.

March 2009

Co n t en t s

Pag e

610

Introduction

600-5

611 61 1

Defi De fini niti tion on of a Mu Mult ltip ipha hase se Fl Flui uid d

612 61 2

Most Mo st Co Comm mmon on Typ ypes es an and d App Appli lica cati tion onss of of MPPs MPPs

613

Purpose of the Manual

614 61 4

Upst Up stre ream am Oi Oill Fi Fiel eld d Ap Appl plic icat atio ions ns

615

Refinery Applications

616 61 6

Wha hatt Ki Kind ndss of Pu Pump mpss ar aree MP MPPs Ps??

617

Conclusion

620

Commercially Available MPP Types

621

General

622

Twin Screw MPP

623

Helico-Axial Pu Pump

624 62 4

Progr Pro gres essi sing ng Ca Cavi vity ty Pu Pump mp (PC (PCP) P) or or Sing Single le Scr Screw ew Pum Pump p

625 62 5

Elec El ectr tric ic Su Subm bmer ersi sibl blee Pu Pump mp (E (ESP SP))

626 62 6

Gene Ge nera rall MP MPP P Se Sele lect ctio ion n Gu Guid idel elin ines es

630

Design Recommendations

631

General

632

Mechanical Seals

633 63 3

Scre Sc rew w Sea Seala lant nt fo forr Twi win n Sc Scre rew w Pum Pumps ps

634 63 4

Roto Ro torr De Desi sign gn fo forr Twi win n Sc Scre rew w Pu Pump mpss



2009 Ch ev r o n U.S.A . In c . A l l r i g h ts r eser v ed .

600-13

600-39

600-1

6 0 0 Mu l t i p h a s e P u m p s

600-2

Pu m p Man u al

635

Effe Ef fect ct of Slu Slugs gs—G —Gas as and Liq iqui uid d

636

Motor Mot or Sel Select ection ion and Use of Adj Adjust ustabl ablee Spee Speed d Driv Drives es (AS (ASD) D)

637

Meth Me thod odss to to Re Redu duce ce Sa San nd Ero Erossion

638 63 8

Recy Re cycl clee Stre Stream am Fla Flash shin ing g (Sur (Surfa face ce Pum Pumps ps))

639 63 9

Suct Su ctio ion n and and Di Disc scha harg rgee Pip Pipin ing g (Su (Surf rfac acee Pum Pumps ps))

640

MPP Materials

641

General

642

Twin Screw Pumps

643 64 3

Heli He lico co-A -Axi xial al,, PCP PCP, and and ESP ESP Mat Mater eria ials ls

644 64 4

Mech Me chan anic ical al Se Seal al Ma Mate teri rial alss (al (alll typ types es of MP MPPs Ps))

650

Manufacturers—Twin Screw MPPs

651

General

652

Bornemann MPPs

653

Leistritz MPPs

654

Flowserve MPPs

655

Reco Re comm mmen enda dattio ions ns an and d Com Comme men nts

660

Manufacturers—Helico-Axial MPPs

661

General

662

Framo

663

Sulzer

664


670

Manufacturers—Progressing Cavity MPPs

671

General

672

Moyno

673

seepex

674


680

Manufacturers—Electric Submersible (ESP) MPPs

681

General

682

Centrilift

683

Schlumberger (R (Reda)

684




2009 Ch ev r o n U.S.A . In c . A l l r i g h t s r es er v ed .

600-56

600-59

600-67

600-71

600-75

Ma r c h 2 0 09

Pu m p Man u al

600 Mu l t i p h as e Pu m p s

690

March 2009

Sizing Sizi ng of the the MPP MPP,, Its Its Driv Driver er,, and and Asso Associ ciate ated d Faci Facili liti ties es (Upstream Applications)

600-80

691 69 1

Twi win n Scre Screw w MPP MPP Desi Design gn Gui Guide de for for Ups Upstr trea eam m Appl Applic icat atio ions ns

692

Sizing

693

Pump Si Sizing Calcu cullation

694 69 4

Gas Vol olum umee Fr Frac acttio ion n (G (GV VF)

695 69 5

Thee Recy Th Recycl cle, e, Sli Slip, p, Fla Flash shin ing g Fact Factor or for for Twi Twin n Scre Screw w MPPs MPPs

696 69 6

Pump Pu mp Ef Effi fici cien ency cy fo forr Twi Twin n Scr Screw ew MP MPPs Ps

697 69 7

Over Ov eral alll Me Mech chan anic ical al Ef Effi fici cien ency cy Ca Calc lcul ulat atio ion n

698 69 8

Vol olum umet etri ricc Effi Effici cien ency cy Cal Calcu cula lati tion on

699 69 9

Pump Pu mp Si Sizi zing ng Sp Spre read adsh shee eett fo forr Twi Twin n Scr Screw ew MP MPPs Ps

6910

Piping Pipin g and and Instru Instrumenta mentation tion Diagr Diagram am (P&ID) (P&ID) for a Twin Twin Screw MPP

691 69 11

Sepa Se para rato torr Sizi Sizing ng for for Twi Twin n Scre Screw w MPPs MPPs

6100

Typical MPP Application Opportunities

6101

General

6102 610 2

Upstre Ups tream am Appl Applica icatio tion n Oppor Opportun tuniti ities— es—Lis Listi ting ng

6103 610 3

Upstre Ups tream am Appl Applica icatio tion n Oppo Opportu rtunit nities ies—De —Detai tails ls

6104 61 04

Down Do wnst stre ream am App Appli lica cati tion onss

6110

Technology Qualification Process (TQP)

6111

Introduction

6112

Chevron TQ TQP

6113 61 13

Defi De fini niti tion on of Qu Qual alif ific icat atio ion n

6114

Machinery TQ TQP

6115 61 15

Tech echnol nology ogy Dev Develo elopme pment nt Stag Stages es (TDSs (TDSs)) for MPP MPPss

6116

TQP Su Summary

6120

Economics Ec

6121

General

6122 61 22

Exis Ex isti tin ng Faci Facili liti ties es

6123

New Facilities

6124 61 24

Fact Fa cto ors to Con Consi side der r

6125

Examples

6126

Cost Compa Comparison rison Stu Study dy for for an excee exceeding dingly ly high high GVF of of 98 Percen Percent—MPP t—MPPss versus a Conventional Separation System




600-93

600-101

600-108

600-3


Pu m p Man u al

613 130 0

Selected MPP Instal alllation onss (including Lesson onss Lear arn ned)

600 60 0-117

6131

General

6132 613 2

Humble Hum ble’’s Flu Fluid id Flo Flow w Test Test Fac Facili ility ty MPP

6133

Trinidad

6134

Mitsuee Field, Mitsu Field, Slave Slave Lake, Lake, Canad Canadaa (later (later moved moved to Princ Princess ess Field Field in in Canada) Canada)

6135 61 35

Mits Mi tsue ue Pum Pump p Move Moved d to the the Pri Princ nces esss Fiel Field d

6136 613 6

Main Mai n Pass Pass 313, 313, Offs Offshor horee Platfo Platform rm in the Gulf Gulf of Mexic Mexico o

6137 61 37

Humb Hu mble le,, Tex Texas as,, Prod Produc ucti tion on Fie Field ld

6138 61 38

Duri Du ri Tri rial al,, In Indo done nesi siaa

6139

COB Facility Facility,, El Tigre Tigre Field, Field, Venezu Venezuela; ela; Boscan Boscan Field, Field, Venezu Venezuela; ela; Kome, Kome, Miandoum; and Belobo Fields, Chad

6131 61 310 0 Ma Main in Pa Pass ss 59 A

600-4

6140

New Developments (as of 2008)

6141

General

6142 61 42

Twi win n Scr Screw ew Pu Pump mp De Deve velo lopm pmen ents ts

6143 61 43

Heli He lico co-A -Axi xial al Pu Pump mp De Deve velo lopm pmen ents ts

614 144 4

PCP PC P De Dev vel elo opm pmen ents ts

614 145 5

ESP ES P Dev evel elop opme ment ntss

6146 61 46

Mech Me chan anic ical al Se Seal al De Deve velo lopm pmen ents ts

6150

Definitions and Acronyms

6151

Definitions

6152

Acronyms

6160

References

6161 61 61

Comp Co mpan any y Spe Speci cifi fica cati tion onss

6162 61 62

Amer Am eric ican an Pet Petro role leum um Ins Insti titu tute te (AP (API) I)

6163 616 3

Nation Nat ional al Assoc Associat iation ion of of Corros Corrosion ion Engi Enginee neers rs (NACE (NACE))




600-141

600-146

600-150

Ma r c h 2 0 09

Pu m p Man u al


610 In t rod rod u c t ion ion 611 611 Definition Definition of a Multipha Multiphase se Fluid A multiphase fluid is defined as a fluid that consists of two or more phases in which, in the most basic case, one phase is a gas and one phase is a liquid. The multiphase fluid often involves three or more substances, such as crude oil, gas, and water. Additionally, Additionally, multiphase fluids can also contain wax, natural gas hydrates, and sand or other particulate. A multiphase pump (MPP) handles multiphase fluids, but it can also pump single phase fluids, such as liquids liquids or gas (for a designated designated period of time). Additional definitions used in multiphase pumping are provided in Sec Sectio tion n 615 615..

612 612 Most Common Common Type Typess and Applications Applications of MPPs MPPs This manual describes the four most common types of MPPs. Other types exist, but are less common and are not discussed. The most common types and applications of MPPs are: • • • •

Twin Screw Pumps Helico-Axial Pu Pumps Prog Progre ress ssin ing g Cav Cavit ity y Pum Pumps ps (PCP (PCPs) s) Elec Electr tric ic Subm Submer ersi sibl blee Pump Pumpss (ESP (ESPs) s)

The most common MPP in the petroleum industry is the twin screw type, and it is usually the type recommended for Chevron applications. Twin screw and helico-axial pumps have been installed onshore at grade, on offshore platforms, and on the seabed floor. PCPs and ESPs have been used mostly in downhole onshore applications and in offshore dry-tree applications supported from platforms. Each type has its own particular application considerations. For example, a helicoaxial MPP usually includes a buffer tank ahead of the pump to minimize the effect of slugs. The other three types do not deploy such a tank. Most of the MPP applications are upstream, pumping from an oil well or oil field. Multiphase pumping applications exist in refineries, as well, such as pumping gaseous liquid from a flare gas knockout drum. As of the writing of this manual, the installation list for the 94 MPPs that Chevron (including legacy-Texaco) has installed is shown in Fig Figure ure 600 600-1 -1..

March 2009




600-5

M a r c h 2 0 0 9

Fig. Fig. 600 600-1 -1 Loc No .

L o c at i o n

No. Pur

Co u n t r y

No. Op er

Op er t g Ye Year s

S er v i c e

Man u f ac t u r er

Pu m p Si Si ze Fl o w (b (b p d e)

GVF (%)

Dif. P (psi)

11

Indian Co Colonial, USA CA

1

1

2001 to P resent G assy Oil/Water Emulsion

Bornemann

MW 7.3

12

E l Tigre (Hamaca) P roduction roduction

Venezuela

2

2

2001 to P resent Gassy C rude

Bornemann

MW 9.3zk to 60,377 53

92

220

El Tigre (Hamaca) P roduction roduction

Venezuela

7

7


Bornemann

MW 9.3zk to 135,698 90

70 to 90


Venezuela

6

6


Bornemann

MW 9.3zk to 135,698 90


Venezuela

5

5


Bornemann

El Tigre (Hamaca) Gathering Station

Venezuela

4

4

1998 to P resent Gassy Watery Crude


Venezuela

4

4

El Tigre (Hamaca) Tran Transfe sferr

Venezuela

4


Venezuela

Boscan Boscan



2 0 0 9 C h e v r o n U . S . A . I n c . A l l r i g h t s r e s e

Chevron Chevron Multipha Multiphase se Pump Pump (MPP (MPP)) Applicat Applications ions (2 of 2) 2)

13

Max RPM

Max B HP

Dr i v e

H2S (ppm)

100

Motor

None

1522

618

Motor

None

268

1760

937

Motor

None

92

268

1760

937

Motor

None

MW 9.3zk to 135,698 90

92

268

1760

937

Motor

None

Flowserve

NLXSHP 5J SR

30 to 40

180

1800

600

Motor

None


Flowserve

NLXSHP 5J SR

30 to 40

180

1200

600

Motor

None

0

2002 to 2005

Flowserve (Failed)

NP S14HP

75,017

10 to

800

1787

1600

Motor

None

5

5

2005 to P resent Gassy Crude

Bornemann

MW 10.6zk

75,017

10 to 20

800

1787

1600

Motor

None

Venezuela

11

11

1998 to P resent Gassy, Sandy (0.75%) Crude

Warren Colfax

GTS 208

20,000

20 to 30

200 to 350 350

Motor

None

Venezuela

4

4

2003 to P resent Gassy Sandy

Warren Colfax

GTS 268

40 000

40

500

Motor

None

Gassy Crude

P u m p M a n u a l

M a r c h 2 0 0 9

Fig. Fig. 600 600-1 -1 Loc No .

L o c at i o n

No. Pur

Co u n t r y

No. Op er

Op er t g Ye Year s

S er v i c e

Man u f ac t u r er

GVF (%)

Pu m p Si Si ze Fl o w (b (b p d e)

Dif. P (psi)

11

Indian Co Colonial, USA CA

1

1

2001 to P resent G assy Oil/Water Emulsion

Bornemann

MW 7.3

12

E l Tigre (Hamaca) P roduction roduction

Venezuela

2

2


Bornemann

MW 9.3zk to 60,377 53

92

220


Venezuela

7

7


Bornemann

MW 9.3zk to 135,698 90

70 to 90


Venezuela

6

6


Bornemann

MW 9.3zk to 135,698 90


Venezuela

5

5


Bornemann


Venezuela

4

4



Venezuela

4

4


Venezuela

4


Venezuela

Boscan Boscan

Max RPM

Max B HP

Dr i v e

H2S (ppm)

100

Motor

None

1522

618

Motor

None

268

1760

937

Motor

None

92

268

1760

937

Motor

None

MW 9.3zk to 135,698 90

92

268

1760

937

Motor

None

Flowserve

NLXSHP 5J SR

30 to 40

180

1800

600

Motor

None


Flowserve

NLXSHP 5J SR

30 to 40

180

1200

600

Motor

None

0

2002 to 2005

Flowserve (Failed)

NP S14HP

75,017

10 to

800

1787

1600

Motor

None

5

5

2005 to P resent Gassy Crude

Bornemann

MW 10.6zk

75,017

10 to 20

800

1787

1600

Motor

None

Venezuela

11

11


Warren Colfax

GTS 208

20,000

20 to 30

200 to 350 350

Motor

None

Venezuela

4

4


Warren Colfax

GTS 268

40,000

40

500

Motor

None

14

Lake Maricaibo Venezuela

1

1

2005 to P resent Gassy, Sandy (<1.0%) Crude

Weatherford

3,000

30 to 70

55

Motor

None

15

Kome

C had

3

3

2003 to P resent Ga Gassy Crude

Leistritz

L4HK 330 to 68,454 126 126

2

Kome

Chad

4

4


Leistritz

L4HK 330 to 156,812 214 214

56

Miandoum

C had

3

3

2003 to P resent Ga G assy Crude

Leistritz

L4HK 330 to 59,558 100 100

Belobo

C had

4

4


Leistritz

Gulf of Thailand Thailand

1

0

2004 to 2008

Bornemann

To t al s

94

79



2 0 0 9 C h e v r o n U . S . A . I n c . A l l r i g h t s r e s e r v e d .

Chevron Chevron Multipha Multiphase se Pump Pump (MPP (MPP)) Applicat Applications ions (2 of 2) 2)

13

16

Gassy Crude

Gassy Crude

1150

215

Motor

None

175

1150

684

Motor

None

2

815

1150

960

Motor

None

L4HK 330 to 133,240 189 189

38

365

1150

615

Motor

None

MP C 268

99

410

??

??

Motor

??

??

6 0 0 - 7


Pu m p Man u al

613 Purpose urpose of of the Manual nual Previously, Previously, some Chevron personnel have been reluctant to install MPPs because they are more comfortable with conventional systems. Among the goals of this manual are to convey the facts about MPPs, along with their applications and benefits, and to improve improve the comfort level of Chevron personnel. To amplify a bit further, the purpose of this manual is to provide: •

Assistan Assistance ce to the following following in unders understand tanding ing MPP techno technology logy and how to apply apply this technology to drive down the cost of production and the handling of mixed oil, water, sand, and gas streams: – – – – –

Upstream, midstream, and downstream downstream facility engineers engineers Reservoir engineers Production engineers engineers Project engineers OPCO discipline engineers engineers Project managers

P u m p M a n u a l

6 0 0 M u l t i p h a s e P u m p s


Pu m p Man u al

613 Purpose urpose of of the Manual nual Previously, Previously, some Chevron personnel have been reluctant to install MPPs because they are more comfortable with conventional systems. Among the goals of this manual are to convey the facts about MPPs, along with their applications and benefits, and to improve improve the comfort level of Chevron personnel. To amplify a bit further, the purpose of this manual is to provide: •

Assistan Assistance ce to the following following in unders understand tanding ing MPP techno technology logy and how to apply apply this technology to drive down the cost of production and the handling of mixed oil, water, sand, and gas streams: – – – – – – – –

Upstream, midstream, and downstream downstream facility engineers engineers Reservoir engineers Production engineers engineers Project engineers OPCO discipline engineers engineers Project managers Business unit managers managers Asset managers

•

A tex textt to to ass assis istt in in spe speci cify fyin ing g MPP MPPs; s;

•

An unde unders rsta tand ndin ing g of of the the econ econom omic icss o off MPPs MPPs;;

•

Exam Exampl ples es of exis existi ting ng MPP MPP app appli lica cati tion ons; s;

•

Scenarios Scenarios that point point to to opport opportunit unities ies for MPPs where they provide provide an an econom economic ic advantage, e.g., onshore, offshore platforms, and subsea;

•

A refere reference nce tool tool for for peopl peoplee to bette betterr learn learn the the techno technolog logy y and econ economi omics cs of multiphase pumping;

•

A teachin teaching g tool tool to to be used in conjun conjunctio ction n with with a “power “power point” point” presentat presentation ion to various organizations organizations to help realize the economic importance of MPPs.

614 614 Upstre Upstream am Oil Field ield Applicat Applications ions In an oil field, MPPs are usually located near an individual well or at a manifold, where production flow lines combine several wells. These pumps may be located onshore, on offshore platforms, on the seabed floor (subsea), or downhole in an oil well. In a traditional surface oil field application, an MPP can replace a conventional system consisting of: • • • • • •

600-8

Separation vessel Gas compressor Pump Gas pr production li line Liquid pr production li line Sand Sand or or part partic icul ulat atee hand handli ling ng sys syste tem m 


Ma r c h 2 0 09

Pu m p Man u al


By comparison, a multiphase pumping system only consists of: •

The MPP MPP itself itself,, with with or or withou withoutt a buffer buffer tank, tank, which which replaces replaces the separat separator, or, the pump, and the compressor;

•

A single single combined combined gas gas and and liquid liquid producti production on line line that replaces replaces the individu individual al gas and oil lines, the gas line being from the compressor discharge and the oil line being from the pump discharge (refer to Fig Figure ure 600 600-2 -2). ).

Fig. 600600-22

Comparison Comparison of Conventiona Conventionall versus MPP Design Design Showing MPP Installation Installation Advan Ad vantag tages es

Conventional Separation

Multiphase In particular, a twin screw multiphase pumping system has the following advantages: • • • • •

One piece piece of of equi equipme pment, nt, the MPP, MPP, inste instead ad of of sever several; al; A singl singlee pipel pipeline ine to the the proc process essing ing facili facility ty,, inste instead ad of of two; two; Sign Signif ific ican antl tly y redu reduce ced d capi capita tall cost cost;; Less weight weight and smaller smaller footp footprint rint than a conven convention tional al system system (important (important for an offshore platform, where weight and space are extremely e xtremely costly); For sub subsea sea,, a simpli simplifie fied d seab seabed ed sup suppor portt struct structure ure..

If gas concentrations and power costs are high, an MPP may not be the most economical choice compared to the conventional system. Each application must be evaluated based on its own economical situation.

March 2009




600-9


Pu m p Man u al

615 Refinery finery Applica Application tionss MPPs are used in refining to pump multiphase fluids having gas content above 5 percent. The bottoms fluid fluid from a flare knockout drum is one one example. MPPs can also replace centrifugal pumps that are not delivering the desired flowrate due to entrained or free gas.

616 616 What Kinds of Pumps Pumps are are MPP MPPs? In the Pump Manual, pumps are generally divided into five categories as shown in Figure Fig ure 600 600-3 -3.. Fig. 600-3

(Courtesy of t he Hydraulic Hydraulic Insti tute) Pump Ca Catego tegorie riess (Courtesy

PUMPS

Centrifugal

Reciprocating Positive Displacement

Rotary Positive Displacement

Metering

Miscellaneous

In Fig Figure ure 600 600-3 -3,, the MPPs described in this manual fit into the centrifugal (helicoaxial pumps and ESPs) and rotary positive displacement (twin screw and PCPs) boxes of the above chart. chart. Kinetic centrifugal pumps can also be classified as in Fig Figure ure 600 600-4 -4.. In Fig Figure ure 600 600-4 -4,, ESPs and helico-axial pumps fall under KINETIC, Centrifugal, Turbine Type, VERTICAL TYPE Single and Multi Stage, Deep Well Turbine (Including Submersibles). Positive displacement pumps are classified in Fig Figure ure 600 600-5 -5.. In Fig Figure ure 600 600-5 -5,, twin screw MPPs are designated as positive displacement, rotary pumps, screw, screw, and multiple. MPP PCPs are designated designated as positive displacement, displacement, rotary pumps, screw, and single.

600-10




Ma r c h 2 0 09

Pu m p Man u al

Fig. Fig. 60 600-4 0-4

March 2009


Kinetic Kinetic Pump Pump Cla Classif ssifica ication tionss (Courtesy (Courtesy of t he Hydraulic Hydraulic Insti tute)




600-11


Fig. 600600-55

Pu m p Man u al

Positive Positive Displace Displacemen mentt Pump Pump Classi Classificat fications ions (Courtesy (Courtesy of t he Hydraulic Hydraulic Insti tute) +25,=217$/

3,6721

6,03/(;

3/81*(5

'83/(;

'28%/( $&7,1*

67($0 9(57,&$/

5(&,352&$7,1* 38036

+25,=217$/

6,1*/( $&7,1*

9(57,&$/

'28%/( $&7,1*

32:(5

3,6721

6,03/(; '83/(;

+25,=217$/ &21752//(' 92/80(

3/81*(5

',$3+5$*0

%/$'(%8&.(7 9$1(

08/7,3/(;

6,03/(;

3,6721 9(57,&$/

326,7,9( ',63/$&(0(17

3/81*(5

'83/(; 0(&+$1,&$//< &283/('

08/7,3/(;

+<'5$8/,&$//< &283/('

5ROOHURU6OLSSHU

%/2:&$6(

3,6721

)/(;,%/( 0(0%(5

/2%(

527$5<38036

 $;,$/  5$',$/

)/(;,%/(78%( )/(;,%/(9$1( )/(;,%/(/,1(5

6,1*/( 08/7,3/(

*($5

(;7(51$/ ,17(51$/

&,5&80)(5(17,$/ 3,6721

6,1*/( 08/7,3/(

6&5(:

6,1*/( 08/7,3/(

617 Concl onclus usio ionn MPP technology is mature. These machines, especially the twin screw type, are reliable. Many have been operating for years with little operator attention. There are currently hundreds of installations throughout the world, with many more in progress and anticipated. anticipated. Chevron alone has had 94 applications in operation operation since 1990. Sec Sectio tion n 61 6120 20 lists and describes several of these installations. Questions or help with a potential MPP application should be addressed to Bob Heyl at: [email protected]. Facilities Engineering Department (FED) 1400 Smith St. Houston, TX Office phone: 713-372-7272 Alternately, Alternately, access contacts at ETC MEPS team at: http://etc.chevron.com/fe-mee/machinery/default.asp

600-12




Ma r c h 2 0 09

Pu m p Man u al


620 Commercia ommercially lly Availa Available ble MPP Types ypes 621 Genera nerall This section describes the four most commonly used types of commercially available MPPs. An MPP is usually installed in an upstream oil field, but they can also be applied in a refinery wherever liquid and gas are combined in a mixed stream and transported. The four types that are described in this manual are summarized in Fig Figure ure 600 600-6 -6.. Fig. ig. 600-6

MPP MPP Summa ummary

MPP Ty p e

Bor Bornemann ann

900,00 ,000

1015

(1) 100(1)

Leistritz

330,000

1450

(1) 100(1)

F lowserve

280,000

1000

(1) 100(1)

F ramo

100,000

900

(1) 100(1)

Sulzer

650,000

1200

(1) 100(1)

Moyno

60,000

900

40

seepex

50,000

600

40

Centrilift

14,000

5000

60

Schlumberger (Reda)

9,000

4000

60

Man u f ac t u r er s

Twin Twin Screw Screw

Helico-Axial

P rogressive Cavity (P CP )

E lectric Submersible (E SP )

1

Max Installed Capacity (bpd)

Max Installed Pressure Differential (psi)

Max GVF (%)

Note: 100% is possible when the the pump pump is supplied with a relatively relatively small small amount amount of externally supplied supplied liquid either either as screw sealant for the twin screw pumps or directly into the flow stream for helico-axial pumps.

Figure Fig ure 600 600-7 -7 includes several additional characteristics.

Comparing t he Four Types of MPPs Figure 600 Figure 600-7 -7 is a general overall comparison of the four types of MPPs. These four types of pumps will be discussed in much more detail in Sec Sectio tion n 62 622 2, Sec Sectio tion n 623 623,, Sectio Sec tion n 624 624,, and Sec and Sectio tion n 625 625..

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600-13


Fig. 600600-77

Pu m p Man u al

Comparis Comparison on of Four Type Typess of Multiphase Multiphase Pumps Pumps (MPP (MPPs) s) Type o f MPP Progressing Cavity Tw i n Sc r ew Hel i c o -A x i al (PCP)

General General Desig n Location

Surface/subsea seabed Mounting orientation Horizontal Rotors and Max Temperature Temperature Rotors Rotors (C (C=contacting, contacting, N N=noncontacting) Max temperature (°F ) 600

Speed Speed (rpm ) Case Removable liners Bearings Drivers

Max GVF (%)

Fluid Flow Slug handling (1=unaffected, 5=greatly affected) Erosion Resistance Resistance (1=very (1=very resistant resis tant,, 5=not resistant) Efficiency Max viscosity (SSU)

Mechanical Seals Number

Maximum capacity (bpd)/ differential pressure (psi) Lubrication

600 to 3,600

Surface/subsea seabed Vertical/horizontal

Surface/downhole (land or sea) Vertical/horizontal

Surface/downhole (land or sea) Vertical

N

C

N

500

300 with elastomeric stator 300 to 550

300 to 400 1,800 to 5,400

No Antifriction

No Sleeve

ASD elect moto otors

ASD elect motors

40% (downhole)

60% with gas separators and handlers

2,000 to 7,000

Yes Ant Antifriction

No Ant Antifriction/tilting pad ASD AS D elect motors, motors, ASD AS D elect motors, motors, nat. gas engines nat. gas engines, hydraulic turbines 100% with external 100% with special screw sealant design features and external liquid supply 1

2 (with buffer tank)

5

5

1

2

4

4

No limit for production or refinery services

300 SSU

No limit for production or refinery services

300 SSU

4 sets (single, or dual dual unpressurized, or dual pressurized) 900,000/1,450

2 sets (one single, one dual pressurized)

1 (single or dual pressurized)

2 sets (single or dual pressurized)

650,000/1,200

60,000/900

14,000/5,000

Self-contained or externally supplied lube oil

Externally supplied SelfSelf-co con ntain ained lub lube oil oil lube oil

Reliability Maintenance Easy (1) or Difficult (5) Field (F) or Shop (S) repair Mean time time between failure failure (Years)

600-14

Electric Submersible



Pump Pumped fluid luid lubricated

3

4

2

5

S 5+

S 3+

F or S 2 to 3

S 2 to 3


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Figure 600 Figure 600-8 -8 is a comparison of the advantages and disadvantages of the four types of MPPs. Fig. 600600-88

Advantages/ Advantages/Disadva Disadvantage ntagess of Four Types of Multiphase Multiphase Pumps (MPP (MPPs) s) Type o f MPP

Ad van tages tag es

Tw i n Sc r ew

Hel i c o -A x i al

Good flow and pressure ranges

Good flow and pressure ranges

One set of mechanical seals

100% GVF with external liquid screw sealant, 95% without

100% GVF with external liquid, 95% without

F ewer bearings than twin twin screw or helico-axial

Reliable

Fairly reliable

Can be repaired in the field

Ero Erosion resistant

Ero Erosion resistant

Slo Slow speed

Self-contained lube oil system Several wells can feed one pump

Disadvantages

Pr og r es s i n g Cav i t y (PCP)

Electric Submersible (ESP) (ESP) 2 sets of mechanical seals

Self-contained lube oil system Several wells can feed one pump

Pumps heavy viscosity oil easily

Pumps heavy viscosity oil easily

Does not tend to form emulsions

Does not tend to form emulsions

4 sets of mechanical seals

2 sets of mechanical seals

Not as reliable as the twin screw or helico-axial

Not as reliable as the twin screw or helico-axial

Usually needs a shop repair

Usually needs a shop repair

Usually deployed downhole, one pump pump per well

Usually deployed downhole, one pump per well

Pressurized lube oil system

Lubricated by the pumped stream

Lubricated by the pumped stream

Not as reliable as the twin screw

Highly susceptible to sand erosion

Highly susceptible to sand erosion

Limited ited flow low rang ange

Limited ited GVF

Limited ited GVF

Viscosity limited to 300 SSU

Viscosity limited to light oil Flow and pressure range limited by the well’s casing size

Ten Tend ds to to form orm emulsions

Flow and pressure range limited by the well’s casing size Ten Tend ds to to for form emulsions Motor and electric cable are downhole causing many problems

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Twin screw pumps and progressing cavity pumps are both classified as rotary positive displacement displacement pumps, each designed designed to API 676. However, However, each supplier will have his own set of exceptions to this specification. Helico-axial pumps are a type of centrifugal pump that combines aspects of axial and centrifugal flow. They are loosely designed in accordance with API 610, but again, suppliers have many exceptions. ESPs are centrifugal or mixed flow types. Various Various API Recommended Practices provide guidelines about sizing, operating, testing, and maintaining. They are listed in Sec Sectio tion n 616 6160 0. Twin screws and PCPs will pump a virtually constant capacity, capacity, regardless of the magnitude of the backpressure, as long as the driver has adequate power. If the pump lacks adequate adequate horsepower to to overcome the backpressure, backpressure, the pump will stall. A pump with adequate power has the potential to overpressure its case or the discharge piping. To To prevent this, a relief or pressure limiting valve is required between the pump’s pump’s discharge flange flange and the discharge block block valve. Pressure relief or pressure limiting valves are always installed if these pumps are used. Unlike rotary positive displacement pumps, helico-axial and ESP pumps use centrifugal force and high velocities to increase pressure at the pump discharge flange. At zero flow or “shutoff”, these pumps provide their greatest discharge discharge pressure. If this pressure pressure is greater than the design design pressure of the discharge discharge pipe, a pressure relief valve must also be installed with with these pumps. For additional information, refer to each type of pump in its specific subsection of this Section 600 and also in other sections of the Pump Manual. An electronic version of the entire Pump Manual can be found at the Chevron Engineering Standards website. Both the twin screw pump and the helico-axial pumps are surface machines located onshore, on offshore platforms, or subsea. They are not deployed downhole. Though the helico-axial pump can handle a higher pressure boost than the twin screw pump, the twin screw pump is superior in almost every other category. Based on the complicated nature of the helico-axial pump and Chevron’s experience at Duri, the twin screw pump has proven itself as the better choice for most applications. See Sec Sectio tion n 613 6138 8 , Lessons Learned for additional reasons. By a wide margin, twin screw pumps are installed in more surface multiphase applications than any other type. The main advantages of a PCP over the twin screw pump and the helico-axial pump is that it involves fewer mechanical seals, has fewer bearings, and can be repaired more easily in the field. A PCP’s maximum flowrate and pressure boost is lower than the twin screw pump or the helico-axial pump. Because the PCP’s rotor continuously contacts the stator, the PCP will wear, and reliability suffers. ESPs and PCPs are usually installed downhole in one well. No matter what installation orientation orientation (vertical or horizontal), they are not considered reliable. Their capacity is designed to match the production of the well, which is definitely lower than the capacity of a twin screw pump or a helico-axial pump. An ESP’s maximum pressure boost may be higher than any of the other three pumps.

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Most all of our industry’s industry’s surface MPP experience has been with twin screw pumps. Indeed, as of 2008, there exist throughout the world 600 twin screw pumps and only 50 helico-axial pumps. Chevron (and legacy-Texaco) legacy-Texaco) experience has also been almost entirely with twin screw MPPs, having installed 88. The initial twin screw pump installations installations were carefully monitored by Chevron to learn as much as possible from each. They are listed listed in Fig Figure ure 600 600-9 -9,, and these installations and others are referred to throughout this manual as examples. Fig. Fig. 600 600-9 -9

Monitore Monitoredd Twin Twin Screw Screw Pump Pump Insta Installati llations ons

Location or Oil Field

Year In s t al l ed

Man u f ac t u r er

Ty p e

1992

Leistritz

Twin Screw

Tested heavy and light oil with varying amounts of water, sand, and GVFs.

2. Trinidad

1992

Leistritz

Twin Screw

P umped a multiphase fluid with an appreciable amount of sand.

3. Mitsue Field, Canada

1993

Leistritz

Twin Screw

Experienced severe slugging from crude oil wells a mile away. Moved to the Princess Field.

4. Prin P rincess cess Field F ield,, Canada

1995

Leistritz

Twin Screw

Moved from Mitsue. P umped multiphase fluids 20 miles to processing facility.

5. Main Pass 313 313 P latform latform,, Gulf G ulf of Mexico

1993

Leistritz

Twin Screw

Decreased wellhead pressure increasing production.

1997

Leistritz

Twin Screw

Decreased wellhead pressure increasing production. Damaged beyond repair in 2006 when over pressured from well rework.

7. Duri Field, Indonesia

1998

Bornemann

Twin Screw

Tested with a Sulzer helico-axial pump to determine which type to buy for the Minas Light Oil Steam Flood project.

8. Duri Field, Indonesia

1998

S ulzer

Helico-axial

Tested with a Bornemann twin screw pump to determine which type to buy for the Minas Light Oil Steam Flood (LOSF) project.

9. El Tigre Field, Venezuela

2005

Bornemann

Twin Screw

Five Bornemann pumps replaced 4 unreliable Flowserve twin screw pumps.

10. Main Pass 59A P latform latform,, Gulf G ulf of Mexico

2007

Leistritz

Twin Screw

Boosts wellhead pressure to match system pressure. The 1,700 HP natural gas engine is the largest currently driving an MPP. MP P.

1. Humble’s Humble’s Flow F low Tes Testt Facil Facilit ity y, Tex Texas as

6. Humble Oil Field, Tex Texas as

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622 Twin Screw crew MP MPP General Twin screw pumps are by far the most common type of surface-installed MPP and the design usually recommended for most petroleum industry applications, including Chevron’s. Chevron’s. These pumps are covered in the third edition of API 676, expected to be published in 2009. Twin screw pumps can be deployed in a refinery or in an upstream oil field whether onshore, on a platform, or subsea on the seabed floor. They are mounted horizontally, horizontally, though attempts at vertical installation downhole in an oil well have been attempted. Unfortunately Unfortunately,, none of these downhole downhole installations installations have proven to operate reliably. reliably. In oil fields, they pump multiphase fluid from a single well or from a discharge manifold supplied by several wells. An external view of an MPP twin screw pump is shown in Fig Figure ure 600 600-10 -10,, and an internal view showing the major components is shown in Figu Figure re 600600-11 11.. Fig. 600 600-1 -100 External External View View of Twin Screw MPP MPP in Minas, Indonesia Indonesia

600-18

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Rotors and Stators As Figur Figuree 600-1 600-11 1 shows, twin screw pumps consist of two rotors side by side, held apart by bearings. The screws are either an integral part of the shaft or manufactured separately and heat shrunk or pressed onto the shaft. Fig. 600600-111 Internal Internal View View of Twin Twin Screw MPP MPP (Courtesy (Courtesy of Leistrit z Pumps) Pumps)

The MPP rotor is stiffer than the rotors in a pure liquid twin screw pump. Unlike a liquid pump, there is no contact between the MPP screws and the stator or case. The possibility of contact contact is further reduced by increasing the clearances to to compensate for either gas slugs or particulate. (Refer to Sec Sectio tion n 634 for design recommendations.)

Speed The speed of the pump is usually 600 rpm to 1,800 rpm, but they have run reliably at 3,600 rpm to achieve higher capacities. Design speed is a function of the service and pumped fluid characteristics. For example, the Chevron Princess Pump ran reliably at 3,600 rpm for years. (Refer to Sec Sectio tion n 613 6135 5 .)

Case The twin screw case is robust. If particulate is present, the case is usually bored to accept a replaceable liner. liner.

Bearings The twin screw uses radial antifriction bearings. Thrust bearings are theoretically not required. However, one of the radial antifriction bearings is designed to handle a minor thrust load that can be present during heavy slugging.

Drivers The most common twin screw driver is an electric motor with an adjustable speed drive (ASD) or often, more specifically, specifically, a variable frequency drive (VFD). Other drivers used are natural gas or diesel engines. Twin Twin screw MPPs are not usually driven by steam or gas turbines. Steam is not usually available at the right conditions in the upstream environment, and the speed, expense, or horsepower of

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600-19


Pu m p Man u al

gas turbines is usually too high for twin screw operation. The driver is coupled to one rotor, and the second rotor is driven by the first through a set of gears at one end of the rotor set.

Gas Volu Volu me Fractio n (GVF) Gas volume fraction is the volume of gas as a percent of the total volume of all the fluids (gas and liquid) at pump suction conditions. A properly designed and applied twin screw pump can pump from 0 to 100 percent GVF indefinitely, with an adequate and reliable supply of a screw sealant. (Refer to the Screw Sealant item at end of this section.)

Fluid Flow As shown in Figu Figure re 600600-11 11,, multiphase fluid enters the twin screw pump at its center. center. The fluid is split into two equal streams, each stream channeled to opposite ends of the case where the fluid enters the screws at suction pressure. The fluid is then pushed to the discharge at the pump’s center. Because the flow is split, with virtually equal portions entering the opposite opposite ends of the screws at the same time, thrust on the pump is theoretically zero. Slugs of liquid following slugs of pure gas are also hydraulically balanced and will not damage the pump.

Erosion Sand and other particulates can cause wear in twin screw pumps by wedging into the clearances between rotors and between the screw edges of each rotor and the case or stator liner. As discussed, these clearances can be adjusted to reduce erosion. Sand in the crude oil may not necessarily cause erosion if the crude oil’s viscosity is high enough and/or the gravity is heavy enough (roughly an API gravity of 30 degrees or lower). For example, a test at Duri, Indonesia, in 1998 1998 showed that sand flowed through the pump without appreciable wear. (Refer to Sec Sectio tion n 637 and Sectio Sec tion n 638 638,, especially Lessons Learned, item A.)

Efficiency There are two definitions of efficiency: mechanical efficiency and volumetric efficiency. efficiency. Mechanical efficiency, expressed as a percent, is simply the theoretical power needed to pump a specified specified flow and pressure, pressure, divided by the actual power power delivered by the driver to the pump’s shaft. Volumetric efficiency is the amount of volume delivered by the pump, divided by the theoretical total amount of volume transferable, again expressed as a percent. Both efficiencies suffer if the internal clearances of a twin screw pump are increased. Larger clearances increase “slip”, defined as the amount of fluid that leaks backward from the high pressure side of each screw flight to the low pressure side. Larger clearances increase slip and reduce efficiency.

600-20

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Pump efficiency can decrease from: • •

• • •

Increa Increased sed cleara clearance ncess to to comp compens ensate ate for partic particula ulate; te; Increa Increased sed clear clearanc ances es to compe compensa nsate te for the the expect expected ed high high operat operating ing temp tempera era-ture, because the MPP handles gas (high GVFs increase the pumping temperature more than low GVFs, requiring greater clearances); Low viscos viscosity ity of gas that that slip slipss more more easi easily ly than than liqui liquid; d; A required required high pump different differential ial pressu pressure re that that increas increases es the the “slip” “slip” within within the the pump; Pump Pumped ed liq liqui uid d whe when n its its vis visco cosi sity ty is low low.

Pump efficiency can increase from: • •

High viscosity viscosity liquid liquid (above (above API 30 gravit gravity) y) that that seals the clearances clearances better better than a low viscosity liquid; Increasing Increasing the pump speed, speed, which which decreases decreases “slip” “slip” and and improves improves efficienc efficiency y.

Mechanical Seals The process fluid in the pump is separated from the outside atmosphere by mechanical seals that, in most designs, seal against pump suction pressure. Except for startup conditions, this pressure is usually low, low, a feature that directionally improves the seal’s reliability. Each twin screw pump has four sets of mechanical seals, one set at the end of each screw. screw. For a dual seal arrangement, this amounts to eight single seals in one pump. Mechanical seals are further discussed in Sec Sectio tion n 632 632.. Seals using the following API 682 seal flush plans have been found to be very reliable: • • •

API Seal Seal Flush Flush Plan Plan 11, 11, or or 31, 31, or or 32 for single single seals; seals; API seal seal plan plan 52 for for unpre unpressu ssuriz rized ed dual dual seal sealss with with a buf buffer fer flui fluid; d; API Seal Seal Flus Flush h Plan Plan 53A, 53A, or 53B, 53B, or or 53C, 53C, or 54 for for press pressuri urized zed dual dual seal sealss with with a barrier fluid.

The type of seal and its required seal flush plan are selected in accordance with the specific field conditions.

Maximum Maximum Capacity and Differential Pressure The maximum designed twin screw MPP capacity currently available is approximately 900,000 bpd. The maximum differential pressure is 1,450 psi. These maximums are not likely to be achieved simultaneously simultaneously or in the same pump, since they are affected by:

March 2009

•

GVF percentage percentage (the higher higher the the GVF GVF, the the lower lower the the rates rates and the different differential ial pressure achievable);

•

Viscosity iscosity of of the liquid liquid (the (the higher higher the visco viscosity sity,, the higher higher the capacity capacity and and differential pressure achievable);

•

Amount Amount and and size size of the particulat particulatee (the (the larger larger the partic particulat ulatee size, size, the the larger larger the the clearances and the amount of slip, reducing the pump’s pump’s capacity and differential pressure achievable). 


600-21


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Lubrication Twin screw pumps use antifriction radial bearings, one of which is ca pable of resisting some thrust. They are enclosed in their own bearing housing. Usually each bearing housing contains contains its own separate separate lubricating oil oil reservoir, although although a centralized forced feed lubrication system is also used on occasion. Chevron requires the lubricating oil to stay below 180°F (82°C) under the worst pumping and atmospheric conditions. conditions. Mineral oil tends to to oxidize, and and for every 10° 10° above 180°F (82°C), the life of mineral is cut in half. There are three ways to alleviate the problem if the atmospheric temperature is hot: •

For a selfself-con contai tained ned bear bearing ing hous housing ing,, this this can be be accompl accomplish ished ed with with an air air cooled bearing housing by attaching a fan to the pump shaft. For example, the Duri pump operated under hot conditions, and its oil temperature stayed below 180°F (82°C) by using an air cooled bearing housing fan.

•

A centra centraliz lized ed force forced d lubric lubricati ation on syste system m can also also be desi designe gned d to keep keep the the oil below 180°F (82°C). For example, example, the MPP in the Mitsue field field used a force feed circulating system.

•

Finally Finally,, syntheti syntheticc oil that allows allows for for a higher higher operating operating temperatur temperaturee will will work work satisfactorily. satisfactorily. However, this could lead to mistakes if operators were to add mineral oil as makeup oil instead of the synthetic oil.

Installation of an RTD or thermocouple in the lube oil of each bearing housing or touching the outer race of each bearing is recommended. If installed at the outer race, the bearing temperature will operate approximately 20° hotter than the lube oil, and the limit should be increased to 200°F (93°C).

Reliability If properly designed and applied, twin screw pumps have proven to be reliable, normally operating longer than 5 years.

Screw Sealant A twin screw MPP always needs liquid to seal the clearances between the screws and the case. Without this liquid, and if not shut down by its high temperature shutdown instrumentation, instrumentation, the MPP will stop pumping, heat up, and seize. This liquid is called screw sealant, and the amount needed is approximately 4 to 5 percent of the pump’s capacity. capacity. This liquid must be contained in the suction suction flow stream or injected either into the suction line or at the ends of each screw at the mechanical seals, such as when supplied by the seal flush liquid.

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623 Helicolico-Axial Axial Pump General Similar to twin screw pumps, helico-axial pumps are found onshore at grade, on offshore platforms, and subsea. They pump multiphase fluid from a single well or from a discharge manifold fed by several wells. These pumps can be mounted in the horizontal or vertical positions. In this pump design, the pump increases pressure using several stages of open impellers that resemble augers or screws. Multiphase fluid moves from one stage to another, helically and axially (parallel to the pump shaft). The external view of a helico-axial pump is shown in Figu Figure re 600-1 600-12 2, and an internal view showing the major components is shown in Fig Figure ure 600 600-13 -13.. Fig. 600600-12 12 External External View of Helico-axia Helico-axiall Pump Installed in Legacy-T Legacy-Texa exaco’s co’s Humble Flow Facility, Before Installation Installation in Duri, Indonesia (1998)

MPP 7-stage helico-axial 125,000 bpd 700 hp motor w/ VFD (3600 rpm)

There are approximately 42 helico-axial pumps throughout the world. At the time of this writing, Framo has 18 installed subsea pumps on the seabed floor, mostly in the Norwegian sector of the North North Sea, plus 2 onshore and 2 on offshore platforms. platforms. Sulzer has built 20 pumps, of which 17 are installed onshore, 2 on offshore platforms, and 1 subsea.

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Rotors and Stators As can be seen in Figu Figure re 600-1 600-13 3 , the rotating element of a helico-axial pump consists of several compression cells, each of which is composed of a rotor attached to the pump’s shaft and a stator attached to the case. The stator redirects the flow into the inlet of the next rotor or compression cell. The number of cells depends upon the differential pressure required. Fig. 600600-13 13 Internal Internal View View of Helico-a Helico-axial xial Pump (Courtesy of Sulzer Pumps)

Speed The speed of these pumps varies from 2,000 rpm to 7,000 rpm. Design speed is a function of the service and the pumped fluid characteristics.

Case The case is a pressure vessel like any multistage centrifugal pump. Unlike the twin screw pump, the case does not have a replaceable liner.

Bearings Radial loads are supported by hydrodynamic or sleeve bearings if the design speeds are greater than 3,600 rpm. At or less than this speed, the bearings are of the antifriction type. Thrust bearings are usually tilting pad or “Kingsbury” type for any speed.

Drivers For most common applications, the pumps are driven by an electric motor. However, However, a natural gas engine or a diesel engine can also be used for surface applications. For subsea, a hydraulic drive or an electric motor is commonly used.

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To reach the higher operating speeds, a gearbox, variable speed coupling, or, for the electric motor, an ASD is required. As with the twin screw pump, changing the speed allows the pump to operate at different capacities. The difference with this pump versus the twin screw pump is that changing the speed also changes the differential head that the pump can produce.

Gas Volu Volu me Fractio n (GVF) A properly designed and applied helico-axial helico-axial pump can pump from 0 to 100 100 percent GVF indefinitely with an adequate and reliable supply of a liquid to the inlet. Note that a pump designed for a low GVF may not pump at all at a high GVF. GVF. (Refer to Sectio Sec tion n 613 6138 8, especially Helico-axial MPP Test Results.)

Fluid Flow Multiphase fluid moves from one stage to another, helically and axially (parallel to the pump shaft). Between each impeller is a stator (diffuser) or set of vanes attached to the pump case that directs the fluid from the discharge of one impeller to the suction of the next. The impeller openings become progressively smaller with each successive stage toward the discharge to compensate for the compression of the gas.

Erosion Sand and other particulates cause wear in a helico-axial pump due to the angle of impact with the rotor and stator. This angle of impact changes depending upon the speed and the flowrate. To reduce wear, wear, the pump is run as slowly as possible and at its best efficiency point. Also, helico-axial pump manufacturers coat their rotors and stators with a hard material, such as tungsten carbide, or they gas harden them with nitride or boride gas to minimize erosion.

Efficiency The mechanical efficiency of a helico-axial pump is usually lower than that of the twin screw pump. This is especially true at higher viscosities (greater than 300 SSU), where centrifugal pump efficiencies fall off dramatically dramatically.. For example, at Duri, the mechanical efficiency of the helico-axial pump was 22 percent, while that of the twin screw pump was 45 percent. (Refer to Sec Sectio tion n 613 6138 8.)

Mechanical Seals In Figu Figure re 600600-13 13,, the mechanical seal system consists of a mechanical seal at both the motor and outboard ends.

Maximum Maximum Capacity and Differential Pressure The maximum pump capacity is approximately 650,000 bpd with multiphase fluid measured at inlet conditions. Maximum pump differential pressure is approximately 1,200 psi. As with the twin screw pumps, these maximums are independent of each other and are not likely to b e achievable simultaneously or even with the same pump.

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These maximums are affected by: • •

Viscosity iscosity of the the liquid liquid (the lower lower the viscosity viscosity,, the higher higher the the rates rates and differen differen-tial pressures achievable); Percen Percentt gas in in the flui fluid d (GVF). (GVF). (The (The highe higherr the GVF GVF,, the lowe lowerr the rate ratess and differential pressures achievable. For example, a helico-axial pump produces half the differential pressure if the GVF increases from 80 to 90 percent and half of that if it increases to 95 percent.)

Lubrication A circulating lubrication system is required to cool and lubricate all the bearings. It usually consists of a reservoir, lube oil pump, cooler, filters, and associated alarms and other instrument devices.

Reliability The helico-axial pump is complicated by its circulating lubrication system and high speed. These complications have been known to affect pump reliability. reliability. For example, the side by side twin screw and helico-axial pump tests at Duri demonstrated how this complexity can cause problems. (Refer to Sec Sectio tion n 613 6138 8 .)

Buffer Tank Slugs of liquid or slugs of gas are common for any MPP stream, but unlike the twin screw pump, in which the flow is split to balance slugging, the helico-axial pump often uses a “buffer” tank (actually a vessel) installed ahead of the pump. The “buffer” tank dampens the effect of any slug and allows the pump to operate with a lower thrust bearing capacity. The buffer tank also causes the gas and liquid to become more homogeneous before before entering the pump and and provides some residence residence time enabling particulate to settle out. Fig Figure ure 600 600-14 -14 shows such a buffer tank. Note the stand pipe in the center of the tank, which has holes for gas to enter into the liquid stream going through the stand pipe. Fig. Fig. 600 600-1 -144 “Buffer” “Buffer” Tank ank (Courtesy of Sulzer Pumps)

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624 624 Progressing Cavity Cavity Pump Pump (PCP (PCP)) or Single Single Screw Screw Pump Pump General Multiphase PCPs are usually installed horizontally on the surface. They can also be installed vertically, vertically, downhole in a single well, driven by a long shaft with an electric motor from the surface. Like the twin screw pump, the PCP is a positive displacement (PD) pump. The detailed comments made about PD pumps in the twin screw section apply to these pumps, as well, including overpressuring potential and the need for a pressure limiting valve in the discharge piping before the first discharge block valve. External views of the progressing cavity pump are shown in Figu Figure re 600600-15 15 (horizontal orientation) and Fig and Figure ure 600 600-16 -16 (vertical orientation). Internal views of the major components are shown in Fig Figure ure 600 600-17 -17 and Fig and Figure ure 600 600-18 -18.. Fig. 600600-15 15 Externa Externall View View of PCP (Courtesy of Tarby Pumps)

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Fig. 600600-16 16 External External View View of PCP PCP in Downhole Downhole s eepex) x) Orientation (Courtesy of seepe


600-27


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Fig. 600600-17 17 Intern Internal al View View of PCP PCP (Courtesy of Tarby Pumps)

Fig. 600 600-1 -188 Internal Internal View View of PCP in Downhole Orientation Orientation (Courtesy of Robbi ns and Myers, Inc.” makers of Moyno pumps)

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Rotor and Stators (Including Elastomeric Stators) The progressing cavity pump is essentially a single, serpentine screw rotor that revolves inside a stationary liner called the stator. With rare exceptions, the stator is an elastomer, while the rotor is a hardened steel alloy. Unlike the screws in a twin screw pump, the rotor is in intimate contact with the stator. stator. Continuous lubrication between the two is absolutely absolutely necessary to prevent prevent excessive heat buildup buildup between the rotor and the stator and corresponding wear. wear. Tests for elastomeric decompression and swelling must be run to determine the compatibility of the elastomeric stator with the pumped fluid and to avoid excessive heat buildup. Elastomeric Decompression. In some cases, the elastomeric stator becomes infused with the pumped gas during normal operation. If this occurs, the stators can be destroyed from the explosive explosive decompression of the infused gas as the the pump is de-pressured. To To prevent this and to decide if a proposed stator is acceptable, a compatibility test is required before finalizing the selection of the elastomer. elastomer. The test involves placing an actual sample (usually crude oil and gas) in an enclosed pressurized chamber with the the proposed elastomer. elastomer. After an elapsed elapsed period of time, the chamber pressure is lowered to determine if any of the infused gas destroys the elastomer. Elastomeric Swelling. The elastomeric stator can also swell from the multiphase fluid’s chemistry. When purchasing a PCP, the amount of elastomeric swelling must be tested for fluid compatibility compatibility.. This swelling, if any, any, increases increases the contact pressure pressure between the rotor and the the stator and must be considered considered in sizing the bore bore of the stator. stator. If the allowance for swelling is not enough, the contacting force will be excessive, overheating the stator and causing the pump to fail. If the design allowance for swelling is too large, the pump will not reach its design capacity. capacity. Elastomer selection is therefore a major concern. Choosing an elastomer that is compatible with the pumped fluid, preferably with no gas infusion and no swelling, is vital to the life and performance of the pump.

Speed PCPs run at slow speeds, usually from 300 rpm to a maximum 550 rpm. This slow speed is required due the intimate contact between the rotor and the stator.

Case The case material for these pumps is usually carbon steel, but other materials can be provided, if required, and 316 316 SS is often recommended. With With one rare design exception, the case is lined with the elastomer. (Refer to General in Sec Sectio tion n 624 and Metal to Metal PCP in Sec Sectio tion n 614 6144 4.)

Bearings One set of antifriction bearings is provided on the motor end for radial and thrust located between the mechanical seal and the coupling.

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Drivers These pumps are usually electric motor driven with either an ASD or a gear set to reduce the speed and to adjust the capacity. Like the twin screw pump, the ASD allows the PCP to operate at different speeds and different capacities, enabling it to match the well’s production from its initial flowrate throughout its lifetime.

GVF A PCP cannot operate without liquid. If this occurs, the rotor will grab the elastomeric stator, stator, causing intense friction and heat, which will immediately destroy the stator. For this reason, and based on Chevron experience, a PCP should be limited to a 30 percent GVF (unless an adequate and reliable external or recyled liquid stream is introduced into the suction, in which case, the inlet stream’s stream’s GVF may be raised to 40 percent). (Note that some supplier’s marketing documents promote using the pumps pumps at GVFs as high as 99 percent in research tests with with specialized elastomers for the stator and coatings for the rotor to reduce friction and heat. Due to Chevron’s Chevron’s experience with stator failures from transient conditions in the field which caused the pump to run dry, dry, it is strongly recommended that the GVF be limited to a maximum of 40 percent.)

Fluid Flow Fluid is displaced from inlet to outlet as the gas/liquid mixture is trapped in cavities that are formed between the rotor and the stator. Unlike the helico-axial pump, one of the advantages of the PCP is that the flow is uniform, with low shear, meaning that tight emulsions will not be formed by the PCP.

Erosion Particulate in the pumped stream will become partially embedded in the elastomeric stator. stator. The particulate will contact the rotor with each revolution, causing wear, and increasing the slip, with the resulting loss of the pump’s pump’s capacity and differential pressure.

Efficiency As with all PD pumps, the volumetric efficiency is high until wear and slip occur.

Mechanical Seal A surface PCP can use a single seal or a pressurized dual seal. In some of the earlier applications, packing was used by companies other than Chevron. Packing is not recommended due to the required leakage of the pumped fluid as lubricant for the packing. This leakage leakage causes safety and environmental environmental concerns. Also, if the the packing fails, gas and liquid liquid will be released, released, causing an even more severe concern. concern.

Maximum Maximum Capacity and Diff erential Pressure The maximum capacity of a surface PCP MPP can be as high as 60,000 bpd, and the maximum differential pressure can be 900 psi, again not with the same pump. The reasons are the same as previously described for the twin screw and helico-axial pumps.

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Lubrication PCPs usually have one set of bearings contained in a bearing housing and lubricated by oil or grease. In a vertical downhole downhole application, application, the shaft is centered in the the tubing by bushings which are product lubricated.

Reliability The mean time between failures averages 2 years to 3 years. The most common failure mode is the elastomeric stator, followed by mechanical seals. Unlike a twin screw pump or a helico-axial pump, a PCP pump is often repaired in the field.

625 625 Electric lectric Subme Submersible rsible Pump Pump (ESP (ESP)) General An ESP is a multistage, centrifugal or axial flow pump that is almost always installed downhole in an oil well. The ESP pump itself typically consists of many small diameter impellers on a shaft, with product lubricated sleeve bearings between each impeller. The entire unit can be 100 or more feet long. ESPs have been installed on the surface, in a horizontal position, but this is NOT recommended as their reliability in this has been unsatisfactory. An ESP fits in an oil well caisson, and therefore, its diameter and capacity are restricted. The suction is from the well through a screened inlet, and the discharge flows directly into the production tubing. tubing. An external view of a vertical downhole electric submersible pump is shown in Figuree 600Figur 600-19 19,, and an internal view is shown in Figu Figure re 600600-20 20.. Not all multiphase ESP pumps will necessarily have all these components.

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Fig. 600 600-1 -199 External External View View of Vertical Vertical Electrical Submersible Submersible Pump Pump (Courtesy (Courtesy of Schlumberger) Schlumberger)

Fig. 600 600-2 -200 Cross-Sectiona Cross-Sectionall View of Vertical Vertical Electrical Electrical Submersible Pump Pump (Courtesy (Courtesy of Schlumberger) Schlumberger)

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Rotors and Stators (includ ing Gas Separators Separators and Gas Gas Handlers) An ESP assembly for a multiphase application, from bottom to top, consists of an electric motor, a protector (seal), a gas separator, often a gas handler, and the ESP pump itself. Like helico-axial helico-axial pumps, the number of of ESP impeller stages is chosen chosen to meet the design differential pressure. To To do this, the pumps generally require numerous stages. All this makes the overall length of the pump and motor long, over 100 feet in some cases. ESPs can be outfitted with a variety of devices to separate the gas from the multiphase fluid stream. A gas separator is usually a centrifugal or rotary device installed between the motor and the pump. It vents the separated gas into the annulus between the caisson and pump above the liquid level. A gas handler can be connected between the gas separator and the ESP. ESP. It increases the suction pressure to the ESP, re-liquefying re-liquefying some of the gas and lowering the GVF to the ESP. ESP. It also decreases the size of the remaining gas bubbles and homogenizes the mixture. The protector is described in this section in Bearings and in Protector or Seal System.

Speed Speeds range from 1,800 rpm to 5,400 rpm using an ASD.

Case Case diameter and therefore the impeller diameter is determined by the size of the caisson. Case material is normally carbon steel which can be coated or replaced with proprietary materials. (Refer to Sec Sectio tion n 680 for details.)

Bearings ESPs have sleeve bearings that are lubricated by the fluid being pumped. In the preferred design, a bearing exists exists between each impeller, impeller, and therefore, the the number of bearings is equal to the number of impellers, as many as 300 in some cases. This bearing arrangement is only only in the preferred design and must be specified. Unlike Unlike the ESP itself, the electric motor is oil lubricated, made possible by a “seal bag” in the protector or seal system section. Included below the “seal bag” is the pump’s thrust bearing, also lubricated by oil.

Driver An ESP is driven by an electric motor, also installed downhole. The ESP motor is installed below the pump, with the pumped fluid flowing around the motor before it enters the pump’s suction. This design is intended to provide needed cooling for the motor. motor. However, this can cause problems, as the motor will not be adequately cooled by streams containing a high GVF or streams containing a high percentage of particulate. With high GVF streams, the gas provides insufficient heat transfer, while for high particulate streams, the particulate coats or packs around the motor, severely restricting heat transfer. transfer. For this reason, most ESP MPP manufacturers recommend that the pump be controlled or shut down based on high motor temperatures instead of traditional high motor amperes.

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As with the other pumps described earlier, ESPs are often controlled by ASDs. The ASD allows the pump to operate at different speeds and different capacities. As with any centrifugal pump, controlling the pump speed means the pump will operate on a different head/capacity curve, which can present problems for operations.

GVF Based on Chevron experience, the GVF for an ESP (without special gas separation devices) should be limited to 40 percent, even though manufacturers’ marketing brochures indicate indicate that they can handle GVFs GVFs as high as 90 percent with with specialized gas separators and gas handlers. Based on Chevron experience, if these devices are included for actual field operations use, the GVF should be limited to 60 percent.

Fluid Flow Fluid flows vertically upward, past the motor into the gas separator, then into the gas handler (when supplied), and finally into the ESP itself. The fluid gains pressure through each impeller and diffuser stage. After leaving the last stage, the fluid discharges into the production tubing.

Erosion Particulate causes erosion to the impellers and, to a larger extent, to the bearings, causing them to wear rapidly. Mean time between failures can be as low as a few months, depending on the amount of sand being pumped.

Efficiency The mechanical efficiency of an ESP is usually lower than the twin screw pump. This is especially true at higher viscosities (above 300 SSU), at which centrifugal pump efficiencies fall fall off dramatically. dramatically.

Protector o r Seal Seal System As mentioned, a protector exists between the motor and gas separator. separator. Located in the protector is a “seal bag” that protects and segregates the motor’s lubricating oil from the produced fluid, and it also equalizes e qualizes the motor’s pressure to that of the pump. Also, the protector protector houses an oil lubricated thrust thrust bearing to handle handle the thrust from the ESP.

Maximum Maximum Capacity and Diff erential Pressure ESP stages are added or subtracted such that the pump’s pressure matches production pressure pressure requirements. Increasing the the impeller diameter increases the the pump’s pump’s capacity. capacity. However, the impeller impeller diameter is limited limited by the caisson size. Pumps can be designed for increased speed to raise their capacity. Maximum rates are 14,000 bpd, and one of the manufacturers claims that its ESP can develop a differential pressure up to 5,000 psi.

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Reliability Typically, ypically, ESPs are pulled from the well every 2 years to 3 years for required maintenance. Despite attempts to improve reliability, reliability, ESPs are not reliable for a variety of reasons, some of which are as follows: •

ESPs experience experience electrical electrical cable shorting shorting problems, problems, motor problems, problems, bearing bearing problems, seal bag problems, and other mechanical mechanical problems all made worse worse by higher downhole temperatures, corrosion, erosion, and gas.

•

They are often often installed installed in a deviated deviated or slanted slanted well. well. Installi Installing ng them them in in nonver nonver-tical orientations causes the bearings to wear unevenly and more quickly. quickly.

•

As previ previous ously ly discu discusse ssed, d, radia radiall sleeve sleeve beari bearings ngs (as (as many many as 300 in in some some cases) cases) are lubricated by the fluid being pumped. If the fluid contains particulate, the particulate enters the bearing with resultant wear. wear.

•

If the the fluid fluid has a high high GVF GVF,, the the bearings bearings will not be adequa adequately tely lubricated lubricated,, causing premature failure.

Horizontal installation of these pumps negatively affects the reliability, reliability, as well. The horizontal position, the long pump shaft length, and the increased probability of misalignment cause the bearings to wear unevenly and more rapidly than if located in the vertical position.

626 626 Genera Generall MPP MPP Selection Selection Guidelines Guidelines As stated earlier, an MPP is a single piece of equipment used to pump oil, water, gas, and sand. It is most often the economical choice for liquid with a GVF greater than 5 percent. The flowcharts shown in Fig Figure ure 600 600-21 -21,, Fig Figure ure 600 600-22 -22,, Fig Figure ure 600 600-23 -23,, and Figure Fig ure 600 600-24 -24 provide a general guideline for selecting an MPP for a particular generic application. They are meant to provide some guidance but are not to be taken as the final determining factor in the selection of a particular type of MPP. If an MPP installation is considered, an ETC specialist or a local expert should be consulted.

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Fig. 600 600-2 -211 Pump Sele Selection ction Flowcha Flowchart rt I need an MPP N=No

Y=Yes Y

Onshore or Platform

N

N

Y Subsea

Y

Seabed

Y

N Downhole

N Downhole

Y

Depth < 5500 ft

Above Ground

Y

N

Wet Tree

Y Y

See SME N

ESP Go to Sheet C

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Go to Sheet C

Go to Sheet A

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Fig. 600600-22 22 Pump Sele Selection ction Flowchart Sheet Sheet A Sheet A

Y

Viscosity at All Design Conditions < 300 SSU

Y

Viscosit Viscosity y at Any Design Condition > 300 SSU

Y

N

Particulate > 0.01 wt%

N

N Y

Go to Sheet B

Y

Y

Y

Total Flow < 500,000 bpd

Flowing T < 300 F

GVF < 95%

N

N

N

Helico-axial

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Specially Designed Helico-axial System See SME

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Fig. 600600-23 23 Pump Sele Selection ction Flowchart Sheet Sheet B Sheet B

Y

DP < 1,400 psi

N

Y

GVF < 95%

N

Y

FT < 600F

N


N

Y

Specially Designed Twin Screw System See SME

Twin Screw

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Fig. 600600-24 24 Pump Sele Selection ction Flowchart Sheet Sheet C Sheet C

Y

Y


N

GVF < 40%

N

Y T < 300F

Y

N

N GVF < 60%

DP < 900 psi

N

Y

ESP

See SME

PCP or ESP

630 Design sign Reco Recomm mmeenda ndations tions 631 Genera nerall Most of Chevron MPP experience has been with twin screw pumps because they are the most versatile, reliable, and appropriate pumps for most Company applications. While most of the recommendations in this section pertain to all types of MPP designs, some apply only to twin screw pumps and are so noted.

632 Mechanica chanicall Se Seals The subject of mechanical seals is complex. The following is a brief discussion of mechanical seals as they apply to MPPs. Mechanical seals used in MPPs should be purchased in accordance with Chevron specification PMP-SC-4662, which modifies API 682. API 682, Annex A, provides a good tutorial on seals, their usage, and selection procedures. Both the Chevron standard and API 682 discuss aspects of mechanical seals, including materials, seal part codes, flush plans, plans, auxiliary hardware, and more.

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Chevron has a PSA with both John Crane and Flowserve. These agreements include a seal selection guide. A copy of the guide exists in the Chevron Pump Manual — — Engineering Guidelines (Gray Book), Section 850. Bergmann also makes a quality mechanical seal and has extensive experience applying them to MPPs. The following types of mechanical seals and API seal plans are commonly used in MPPs (refer to API 682 for details): •

Single Single Seals Seals (using (using an API API Seal Seal Flush Flush Plan Plan 11 as sho shown wn in in Fig Figure ure 600 600-25 -25,, Seal Flush Plan 31 as shown in Figu Figure re 600600-26 26,, or Seal Flush Plan 32 as shown in Figure Fig ure 600 600-27 -27). ).

•

Unpres Unpressur surize ized d Dual Dual Seals Seals (with (with a buffe bufferr fluid fluid using using API API Seal Seal Flush Flush Plan Plan 52 as as shown in Fig Figure ure 600 600-28 -28). ).

•

Pressu Pressuriz rized ed Dual Dual Seals Seals (wit (with h a barrie barrierr fluid fluid using using API API Seal Seal Flush Flush Plan Plan 53A as shown in Fig Figure ure 600 600-29 -29 or Seal Flush Plan 53B as shown in Figu Figure re 600-3 600-30 0 or Seal Flush Plan 53C as shown in Figu Figure re 600-3 600-31 1 or Seal Flush Plan 54 as shown in Fig Figure ure 600 600-32 -32). ).

The following paragraphs illustrate examples of the various seal types. They are termed examples, since many different seal arrangements of each type are possible. The specific arrangement depends on such conditions as the amount of particulate, the temperature, and the hazardous composition (if it is hazardous) of the pumped stream. For example, in a single seal, the normal seal with several small springs (pusher type) may be replaced by a bellows seal designed for high temperatures. In another case, due to the amount of particulate in the stream, the standard Type C stationary bellows assembly may need to be switched to one one that rotates so the bellows bellows does not get clogged with particulate.

Single Mechanical Seals All mechanical seals rely on liquid to lubricate and cool the seal faces. Without a thin film of liquid, the seal faces make contact, heat up, and fail. In an MPP, the pumped fluid usually usually contains a significant significant amount of gas, including including periods of 100 percent gas slugging. Gas does not adequately cool cool and lubricate the seal faces. Thus, for a single seal without special design considerations, seal failure is likely. likely. Seal failure will usually result in leakage of the pumped fluid (including its gas phase) to the atmosphere. atmosphere. In MPPs, a single seal can be used if it includes an internal close clearance throat bushing inside inside the seal chamber and other special special design techniques. techniques. The extent of these other design techniques employed depends upon the percentage of GVF and the amount of particulate in the pumped stream. This single seal design is simpler and less expensive than a dual seal, and therefore, it is usually the type recommended for most MPP applications.

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With the use of the internal close clearance throat bushing inside the seal chamber, seal flush flows through the close clearance into the MPP. The bushing’s clearance is designed to keep the pressure in the seal chamber 20 psi or so above the pump’s internal pressure. The purpose of the bushing is to prevent any gas from being released to the atmosphere if the single seal fails. If it fails, only the liquid flush would be released. This same flush can also act as screw sealant for a twin screw pump. The following are four API seal flush plans that can be used in conjunction with the close clearance throat bushing: •

API Flus Flush h Plan Plan 11: 11: If the the multi multipha phase se strea stream m contai contains ns no part particu iculat latee and is is below 200°F (93.3°C), API API Seal Flush Plan 11 11 is acceptable. This plan takes takes a liquid flush from the pump discharge and returns it across the seal faces. The discharge line is enlarged as required to trap liquid that is recycled from the bottom of the line, line, where the liquid has settled, back to the seals. Enough liquid needs to be trapped to enable the appropriate seal flush liquid to be available during normal GVF conditions and during design periods of 100 percent gas slugs. (In the Bornemann twin screw pumps, the fluid is trapped inside the pump case itself.) (Refer to Fig Figure ure 60 600-2 0-25 5 in this section.)

Fig. 600600-25 25 API Sea Seall Flush Plan Plan 11 11 (Courtesy of John Jo hn Crane) Crane)

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•

API Flus Flush h Plan Plan 21: 21: If flash flashing ing is expec expected ted in in API Seal Seal Flus Flush h Plan Plan 11, 11, a coole cooler r will be required. API Seal Flush Plan 21 is the same as Seal Flush Plan 11 only with the cooler added.

•

API Flus Flush h Plan Plan 31: If If a small small amoun amountt of part particu iculat latee (less (less than than 0.01 0.01 wt. wt. %) is present and the discharge discharge fluid is below 200°F 200°F (93.3°C), API Seal Flush Plan 31 is often used. This plan also takes a liquid flush from the enlarged discharge line through a centrifuge or cyclone separator back to the seals. The centrifuge

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separates the particulate from the pumped liquid and rejects the particulate back to the pump’s suction. Note that for the centrifuge to work properly there must be a large difference difference between the gravities of the particulate and the fluid fluid being pumped. Carbon, for example, will will not centrifuge out, but but sand will. (Refer to Figure Fig ure 600 600-26 -26 in this section.) Fig. 600600-26 26 API Seal Seal Flush Flush Plan 31 (Courtesy of John J ohn Crane)

•

API Flus Flush h Plan Plan 32: If If parti particul culate ate is is presen presentt in amoun amounts ts above above 0.01 0.01 wt. wt. %, an an external liquid flush (API Seal Flush Plan 32) is recommended. This approach involves a continuous, clean, 100 percent liquid stream from an external source that enters the seal cavity to cool c ool and lubricate. Water Water is often used for the flush. (Refer to Fig Figure ure 600 600-27 -27 in this section.)

Fig. 600600-27 27 API Seal Seal Flush Flush Plan 32 (Courtesy of John J ohn Crane)

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Dual Mechanical Seals Dual seals are more complicated and more expensive than single seals, and therefore, single seals are more common and preferred. However, except in extremely specialized circumstances, dual seals are still considered necessary for safety reasons when H 2S or other hazardous components are present or if the pumped stream will auto-ignite auto-ignite upon seal leakage. leakage. Unpressurized Dual Mechanical Seals. An unpressurized dual seal consists of two separate mechanical seals, with a buffer fluid circulated between the seals. It is shown in API Standard 682, Seal Flush Plan 52. (Also refer to Fig Figure ure 600 600-28 -28 in this section.) Fig. 600600-28 28 API Seal Seal Flush Flush Plan Plan 52 (Courtesy (Courtesy of John Crane)

The buffer fluid supplied is intended to be more environmentally benign and safer for personnel than the pumped fluid. The buffer fluid, by definition, has a pressure below that of the seal chamber and and provides a flush fluid fluid which lubricates lubricates and cools the outer seal faces. The inner seal flush is provided by any of the seal plans covered under the single seal section above. If the inner seal leaks, the pumped fluid (if it does not flash as its pressure is reduced) will flow from the seal chamber into the buffer fluid reservoir, reservoir, raising its level, and setting setting off a high high level alarm. If the pumped fluid flashes flashes as it enters the reservoir, reservoir, the pressure in the buffer buffer fluid reservoir increases, and a high pressure alarm is initiated. If the outer seal leaks, the more benign buffer fluid will leak to the environment, the reservoir level will drop, a low level switch will alarm, and the pump will shut down. The pumped fluid will not leak to the atmosphere unless both the inner and outer seals leak at the same time. The circulating buffer fluid system consists of a reservoir with a cooler inside, level switches, a pressure gage, an orifice, and assorted valves. The buffer fluid circulates from the reservoir into the chamber between the two seals and then back to the reservoir.

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Pressurized Dual Mechanical Seals. An example of a pressurized dual seal consists of two separate mechanical seals, with a relatively benign barrier fluid circulated between the seals to lubricate and cool both the inner and outer seal faces. The barrier fluid pressure is kept above the seal chamber pressure, which is usually about suction pressure. Thus, if the inner seal leaks, the barrier fluid flows into the pumped fluid. If an outboard outboard seal leaks, barrier fluid flows to the atmosphere. atmosphere. In both cases, the barrier fluid fluid reservoir level will drop, drop, and instrumentation instrumentation in it will shut down the pump. The pumped fluid will not leak to the atmosphere unless both seals leak simultaneously.

For an illustration in the form of a figure, refer in this section to API Seal Flush Plan Plan 53A (see (see Fig Figure ure 600 600-29 -29), ), Plan 53B (see Figu Figure re 600-3 600-30 0), Plan 53C (see Figure Figu re 600-3 600-31 1), and Plan 54 (see Fig Figure ure 600 600-32 -32). ). Jo hn Crane) Fig. 600600-29 29 API Seal Seal Flush Flush Plan 53A 53A (Courtesy of John

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Fig. 600600-30 30 API Seal Seal Flush Flush Plan Plan 53B (Courtesy of John J ohn Crane)

J ohn Crane) Fig. 600600-31 31 API Seal Seal Flush Flush Plan Plan 53C (Courtesy of John

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Fig. 600600-32 32 API Seal Seal Flush Flush Plan 54 (Courtesy of John J ohn Crane)

The circulating barrier fluid system consists of a pumping ring, a reservoir with an internal cooler, several level switches, a pressure gage, a pressure switch, and assorted valves. The barrier fluid circulates from the reservoir into the seal chamber between the two seals and and then back to the reservoir. reservoir. The pressure switch keeps the barrier fluid pressure above the pump’s pump’s seal chamber pressure, which is slightly slightly above pump suction suction pressure. If the pressure pressure switch malfunctions, the barrier fluid pressure can become lower than the suction pressure. This is called pressure reversal. Pressure reversal will likely overcome the closing pressure of the springs springs and open the faces, creating a leak. leak. If purchasing dual seals, seals, this situation should be considered, especially for startup conditions. The amount of pressure reversal that the the seal can handle before leaking leaking should be recorded by the the supplier on the seal data sheets. Suction pressure is highest immediately before and during the startup of an MPP. After startup, the MPP lowers the suction pressure. The barrier fluid must be designed to operate above the highest possible suction and seal chamber pressure expected. There are a number of other components in this barrier fluid system, not shown in the API figure, including automatic shutdowns to prevent leakage to the atmosphere. Comparison of the Seal Types. As mentioned earlier, the single seal with the close clearance bushing is the most common, because it is simpler and less expensive than the dual seals. The next most common is the pressurized dual seal, used where H 2S or other toxic components are included in the MPP stream. The least common is the unpressurized dual seal. The only known application that comes close to the API unpressurized dual seal is the Bornemann “poor man’s” mechanical seal. The inner seal is the same as one would expect in an unpressurized dual seal. The outboard seal is a contacting lip seal, which, not being a mechanical seal, differentiates it from an API unpressurized dual seal. The area between the seals is flushed with an unpressurized buffer fluid at atmospheric pressure. (For more details, refer to Mechanical Seals in Sec Sectio tion n 652 652.) .)

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Materials Materials f or Mechanical Mechanical Seals Seals The standard mechanical seal faces are silicon carbide for the seal ring (flexible spring mounted seal face) and carbon for the mating ring. Silicon carbide is generally selected, since it has high hardness, excellent corrosion resistance, high thermal conductivity, conductivity, and a low coefficient of friction against carbon. It comes in two types, reaction bonded silicon carbide and self-sintered silicon carbide. Reaction bonded silicon carbide is preferred, since it has a lower coefficient of friction against carbon, is less brittle, and is not as hard. It is more suitable for fluids that have a pH from 4 to 11. Silicon carbide has a maximum temperature of 800°F (426.7°C). Tungsten Tungsten carbide is also used as a seal ring material instead of the silicon carbide to run against the carbon mating ring. It has a maximum temperature of 750°F (398.9°C). Seals with silicon carbide or tungsten carbide running against carbon are standard seal offerings and are usually satisfactory if the pumped fluid temperatures are below 750°F (398.9°C) (398.9°C) and little or no particulate particulate is present. Two hard faces, such as tungsten carbide versus silicon carbide, are required if sand or other abrasives are contained in the pumped stream. Unless it is certain that no particulate is present, present, tungsten carbide versus silicon carbide should should be used with API Seal Flush Plans 11, 31, 32, 52, 53A, 53B, 53C, and 54. This face to face combination runs well, even in abrasive water streams. Of course, the toughest application is a problem when the pump and its seal must exist in a remote location pumping a hot, high GVF stream (90 percent and above) containing particulate (quartz) and without access to a clean, cool, external seal flush. In this case, the pumped fluid must be used as the seal flush. The most experienced seal design to date would run hard face against hard face, usually tungsten carbide vs. silicon carbide. Diamond seals (running diamond face against diamond face) have been developed recently, recently, and experience is being accumulated which preliminarily indicates that these seals will likely be the seal face material of choice for this application in the future. Today, Today, however, there is little experience with these seals, and they are not yet recommended. With or without the diamond seal, the seal flush would come from a downstream separator vessel or from the bottom of the enlarged enlarged discharge line line acting as a separator. separator. Again, this enlarged enlarged discharge line segment needs to be designed so that it has enough residence time to knock out the required amount of seal flush liquid to sustain the seals during normal multiphase operating conditions and during design periods of 100 percent gas slugging. Another new seal developed by Chevron for this application is a single mechanical seal, cooled and lubricated by grease fed from a canister. This type of seal was tested for several years at the Chevron Humble facility and found to be reliable. However, the seal is not patented and has not yet been deployed commercially. Testing was only performed on suction pressures of approximately 6 psi. Both the grease canister seal and the diamond seal are discussed in Sec Sectio tion n 614 6146 6, specifically in Grease Canister Seal Flush System.

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Refer to the Chevron Pump Manual —Engineering —Engineering Guidelines Guidelines (Gray Book), Section 800, and API 682, and Chevron Chevron API 682 exception specification, PMP-SC-4662, for an in depth discussion on all types of mechanical seals and the various seal flush plans.

633 633 Screw crew Seal Sealant ant for Twin Twin Screw Screw Pumps In a twin screw pump, the screws are held apart by bearings with only 0.008 inch to 0.010 inch clearance between the screws and with the same clearance between the screws and the pump case or liner. liner. Liquid must fill these clearances. This liquid is often called screw sealant. The design flowrate of the screw sealant must reliably deliver 4 to 5 percent of the pump’s design capacity or the pump will vapor lock, stop pumping, heat up, have internal rubbing between the rotors and stators, and cause severe damage. Screw sealant can be supplied by the liquid portion of the multiphase fluid entering the pump if the GVF is always less than 95 percent (absolutely no slugs of gas). Otherwise, a source of screw sealant must be supplied from a downstream separator (using the pumped liquid) or from an external supply that is unrelated to the fluid being pumped, e.g., water. water. A flush to the mechanical seal can serve two purposes, acting as both the seal flush and the screw sealant. It can come from an enlarged section of the discharge pipe or a downstream in-line separator (e.g., a gas liquid cylindrical cyclone) or a large downstream separator vessel (API Flush Plans 11 or 31) or an external supply (API Flush Plan 32) to the single single or dual seal. The flush flush then enters the seal chamber and the pump where it becomes the screw sealant. API Seal Flush Plan 32 is used for services with a GVF greater than 95 percent. If the fluid being pumped is below a 95 percent GVF, GVF, an external supply of screw sealant is not theoretically required. However, caution is advised in these situations because multiphase flow flow is almost never homogeneous. homogeneous. For instance, with with a 90 percent GVF one might think that no screw sealant is required. required. However, 90 percent GVF is an average. Even at 90 percent GVF, GVF, slugs of pure liquid (0 percent GVF) and pure gas (100 percent GVF) can occur. These slugs slugs must be designed for and communicated to the MPP supplier on the API 676 data sheets. As with the mechanical seal flush, a clean, cool, particulate free, external liquid steam should be supplied. For example, a screw sealant was needed in the Mitsue pump with an average GVF of 75 percent, yet it experienced severe liquid and gas slugging. (Refer to Sec Sectio tion n 613 6134 4 Lessons Learned, item C.) Slugging is described in detail in Sec Sectio tion n 63 635 5. For a dual mechanical seal, the screw sealant must be fed directly into the seal flush port immediately inside inside the inner seal, at the end of of each screw. screw. As explained in Sec Sectio tion n 633 633,, if the screw sealant comes from a discharge separator, the level in the separator will drop as the gas slug is moved by the pump. If the gas slug lasts for a longer duration than designed for, the separator will run dry, starving the pump of screw sealant. With the external supply of screw sealant, a high temperature sensor will pick up the increased heat inside the pump and shut down

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the pump before damage occurs. If a downstream separator vessel is used, a level alarm and shutdown will protect the pump. Refer to Figu Figure re 600-3 600-33 3 for a skidded MPP with a separator built into the discharge line. Fig. 600 600-3 -333 Skidded MPP MPP with a Built-In Sepa Separator rator in the Pump’s Enlarged Enlarged Discharge Line (Courtesy (Courtesy of Leistrit z Corporation)

In conclusion, the downstream separator must be sufficiently sized, taking into account the duration of a 100 percent gas slug. One method to determine the size and duration of slugging is to model the suction piping system by using OLGA, a computer simulation program.

634 634 Rotor Rotor Des Design ign for Twin Twin Scre Screw w Pumps Pumps A liquid-only twin screw pump is designed to pump liquid (no gas), and the rotors are held apart by using the pumped liquid as a lubricating cushion and preventing wear between the parts. For an MPP, the rotors must never touch, and the rotor shaft must be stiffer and, therefore, larger in diameter. For this reason, a liquid-only twin twin screw pump should never be used for multiphase service. The twin screw rotors should be designed such that the rotors will deflect no more than half the designed internal clearance under the most severe operating conditions. A twin screw MPP will also operate hotter than one that pumps pure liquid. Compressing the gas in the pumped fluid causes the pump to run hotter, expanding the internal parts. Internal clearances must be increased. Otherwise, the parts will rub and seize. To avoid this, the rotor clearances should be designed to allow the pump to operate operate without the the rotors contacting contacting each other. other. To To prevent wear, wear, the pump pump should be designed for a temperature of 300°F (148.89°C) above the maximum expected suction temperature.

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For example, the 300°F (148.89°C) recommendation is based in part on the Mitsue pump that experienced a temperature temperature rise of 280°F (137.8°C). (137.8°C). (Refer to Sectio Sec tion n 613 6134 4 Lessons Learned, items A and B.) Unless specifically designed to pump 100 percent gas, MPPs are not designed to pump pure gas efficiently efficiently.. The screw flight spacing spacing (screw locks) are designed for for 100 percent liquid, and the increased clearances, required for gas, make the pump relatively inefficient, typically 30 to 50 percent. Note, however, that in comparing the twin screw pump to the helico-axial pump, PCP, or ESP, at any GVF, the twin screw pump’s efficiency is considerably superior. Bornemann offers a “regressive screw” twin screw pump design in which the screw locks become smaller towards the discharge. This design is marketed as improving the pump’s pump’s volumetric efficiency by as much as 15 percent. (Refer to Sec Sectio tion n 634 634.) .) If particulate is present, the clearance may also need to be increased further to compensate for the size of expected particulate. When developing quotes, a particulate size distribution distribution and an analysis analysis of the particulate particulate showing the percent quartz, silica, clay, etc., should be provided on the API 676 data sheets given to the MPP suppliers to determine the correct clearances. With properly designed clearances, the screws can expand when handling pure gas, and particulate can pass without rubbing or causing erosion. If only one (gas slugs or particulate) is present, the clearances are sized for only that criteria.

635 635 Effect ffect of Slugs— Slugs—Ga Gass and and Liquid Slugging can be defined as the alternating of large pockets of liquids and gas to the pump. A twin screw type pump pump will not be damaged by severe slugging. This This is because twin screw MPPs, besides besides being of a very robust robust design, are designed to split the incoming flow into two equal parts, each part entering the screws from the opposite ends of the pump at exactly the same time. The resulting forces are opposed and cancel each other. This design is one of the primary reasons that the twin screw pump is used for most applications. Other types of MPPs do not have this feature and are, therefore, more susceptible to damage from slugging. Slugging can be very severe if the MPP is located a good distance from the well(s). Before starting the pump, the low points of the suction piping are filled with liquid. During startup, the liquid pockets are flushed into the pump. After this is done, liquid again starts to fill the low points, allowing gas to flow in the upper radius of the pipe, feeding the MPP mostly pure gas. Startup slugging is referred to as terrain slugging, and the effects can be severe. If a liquid slug enters the pump after a gas slug, the suction pressure drops suddenly, suddenly, and the liquid level in the downstream separator rises significantly. significantly. The cooler liquid causes the temperature in the pump to drop significantly, as well. The reverse happens if gas slugs occur after liquid slugs. The pump’s pump’s suction pressure rises suddenly suddenly,, and the discharge separator separator level drops, while the the pump temperature rises significantly. significantly. After the pump has been operating, terrain slugs are often followed by hydrodynamic slugs. Hydrodynamic slugs are caused by the well’s production

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stream, its GVF, and the terrain-caused ups and downs of the pump’s suction line. As described above, the bottom of the suction line begins to fill with liquid, especially at the low points, while the gas flows over the liquid in the upper portion of the line. Liquid slowly fills the line sufficiently sufficiently such that, eventually, eventually, the gas pushes it through and and into the MPP. MPP. Hydrodynamic slugs slugs are usually more frequent frequent but less severe than terrain terrain slugs. Liquid slugging also affects the design size of the downstream facilities. During a liquid slug, the MPP pumps at its theoretical liquid flowrate (not at the liquid percentage of the multiphase multiphase flowrate). The downstream downstream separator, in combination combination with the liquid flow line capacity, capacity, should be sized for this 100 percent liquid rate for the expected duration of the liquid slug. A Pipephase or OLGA computer simulation is required to determine the slug duration and to assist in the proper sizing of the separator and the discharge flow lines. If practical, one way to avoid slugging or at least minimize its severity is to locate the MPP close to the well(s) such that the number of terrain ups and downs in the suction line is kept to a minimum. For example, the Chevron Mitsue pump experienced both types of the slugging discussed above, but other companies have had similar experiences. (Refer to Sec Sectio tion n 613 6134 4 Lessons Learned, item D.)

636 636 Motor Sele Selection ction and Use of Adjustable Spee Speedd Drives Drives (ASD) (ASD) One of the characteristics of a twin screw pump and the progressive cavity pump is that they are positive displacement pumps (capacity is proportional to speed) and constant torque machines (under the same fluid conditions, the required torque is dependent only on differential pressure). They operate independently of speed and gas volume fraction. If the pump is started against the full system backpressure, the motor must develop a large torque. Most motors do not develop full torque until they reach full speed. Therefore, if the pump starts under a load, a larger HP motor will be necessary than will be required for normal operation. A larger HP motor increases the cost of the pump/motor skid substantially. substantially. There are two commonly used methods to avoid this: 1.

Installat Installation ion of a startu startup p recirculat recirculation ion line line (piping (piping from from pump disch discharge arge or or a downstream separator back to a suction header or suction tank) that includes a pressure control valve; valve;

2.

Installat Installation ion of an an ASD on the the motor, motor, a motor motor specifi specifically cally design designed ed for an ASD. ASD.

Solution 1 allows the MPP to start at a low discharge pressure, where the MPP requires a low torque from the motor. motor. The pressure control valve in the recycle line is opened on pump startup allowing the motor to reach full speed and full torque before it closes on a planned planned basis, thereby thereby building the discharge discharge pressure on pump slowly to keep the required torque below that developed by the motor. To do this properly, properly, the operator needs to be certain certain that the suction, suction, discharge, and recirculation lines are full of liquid before the pump is started. This approach could be used after startup during during normal operation to reduce the net production production by recycling flow through the bypass line. However, this approach wastes energy. energy. Also, if the bypass line is left open too long, the fluid will heat up, possibly flash, and increase the GVF.

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Solution 2 provides the advantage that the motor provides the required flow control under operating conditions. An ASD allows the operator to vary the speed and, therefore, the flowrate of the pump, to better match the field’s field’s production. Finally, Finally, by increasing the pump pump speed, an ASD system can be used used to maintain production production as the pump wears. Solutions 1 and 2 can be applied independently. However, both should be implemented. Other drives, such as natural gas or diesel engine drives, can also be used. These drives are not constant torque drives and must be sized such that the pump’s required torque never exceeds the torque available from the drive. Again, the drive may be oversized to accomplish this, or a recycle line may be used. For the helico-axial pumps, which are not constant torque, standard electric motors and typical discharge flow control valves are used, often with a recycle line to keep the pump above the pump’s minimum flowrate (thermal or stable), or an ASD drive and its properly designed motor is used. The flow control valve and recycle line will likely waste energy, energy, so the ASD option is the preferred solution.

637 637 Methods ethods to Reduce Reduce Sand Sand Erosion Erosion Twin Screw Pumps Based on the Duri test, sand rates equivalent to 90 bbl/day will not cause erosion in a twin screw pump as long as the sand is flowing in crude oil at or below 22 degrees API with a viscosity above 330 cp. In this test, it is believed that no erosion occurred because the sand stayed in suspension in the heavy, viscous crude oil. A computer simulation also indicated that a pump handling crude oil between 22 degrees API and 30 30 degrees API is not likely to erode with sand present. The The amount of erosion from sand is expected to increase if the API gravity is above 30 degrees. If the sand is pumped with with only gas, steam, or water, water, the pump will will definitely erode quickly. quickly. This was shown at Duri during the steam injection test. (Refer to Twin Screw MPP Results in Sec Sectio tion n 613 6138 8.) Erosion with water and particulate was also demonstrated at the University of Erlangen in Nuremberg, Germany. Germany. During the 1990s, a sand erosion test was run on a conventional twin screw pump. During the test, a stream of pure water containing a 0.9 vol. % of sand was pumped while the pump’s differential pressure was maintained at approximately 220 psi. The sand was pure quartz with a particle distribution distribution that extended above and below the pump’s pump’s internal clearances. In 1-1/2 hours, the pump wore out out completely. completely. If a twin screw pump is installed with sand in its feed, several design improvements should be implemented to directionally reduce the effect:

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1.

Installin Installing g a removabl removablee liner liner with with Satellit Satellitee or tungst tungsten en carbide carbide coating coating.. Suggestions for coatings are described in Sec Sectio tion n 641 641;;

2.

Gas harden hardening ing the rotors rotors (Again (Again,, refer refer to to Sec Sectio tion n 641 641); );

3.

Coat Coatin ing g the the scre screw w edg edge; e;

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4.

Operating Operating the pump pump at a slower slower speed speed (balan (balancing cing the the cost cost of the the larger larger sized, sized, slower pump against the smaller sized, higher speed pump that will wear more quickly);

5.

Using Using an ASD ASD with with a properly properly designed designed motor motor or a variabl variablee speed speed engine, engine, which allows the pump to run at speeds above its normal operating speed;

6.

Using Using the maximu maximum m number number of screw screw turns turns or locks, locks, more than that necess necessary ary to develop the required discharge pressure;

7.

Prohibit Prohibiting ing balanc balancee holes holes on the the periphery periphery of the screws. screws. (They (They create create a place place for rapid erosion.)

By using hard coated liners and hardened items 1, 2, and 3, the amount of erosion is reduced as long as the particulate in the stream is softer than the coatings. Allowing the pump to operate at slower speeds (item 4) reduces the erosion, since the erosion rate, “e”, equals the velocity, “v”, raised to the 3 rd or 4th power (e = v3). If the pump is designed to provide the required flowrate at a speed less than the motor’s maximum rpm and an ASD is used to drive the motor, motor, the speed of the pump and motor can be increased to compensate for any erosion suffered during normal operation (item 5). Confirm with the manufacturer that the speed increase is acceptable. Using item 6 decreases the pressure boost across each stage, decreasing slip, therefore decreasing erosion. Implementing item 7 eliminates a location where erosion can get a foothold, destroying the coating around it. (It is common for manufacturers to balance their rotors by drilling holes in the tip of various screws.) The most commonly used design modifications to prevent erosion are items 1, 2, 3, 4, and 5. If sand is present, an MPP specialist should be consulted before purchasing the pump. In a twin screw pump, rotor clearances are small, on the order of 0.008 inch, almost always smaller than a grain of sand. Sand tends to wedge between the screw edges and the bore of the pump, causing erosion. Once erosion begins, the slip or the flow of fluid backwards across the screw edges will increase causing additional erosion which continues an ever more rapid rate of erosion.

Helico-Axial, Helico-A xial, PCP, PCP, and ESP Pumps Since a certain speed is required to develop the required pressure differential and flowrate, these types of pumps typically rely on proprietary coatings and materials to minimize erosion. (Refer to Sec Sectio tion n 660 for Helico-axial pumps, Sec Sectio tion n 67 670 0 for PCPs, and Sec and Sectio tion n 680 for ESPs.)

638 638 Recycle Recycle Stream Stream Flashing Flashing (Surface (Surface Pumps) Twin Screw Pumps Liquid near its boiling point will flash into gas if a pressure drop occurs or if its temperature is raised, such as, if a liquid near its boiling point is mixed with a hotter fluid. The result is that a small volume of liquid will flash into a very large volume of gas.

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As mentioned before, if the GVF of a pumped stream is very high, a recycle screw sealant stream will be required. If the screw sealant stream is the pumped fluid recycled from a discharge separator, it is likely to be near its flash point, and flashing needs to be evaluated. Usually a flow control valve is installed on the screw sealant line from the downstream separator to the suction side of the pump. As the fluid passes through the control valve, the fluid pressure drops to that of the suction. As this pressure reduction occurs, the hot screw sealant fluid may flash. Also, if hot enough, the sealant fluid may cause some of the incoming pumped stream to vaporize. Of course, for a given sealant fluid temperature, more of the incoming stream’s volume will flash if it is a lighter gravity fluid rather than a heavier gravity fluid. The net effect of this flashing is that the evolved gas occupies pump capacity. capacity. This gas volume replaces liquid volume in the pump, decreasing the pump’s pump’s volumetric efficiency and causing the pump to be built larger to accommodate the increased gas volume. Once a flow diagram is identified, a process simulation should be done to identify areas where flashing can occur and to quantify the amount of flashing. HYSIM or PRO II are two simulation programs that can be used for this purpose. Potential solutions to minimize the effects of flashing (other than oversizing the pump) are shown in the the following list (the (the recommended solutions solutions are items 3 or 4): 1.

Mixing Mixing the recycl recycled ed stream stream into into the the suction suction stream stream as as far upstrea upstream m of the the pump’s pump’s suction flange as is possible. This allows allows for some atmospheric cooling cooling of the recycled stream and for re-condensing some of the gas before it reaches the pump.

2.

Mixing Mixing the the recyc recycled led stre stream am into into a sucti suction on vesse vessel. l.

3.

Installin Installing g a cooler cooler or condenser condenser in in the recycle recycle stream stream after the the pressure pressure reduction valve, injecting the recycle stream into the suction or into the mechanical seal flush port. The HYSIM process simulator should be run again to size the cooler. Usually the cooler is a small air cooled exchanger. exchanger.

4.

Supplying Supplying the screw sealant sealant from a cool, cool, external external source. source.

For example, Mitsue used these solutions. (Refer to Sec Sectio tion n 613 6134 4 Lessons Learned, item J.) Recycle, Slip, Flashing Factor. Factor. The pump’s size needs to be larger than the size that is first calculated. This is necessary to compensate for flashing and the increased clearances (with increased slip) needed to compensate for heat and particulate. To To do this, one simply multiplies multiplies the initial design capacity by a recycle, slip, flashing factor in accordance with the following:

•

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Use a fact factor or of 1.10 1.10 perc percent ent for for screw screw seal sealant ant that that is is the same same temp tempera eratur turee as pump suction (solution (solution 3 or solution 4);

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•

For For unc uncoo oole led d recy recycl cled ed stre stream ams: s: – – –

Use a factor of 1.15 percent for all GVFs and a heavy crude (API less than than 25 degrees); Use a factor of 1.25 percent for GVFs GVFs less than 50 percent and and a light crude (API greater than 25 degrees); Use a factor of 1.35 percent for GVFs greater than 50 percent and a light light crude (API greater than 25 degrees).

Refer to Sec Sectio tion n 693 for an example of how this is applied. The need for the recycle, slip, flashing factor was determined from the Mitsue pump. (Refer to Sec Sectio tion n 613 6134 4 Lessons Learned, item J.)

Helico-Axial, Helico-A xial, PCPs, and ESP The helico-axial pump and surface PCPs or ESPs may also require a recycle stream for low flowrates. If so, flashing must be considered. Solutions 1, 2, and 3 in Sectio Sec tion n 638 (twin screw pumps) can be applied.

639 639 Suction and Discha Discharge rge Piping Piping (Surfa (Surface ce Pumps) Pumps) Model the Piping During the early design stages, the multiphase simulator, Pipephase, should be run on the MPP’s inlet pipe from the production wells through the discharge piping to the downstream separation. If Pipephase indicates slugging, a transient simulator, such as OLGA, should be used to predict the size, frequency, and duration of the slugs. This information is necessary to properly size the pump and associated equipment. For example, the OLGA simulation of the Mitsue installation indicated significant slugging. (Refer to Sec Sectio tion n 613 6134 4 Lessons Learned, item G.)

Suction Strainer A strainer should always be installed in the MPP’s suction line to catch debris. It should be a permanent, basket strainer, not just a startup “witch’s “witch’s hat”, conical screen. If sized properly, this basket strainer will prevent small pieces of debris from entering and damaging the pump. The openings or mesh size of the strainer is often 1/8 inch, unless wax is present. If wax is present, a filter is used instead of a strainer. strainer. The sizing of the strainer mesh or filter should be determined for each application, and the mesh size should be jointly developed by the purchaser and the pump supplier. The combination of wax and sand in a stream is particularly challenging since sand will plug the filter quickly. Consult an SME on multiphase pumping.

Note

The strainer or filter should be a duplex stainless steel unit that allows switching from one unit to the other while the MPP runs. The open area of the screen should be 150 percent of the pipe flow flow area, unless wax is present. present. For wax, 200 percent is recommended. The strainer should be designed to withstand as large a differential pressure as possible. This This depends upon the the size and pressure rating of the strainer housing and the mesh itself. When purchasing the strainer, determine the strainer’s

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collapse pressure. Finally, Finally, a high differential pressure across the strainer should trigger an alarm, followed by a shutdown that is lower than the collapse pressure. Refer to the Princess MPP and the Main Pass 313 installations. (Refer to Sectio Sec tion n 613 6135 5 Lessons Learned, item B and Sec and Secti tion on 613 6136 6 Lessons Learned, item F.)

Inlet Pipe Orientation The pump should be located as close as possible to the source of the pumped fluid. The suction piping shall be kept as short as possible, with as few elbows as possible. High spots where gas can get trapped or low spots where liquid can collect should be minimized, since they will will create slugging. slugging. Any of these vertical legs that that are absolutely necessary should be located as far from the pump as possible. Inlet piping should enter a twin screw pump from a plane perpendicular (either horizontal or vertical depending on the pump’s suction suction flange) to the axis of the screws. Upstream of the pump inlet flange the pipe should be a straight run for at least 10 pipe diameters or 10 feet, whichever is longer. longer. An elbow should not be installed immediately at the pump’s inlet flange. Pipe that runs parallel to the axis of the twin screw pump’s rotors and that have an elbow bolted directly to the pump flange must be avoided. This will channel more flow to one side of the pump than the other. In a slugging situation, this will increase the pump’s axial thrust forces beyond design and cause a failure.

Pressure Restriction Location A pressure restriction (a control valve or orifice, etc.) shall not be installed near the pump’s pump’s discharge flange. flange. If such a device is installed installed near the pump, the pressure pressure will surge to unacceptable levels, instantaneously, instantaneously, when a slug of liquid follows gas. A pressure restriction, if necessary, necessary, should be installed on the downstream side of the liquid separator in the discharge line. If a liquid separator is not being used, the restriction should be installed as far down the discharge line as possible. Locating restrictions at the proper points will tend to dampen any pressure surge due to slugging. For example, in the Mitsue installation, slugs caused a significant pressure spike due to a pressure restriction near the discharge flange. (Refer to Sec Sectio tion n 613 6134 4 Lessons Learned, item E.)

640 MPP Materi teriaals 641 Genera nerall This section describes materials for MPPs that are designed to operate with streams containing sand or other hard particulate. Materials, coatings, and material hardening processes are improving rapidly, rapidly, and selecting the most erosion resistant material, coatings, or hardening process can be difficult. An ETC or local expert should be consulted if sand or hard particulate is involved.

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642 Twin Scre Screw w Pump Pumpss If twin screw MPPs handle sand, the rotors and case liner or case (if supplied without a liner) must be fabricated using hard materials, ma terial hardened by various methods, or materials coated c oated with overlays suited to withstand abrasion and erosion. For twin screw pumps, the following methods have been used:

Pump Case The pump case or the pump casing under the liner should be carbon steel or better. better. Cast or malleable iron is not acceptable. A pump case liner is strongly recommended.

Pump Case Liner Alternative 1—Stellite 12 Weld Weld Overlay. Stellite can be applied to the case or case liner using the following general weld procedure:

•

Prehea Preheatt the base base mater material ial to to 482°F 482°F (250° (250°C) C) with with a maximum maximum inte interpa rpass ss tempe temperarature of 350°F to 400°F (176.7°C to 204.4°C);

•

Apply Apply a weld overlay overlay,, called called a buffer buffer or butter butter layer, layer, consisti consisting ng of of 316 316 L SS weld rod. The finished thickness of this layer, after machining, should be 0.080 in. (2.0 (2.0 mm); mm);

•

Apply Apply two two layers layers of Stelli Stellite te 12, 12, with with a final total total finishe finished d thickn thickness ess after after machining of 0.12 in. (3.0 mm);

•

Post Post heat heat treat treat at 1,094 1,094°F °F (590° (590°C), C), plus plus or minus minus 50°F 50°F (10°C (10°C). ). This This tempe temperarature should be held for 1 hour. hour. Heating and cooling rates shall be 104°F (40°C) per hour. hour.

Stellite 12 weld overlay has a hardness of 45 HRC. Alternative 2—Titanium. Manufacture the entire liner out of titanium. Alternative 3—Chrome Overlay the th e Liner. Liner. Applying chrome overlay to the pump case or the pump case liner is not recommended. The process of adding chrome over base metal is often performed poorly poorly,, and as a result, the chrome peels off off the base material. Chrome overlay has a hardness of 68 HRC. Recommendations. Alternative 3 is not acceptable. Alternative 1 and Alternative 2 are recommended.

For all of the hardening or coating processes, the supplier should submit with his bid detailed procedures, including weld procedures, and pre- and post-weld heat treatments.

Rotors (Screws) Gas Hardening. Gas hardening is usually used to harden twin screw rotors, since their profile is difficult to apply a welded material to and then remachine to the proper profile.

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There are two commonly used gas hardening techniques: Alternative 1—Nitride 1—Nitride Soak. The entire twin screw rotors can be hardened with nitride gas for 48 hours. The depth of the hardness is approximately 0.003 in. (0.076 mm). Nitriding has a hardness of of 58 HRC. Alternative 2—Boride 2—Boride Gas Diffusion Diffusion Deposition Coating. The twin screws can be hardened with boride gas diffusion over the entire surface of the screws (edge, both flanks, and the root).

•

The parent parent material material should should be 400 series series SS, capable capable of resisting resisting hot carbonic carbonic acid corrosion.

•

Before applying applying the borid boridee diffus diffusion ion coating, coating, the the parent parent material material shou should ld be be heat heat treated to 1,650°F (898.9°C), minimum, and slow cooled.

•

A boride boride dif diffus fusion ion coat coatin ing g should should be be applied applied with with a fini finishe shed d hardnes hardnesss of 1,600 DPH or 1,600 HV, HV, minimum.

•

Finish Finished ed thick thicknes nesss of the coat coating ing shou should ld be 0.004 0.004 in. in. (0.10 (0.102 2 mm), mini minimum mum..

•

After After coati coating, ng, no no check check crac cracks ks sshou hould ld be be visibl visiblee by the the nake naked d eye. eye.

Suggested suppliers are the pump manufacturers, since the coating is purchased when the pump is bought. Boriding has a hardness of 2,000 HV (V = Vickers). If particulate is present in the pumped stream, using Alternative 2 for the screws lasts longer. However, it is more expensive and difficult to apply. The supplier’s procedure needs to be reviewed reviewed and the results inspected. inspected. Alternative 3—Stelliti 3—Stelliting ng the Screw Edges. In addition to Alternative 1 or Alternative 2, Alternative 3 may be used. In Alternative Alternative 3, only the the tips or edges of the screws are stellited. Alternative should not be used by itself, but only in combination with Alternative 1 or Alternative 2. Alternative 4—Other 4—Other Options. The pump supplier should be encouraged to offer hardening alternatives, including price differences that are harder than those mentioned above and/or that could coat more of the screws than just the edges or tips. The pump supplier should submit such details with his bid.

643 643 Helico-Axia Helico-Axial,l, PCP PCP, and ESP ESP Materia Materials ls These types of pumps use proprietary materials. Refer to Sect Section ion 660 for Helicoaxial pump materials, Sec Sectio tion n 670 for PCP materials, and Sec and Sectio tion n 680 for ESP materials.

644 644 Mechanica Mechanicall Seal Seal Mate Materials rials (all (all types of MPPs) MPPs) For most helico-axial and twin screw pump applications running below 300°F (148.9°C) or with no particulate or hydrogen sulfide or highly acidic or basic fluids, the typical materials for the seal parts are: • •

600-58

Seal Seal ring ring:: si silico licon n car carbi bid de Mating ri ring: ca carbon 


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• • •

Hardwa Hardware re (scre (screws, ws, spri springs ngs,, retain retaining ing rin rings, gs, etc. etc.): ): stain stainles lesss steel steel Seco Second ndar ary y seal seal ela elast stom omer eric ic “O“O-Ri Ring ng”: ”: Vit Viton on Clos Closee cle clear aran ance ce bush bushin ing: g: Bron Bronze ze

For other upstream applications, refer to Materials for Mechanical Seals in Sectio Sec tion n 632 of this manual, and, if necessary for other applications, consult Chevron Pump Manual Seal Selection Guides PMP-DG-4662 CRN and PMP-DG-4662 FS.

650 Manufacture nufacturers— rs—T Twin Scre Screw w MPP MPPss 651 Genera nerall The three most common manufacturers of twin screw MPPs are: • • •

Bornemann Leistritz Flowserve

The most common twin screw MPPs are Bornemann and Leistritz. They supply approximately 90 percent of these pumps that are sold. They are well constructed and highly reliable. Both manufacturers supply packaged units on skids. As of this writing, Flowserve has few installations, and they have had problems with their construction and reliability. reliability. We strongly recommend against purchasing their pumps at this time. For example, example, Chevron has had problems problems with Flowserve pumps pumps in Venezuela’s Boscan and El Tigre fields, as well as in Chad. (Refer to Sectio Sec tion n 613 6139 9.) All three pumps use identical flow patterns. The pump’s inlet or suction flange is at axial center of the pump case. The inlet fluid is split in two streams, with equal portions directed to to each end of the pump where the the fluid enters the screws. screws. The screws move the fluid to the center of the screws where the discharge is located. All three manufacturers incorporate four sets of mechanical seals, and all have bearings outboard of the seals. Bornemann also also has a design in which which the discharge discharge is at the end of the the screws by the mechanical seals. This design should be avoided, if possible, since in this design, the mechanical seals are required to seal against discharge pressure. These seals are more difficult to design and their reliability is inferior.

Note

In summary, at the moment, it is strongly recommended that only Bornemann or Leistritz be considered for Chevron applications. Their pumps are well constructed, highly reliable, and can be supplied as packaged units on skids. Colfax owns Warren, Houttuin, Allweiler, and IMO brands. Warren has manufactured a liquid screw pump for many years. We have had success with the Warren pumps, which are pumping 40 percent GVF multiphase flow for approximately 15 years in Venezuela. While not yet recommended for purchase by Chevron, Chevron, Colfax is currently attempting to enter the MPP market in a substantial way.

Note

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Refer to Sec Sectio tion n 613 6130 0 for a discussion of several Chevron and legacy Texaco MPP installations, installations, including several “lessons learned” from each. Several recommendations included in this manual are derived from these “lessons learned”. A complete list of Chevron and legacy Texaco MPP installations is included in Figure Fig ure 600 600-1 -1..

652 Borne Bornema mann nn MP MPPs Ap plic pl icati ati on s Bornemann has made more twin screw MPPs than any other supplier, with over 400 installations worldwide. worldwide. Bornemann claims its largest pump, MPC series, can pump 900,000 bpd at a differential pressure of 1,015 psi. It also makes a smaller version, the MW series. Fig Figure ure 600 600-34 -34 lists 15 significant installations. As shown in Figu Figure re 600600-34 34,, Bornemann pumps are installed onshore, on offshore platforms, and, recently, recently, subsea. The pumps are installed installed in a wide range of applications, such as increasing production by reducing wellhead pressure, transporting multiphase fluids several miles through one pipeline, and taking suction from the annulus of several oil wells where the multiphase fluid averages over 98 percent percent gas. Note Note that, in Figu Figure re 600-3 600-34 4 , one of the Bornemann MPPs was purchased by the Chevron Chevron Midway Sunset field in in Bakersfield, California. It performed so well that eight eight of the pumps are now in in operation at that site. site. Bornemann Corporation) (1 of 2) Fig. 600600-34 34 Significant Bornemann MPP MPP Installations Installations (Information Courtesy of Bornemann

Cu s t o m er

Onshore Offshore Su b s ea

Dat e

No .

Mo d el

Capacity (bpd)

Delta P (psi)

GVF (%)

D r i v er

HP

Poseid Poseidon on

Off Offshor shore e

1989

1

MPC355 MPC355-45 -45F

60,00 ,000

928

96

Elect Electrric

-

Caltex

Onshore

1997

1

MW9.5zk-67

125,000

231

75

E lectric

350

Bakersfield, CA

Chevron

Onshore

2000

1

MW7.3zk-33

7,400

290

60

E lectric

63

Venezuela

S incor

Onshore

2000

1

MW8.5zk-67

74,000

510

82

E lectric

774

Minas, Indonesia

Caltex

Onshore

2000

1

MW8.7zk-46

60,000

110

65

E lectric

161

Bakersfield, CA

Chevron

Onshore

2001

1

MW8.5zk-33

7,400

290

60

E lectric

63

Bakersfield, CA

Chevron

Onshore

2001

1

MW8.5zk-67

71,000

270

80

E lectric

402

Russia

Tatoilgaz

Onshore

2002

2

MW7.3xk-43

17,000

218

75

E lectric

80

Bakersfield, CA

Chevron

Onshore

2003

1

MW8.5zk-67

57,600

205

80

E lectric

239

Bakersfield, CA

Chevron

Onshore

2003

1

MW8.5zk-85

60,000

191

80

E lectric

250

CNRI

Onshore

2003

1

MW9.5xk-90

159,000

171

95

E lectric

646

BP

Subsea

2006

3

SMP C 33550

-

725

70

E lectric

1,475

Location or Oi l Fi el d Tun Tunisia isia Duri, Indonesia

Canada US Gulf of Mexico, King Field

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Fig. 600600-34 34 Significant Bornemann MPP MPP Installations Installations (Information Courtesy of Bornemann Bornemann Corporation) (2 of 2) Onshore Offshore Su b s ea

Dat e

No .

Cairn Energy

Onshore

2006

Algeria

AGIP

Onshore

Canada

Imperial Oil

Onshore

Location or Oi l Fi el d India

Cu s t o m er

M o d el

Capacity (bpd)

Delta P (psi)

GVF (%)

Dr i v e r

HP

2

MW106-132

364,000

180

95

E lectric

1,530

2007

2

MP C-400-79

136,000

798

90

E lectric

-

2008

2

MW8.5zk-85

86,000

189

95

E lectric

370

Recently, Recently, three Bornemann B ornemann MPPs were installed subsea for the British Petroleum King Field in the Gulf of Mexico. BP claims the pumps will increase production by 20 percent and overall recovery by 7 percent, extending the life of the field. The pumps are on the ocean floor under under 5,500 feet of water. water. Each of the pumps is driven driven by a subsea electric motor controlled controlled by an ASD on a host platform. The motor supplies 6,600 volts to the subsea pump, 15 miles away. These are the first twin screw MPPs to be located subsea on the seabed floor.

Orientation and Drivers Bornemann pumps are designed to be installed horizontally. horizontally. Usually, they are driven by electric motor drives with with ASDs, although although they may be driven by natural natural gas engines or other drivers. This enables the pump’s capacity to be controlled to match well production. Flow is usually controlled based on a set suction pressure or wellhead manifold pressure.

Packaging For new installations, Bornemann pumps can be purchased directly from Bornemann, or they can be packaged by Aker Kvaerner as skid mounted units or units ready for grouting. The packages include strainers, valves, piping, pressure and temperature gages, and discharge separators.

Testing Facilit Facilit ies Bornemann does an inhouse test of its equipment with water and air. After the MPP pumps water for a while, Bornemann Bornemann injects air into the the water until the temperature rises to a pre-established level. Bornemann does not test with particulate. This testing is not considered to be a good indicator of how a pump will react while pumping an actual multiphase multiphase fluid.

Particulate Handling and Speed These pumps are usually run at 1,800 rpm but may be run at 3,600 rpm or 1,200 rpm, based on the amount of particulate particulate entrained in the stream, expected expected well production production rates, and the economics of the project. The Bornemann pump demonstrated during the Duri test that it could pump and not retain a substantial quantity of sand without internal damage. (Refer to Sec Sectio tion n 613 6138 8 for details.)

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Materials Materials and Coatings Bornemann pumps are usually fabricated from carbon steel. A fully replaceable liner is offered. The liner can be Stellite weld overlaid, and the screws can be borided to provide provide better wear resistance to sand. sand. The other coating materials materials mentioned in Sec Sectio tion n 640 can also be provided. For example, these features were included in the Caltex Duri twin screw MPP, MPP, manufactured in 1997. (Refer to listing in Fig Figure ure 600 600-34 -34 and Sec and Sectio tion n 61 6138 38.) .)

Mechanical Seals Bornemann will supply its MPPs with a single seal using the close clearance throat bushing or a pressurized pressurized dual seal or an unpressurized unpressurized dual seal. The Bornemann Bornemann unpressurized dual seal is unique, not supplied by any other twin screw MPP manufacturer. manufacturer. It is called the “poor man’s” seal. It consists of an inner seal, identical to an unpressurized dual seal with a lip seal on the outboard end, which differentiates it from the unpressurized dual seal described in API 682. The inner seal is cooled and lubricated from a flush that is routed to the seal from two connections in the case. Like all unpressurized dual seals, the “poor man’s” seal injects the area between the inner or primary mechanical seal and the outer secondary lip seal with a buffer fluid at atmospheric pressure supplied from two tanks built into the MPP case. Bornemann claims it has supplied this seal to 95 percent of its customers, amounting amounting to over 450 units. units. Bornemann also claims claims that the seal lasts approximately 2 years, with the inner seal, as well as the lip seal, failing at just about the same time. Chevron has a few of these seals in the Bakersfield area.

Distinct ive Features Features Bornemann MPPs include several features not normally found in any other MPPs, such as: •

A large large pump case with an intern internal al chamber chamber,, design designed ed to to separat separatee and and retain retain a required portion of the liquid from the feed stream;

•

The The poo poorr man man’’s sea seall des descr crib ibed ed abov above; e;

•

An adjus adjustable table internal internal circulati circulation on valve valve that circulates circulates the trapped trapped liqui liquid d back back to the pump suction. If fully open, the pump’s pump’s entire capacity can be circulated. Bornemann claims that this provision unloads the pump and motor during startup. The valve’s plug contains contains a groove, such that, if the valve is fully closed, it still circulates 3 to 4 percent of the pump’s capacity back to suction. This is usually enough to supply the screw sealant needed if the pump is fed a fluid with a GVF above 95 percent.

Note that these features are not always considered considered positive. There is no instrumentation instrumentation to show if and when the internal chamber runs dry. The potential for this occurring is high if pumping streams exceed a GVF of 98 percent. Bornemann also includes a high temperature shutdown in the case that shuts the pump down if the screw screw sealant liquid in the the case is depleted. If liquid liquid is depleted, the pump heats up and shuts down due to high temperature. If a stream with a GVF greater than 98 percent is anticipated, an external e xternal source of liquid screw sealant/flush should be used. (Refer to Sec Sectio tion n 638 638.) .)

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653 Leist Leistrit ritzz MP MPPs Ap plic pl ic ation ati on s Leistritz model L4HK, its largest twin screw pump, can pump 330,000 bpd at 1,200 psi differential pressure. pressure. Leistritz is working to increase its differential differential pressure capability to to 2,100 psi. Leistritz makes another, another, smaller model, L4MK. Its maximum flowrate is 220,000 bpd at a maximum pressure boost of 300 psi. Both models can handle streams with GVFs of up to 100 percent. At GVFs above 90 percent, Leistritz requires requires a separate system for screw sealant sealant and/or the mechanical seal flush, from a wide section of the discharge line or from a discharge vessel with a level gage, piping, and valves. The level gage allows monitoring of the screw sealant/flush flowrate and assurance that it is flowing all the time. Above 98 percent, a clean, cool, reliable reliable external sourced screw sealant/flush sealant/flush is recommended. (Refer to Sec Sectio tion n 638 638.) .) The first MPPs purchased by Chevron and legacy-Texaco legacy-Texaco (Trinidad, Humble, Mitsue, and Main Pass 313) were all manufactured by Leistritz. They have proven to be reliable, and Leistritz has supplied over 70 MPPs. Figu Figure re 600-3 600-35 5 lists 15 of Leistritz’s Leistritz’s more significant installations. installations. Leistritz’s Leistritz’s current installations are onshore and on offshore platforms. One of them, shown in Figu Figure re 600-3 600-35 5 , was installed by Chevron in 2007 on an unmanned offshore platform, Main Pass 59A in the Gulf of Mexico, driven by a large (1,700 HP) natural gas engine. Leistritz calls this installation installation the “largest of its kind”. The pump is designed to increase production by increasing the wellhead pressure of 18 wells to match that of the additional additional adjacent wells such such that a common production line can be used. The GVF was 95 percent. This is a highly profitable installation, installation, making $80,000/day $80,000/day based on oil at $80/bbl, $80/bbl, resulting resulting in a payout period of only only 0.17 years. (Refer to Sec Sectio tion n 613 6131 1.) Fig. 600600-35 35 Significant Leistritz Leistritz MPP MPP Installations Installations (Information Courtesy of Leistrit z Corporation) Corporation) (1 of 2) Location or Oil Fi e l d Humble, TX

Onshore Offshore Cu s t o m er Su b s ea

Dat e

No .

Mo d el

Capacity Delta P GVF (bpd) (psi) (%)

Dr i v er

HP

Texaco

Onshore

1997

1

L4NG

21,000

130

90

E lectric

65

Mitsue/P rincess

Chevron

Onshore

1995

1

L4HK

40,000

400

75

E lectric

700

Main P ass 313

Chevron

Offshore

1995

1

L4NK

26,000

125

98

E lectric

75

Moreia F ield

P etrobras

Offshore

1998

1

L4HK

61,000

580

88

E lectric

800

P eace River

Shell Canada

Onshore

2007

4

L4MK

87,100

300

95

E lectric

600

Omen

Shell Canada

Onshore

1998

1

L4HK

61,000

940

86

E lectric

710

Chad

E sso

Onshore

2003

5

L4HK

150,800

840

56

E lectric

960

Neiva, Colombia

Colombia

Onshore

2002

1

L4MK

45,000

265

58

E lectric

300

Neiva, Colombia

Colombia

Onshore

2003

1

L4MK

56,000

430

58

E lectric

700

Cent. E xpl.

Offshore

2007

1

L4HK

132,100

250

95

E lectric

820

Matarie, LA

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Fig. 600600-35 35 Significant Leistritz MPP MPP Installations Installations (Information Courtesy of Leistrit z Corporation) Corporation) (2 of 2) Onshore Offshore Cu s t o m er Su b s ea

Dat e

No .

Mo d el

Capacity Delta P GVF (bpd) (psi) (%)

Main P ass 59A

Chevron

Offshore

2007

1

L4HK

152,100

640

Alberta, Ca Canada

Devon

Onshore

2003

1

L4MK

22,000

Bakersfield, CA

Area Energy

Onshore

2005

1

L4MK

China

Bohai Oil Corp

Offshore

1996

1

Brazil

P etrobras

S ubsea

Soon

1

Location or Oil Fi e l d

Dr i v er

HP

95

Gas Engine

1,700

231

95

E lectric

125

130,000

190

35

E lectric

800

L4HK

37,000

525

92

E lectric

650

?

75,000

870

90

E lectric

-

It is expected that shortly a Leistritz pump will be installed on the ocean floor off the coast of Brazil. That pump, SBMS-500, will pump from a water depth of 2,100 feet and produce a pressure boost boost of 870 psi. This pump pump will experience an average GVF of 87 percent but is designed for 100 percent with an external supply of screw sealant. Slugs are expected e xpected because the pump is located 1-1/2 km from the well. Lubricating oil is supplied to the pump and motor from a tank located on the host platform. This system is unique and patented.

Orientation and Drivers Leistritz pumps are installed horizontally. Usually they are driven by an electric motor controlled by an ASD, although they may be driven by natural gas engines or other drivers. This enables the flow to be controlled to match production requirements. Flow is usually controlled from suction pressure or wellhead manifold pressure.

Packaging For new installations, Leistritz pumps are usually packaged as skid mounted units or units ready for grouting. Units include strainers, valves, piping, pressure and temperature gages, and discharge separators. Leistritz surface pumps are commonly packaged by Fluid Power Power Systems in Houston, Houston, Texas, Texas, while its subsea pumps pumps are packaged by Cameron. Of course, course, replacement pumps or new units units can be purchased as individual individual items.

Testing Facilities Fluid Power Systems will test the Leistritz pumps using water and natural gas.

Particulate Handling and Speed Speed These pumps are usually run at 1,800 rpm but may be run at 3,600 rpm or 1,200 rpm, based on the amount of particulate particulate entrained in the stream stream and the economics of the project. For example, the Princess pump ran reliably for several years at 3,600 rpm. (Refer to Sec Sectio tion n 613 6134 4.)

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Materials Materials and Coatings Leistritz pumps are usually fabricated from carbon steel. A fully replaceable liner is offered. The liner can be Stellite weld overlaid, and the screws can be nitrided to provide better wear resistance resistance to sand. The other coating coating materials mentioned mentioned in Sectio Sec tion n 640 can be provided.

Mechanical Seals Leistritz has sold MPPs with the single seal using a close clearance throat bushing, as well as pressurized dual seals. To date, Leistritz has not sold any MPPs with the unpressurized dual seal. If requested, Leistritz will use cartridge seals designed in accordance with API 682.

Distinct ive Features Features Leistritz pumps are more basic than Bornemann pumps, in that the liquid separation chamber and internal recycle valve are not supplied. On the other hand, Leistritz is easy to work with and will modify its equipment, backed by sound technical reasoning. For example, the Mitsue pump was the first MPP in the industry to use the API flush plan #32 with a throat bushing, where the flush also acted as a screw sealant. This was accomplished after discussions between Leistritz and Chevron. Like Bornemann, the Leistritz pump includes a high temperature shutdown if the screw sealant/flush is lost. If fluid is depleted, the pump heats up and shuts down due to high temperature. If a stream with a GVF greater than 98 percent is anticipated, an external source of liquid screw sealant/flush should be used. (Refer to Sec Sectio tion n 638 638.) .) Leistritz also makes a skid mounted MPP that takes suction from a well’s casing if rod pumps are used. It can also take suction from several well casings. The MPP lowers the casing gas pressure that, in turn, increases the downhole liquid level in the annulus. All of this allows the operator to speed up the rod pump to increase crude oil production. The Leistritz design involves adding a small stream of liquid from the discharge of the rod pump to the MPP’s suction to act as the seal flush and screw sealant.

654 Flowse lowserve MPPs Currently not recommended due to numerous failures in Chevron and nonChevron applications.

Note

Ap plic pl ic ation ati on s Flowserve (formerly Ingersoll Rand) claims to have supplied 48 MPPs. Its largest, MP1, pumps up to 280,000 bpd at a differential pressure of 1,000 psi. A list of Flowserve installations is currently not available. Flowserve’s largest pump is installed in Venezuela at Sincor. Flowserve claims that the installation is successful, but this claim has not been verified. Most of the other Flowserve MPPs are onshore, but one is installed on an offshore platform in the Middle East. Flowserve is also looking for a user with whom it can develop a downhole twin screw pump.

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Orientation and Drivers Flowserve pumps are designed to be installed horizontally. horizontally. Usually, Usually, they are driven by electric motor drives controlled by ASDs, ASDs, although they may be driven driven by natural gas engines or other drivers. This enables the flow to be controlled to match production requirements. requirements. Flow is usually controlled from suction suction pressure or wellhead manifold pressure.

Packaging For new installations, Flowserve pumps are usually packaged as skid mounted units or units ready for grouting. Units include strainers, valves, piping, pressure and temperature gages, and discharge separators. Flowserve surface pumps are commonly packaged by outside contractors, working from Flowserve engineering standards. Of course, replacement pumps or new units can be purchased as individual items.

Testing Facilities The Flowserve testing facilities are in Brantford, Ontario, Canada. The facilities can now test with water, oil, and injected air. Particulate cannot be added to the test flowstream.

Particulate Handling and Speed Speed These pumps are usually run at 1,800 rpm but are also run slower, based on the amount of particulate entrained in the stream and the economics of the project.

Materials Materials and Coatings Flowserve’s Flowserve’s standard material for the pump case is carbon steel, but the pumps can also be made of stainless steel or duplex stainless steel. Flowserve is testing various coatings for the screw tips, such as deloran, Stellite, and tungsten carbide. For the case bore, chrome plating and Stellite are offered.

Mechanical Seals Flowserve has sold MPPs with the single seal using a close clearance throat bushing, as well as pressurized pressurized dual seals.

Distinct ive Features Features Like Bornemann, the Flowserve MP1 includes a liquid separation chamber with injection back to suction to act as a screw sealant.

655 655 Recomme Recommenda ndations tions and Comme Comments nts As of this writing, it is strongly recommended that only Bornemann or Leistritz twin screw pumps be considered for Chevron applications. Currently, Currently, because of Flowserve’s Flowserve’s proven poor reliability in Chevron and non-Chevron installations, the purchase of Flowserve MPPs is is not recommended. Flowserve’s Flowserve’s ability to provide provide a reliable MPP is lacking. They are considerably behind Bornemann and Leistritz. Currently, Currently, Flowserve is in the process of a complete pump redesign that also includes its production and quality control processes. Hopefully, Flowserve will improve.

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660 Manufacture nufacturers— rs—H Helico-Axia lico-Axiall MPP MPPss 661 Genera nerall Framo, a Norwegian company, company, and Sulzer, a French company, are licensed to manufacture helico-axial pumps based on the Poseidon technology that was developed jointly by Total, Total, Statoil, and the French Petroleum Institute. The helico-axial type of MPP is discussed briefly in Sec Sectio tion n 623 623.. It is an axial flow/centrifugal pump in which pressure is boosted by multiple impellers in series. Between each impeller, a diffuser directs the flow from the discharge of one impeller to the suction of the next. An external view of this pump is shown in Figuree 600Figur 600-12 12 and an internal view in Figu Figure re 600-1 600-13 3.

662 F r a m o Ap plic pl ic ation ati on s Framo built more than 60 helico-axial pumps, 23 of which are still operating. The maximum capacity available is 100,000 bpd. The Framo MPP design can deliver a pressure boost as high high as 900 psi. Table Table 8 shows some of their their installations. Figure 600Figure 600-36 36 shows that the Framo installations are predominately subsea, with 18 subsea MPPs. In addition, Framo has 2 installations onshore and 3 on offshore platform decks. Framo MPPs are used in a wide variety of applications, including including decreasing wellhead backpressure to increase production and to extend the life of a field. Its subsea applications provide the pressure needed to get the production fluid to the ocean’s surface, thereby increasing production. Framo also has units that pump fluid through a single pipeline to a processing facility several miles away. away.

Orientation and Drivers Framo can supply pumps that are horizontally or vertically mounted. Most Framo pump drivers are electric. One is driven driven by a hydraulic hydraulic turbine. Framo has also used used diesel and gas engine drivers.

Packaging Framo offers a complete subsea package, including all relevant subsea tooling, topside power, a subsea electrical distribution system, umbilical chords, and control systems. One Framo subsea unit in the Lufeng (Statoil) field has been operating since 1997. During that time, the pump lasted 7 years with no pump intervention. This pump is not included in Fig Figure ure 600 600-36 -36,, because it is not an MPP. It is a conventional centrifugal pump, deployed subsea. This pump simply illustrates that Framo has the ability to deploy reliable subsea pumps.

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Fig. 600600-36 36 Significant Framo Framo MPP MPP Installations Installations (Information Courtesy of Framo) Framo)

Cu s t o m er

Onshore Offshore Sub s ea

No .

Capacity Each (bpd)

Press. Boost (psi)

GVF (%)

Dat e

D r i v er

HP

Statoil

Offshore

1994

1

20,000

600

40

electric

1,000

Norske Shell

S ubsea

1994

1

29,000

800

42

hydraulic

1,000

Zafiro

Mobil

S ubsea

1998

3

35,000

500

75

electric

1,150

E TAP

BP

Subsea

1999

3

42,000

320

64

electric

1,200

Statoil

Offshore

1999

3

40,000

360

50

electric

1,500

Lennox

BHP UK

Onshore

2003

1

75,000

430

65

electric

1,150

Celba

Amerada Hess

Subsea

2003

5

11,000

600

75

electric

1,100

Mutineer/ Exeter

Santos

Subsea

2004

3

45,000

430

40

electric

1,500

Huwaila

ADCO

Onshore

2006

2

23,000

1,100

65

electric

1,300

BP

Subsea

2006

4

51,000

400

74

electric

2,400

Stat Statoi oill

Subse Subsea a

2006

4

53,00 ,000

500

68

elec electtric

3,00 ,000

Shaybah

S audi Arabia

Onshore

2006

1

100,000

450

87

electric

1,300

Vincent

Woodside E .

Subsea

2007

4

100,000

600

70

electric

2,400

Brenda #2

Oilexco N.S.

Subsea

2008

1

100,000

500

65

electric

1,500

Location or Fi e l d Poseidon Gulfax A SMUBS

Gulfax A&B

Schiehalion Tor Tord dis

Testing Facilities Framo has a complete full-scale test facility in Norway. Norway. It can test subsea pumps, fully submerged and dry mounted, under actual field conditions. The Framo test facility includes a multiphase test loop equipped with a separator, pumps, and compressor.

Particulate Handling and Speed Speed Note that these pumps pumps run fast, up to 5,100 rpm in Framo’s case. case. With this this high speed, the pump would be expected to suffer erosion if sand is present. Framo tested one of its pumps with a high concentration of sand, using different coatings on the impellers and diffusers. Framo claims that “the impeller/diffuser erosion was minimal”. It is not clear what is meant by “minimal”, but apparently, some wear did occur, and the duration of the test is unknown. Coatings that were tested include Stellite and tungsten carbide. Chevron has no experience with sand erosion in a helico-axial pump.

Materials Materials and Coatings Framo can make its pump’s pump’s cases out of carbon steel for onshore applications or duplex or super duplex for subsea and offshore platform applications. For particulate handling handling and reduced wear, wear, Framo will coat their impellers impellers and diffusers with different coatings, including Stellite and tungsten carbide.

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663 Sulz ulzer Ap plic pl ic ation ati on s Sulzer has built 21 helico-axial pumps. The maximum capacity available is Model MPP12 at approximately 650,000 bpd. Sulzer also has MPPs deployed that can deliver a maximum pressure boost of 1200 psi. Figu Figure re 600-3 600-37 7 shows Sulzer installations. From Fig Figure ure 600 600-37 -37,, it can be seen that most of Sulzer’s Sulzer ’s installations installations are either onshore or on an offshore platform. It includes only one MPP for subsea, the Nautilus, but it was never never deployed. It was a vertical vertical pump, while the remaining remaining pumps listed in Fig Figure ure 600 600-37 -37 are horizontal. Sulzer Pumps) Fig. 600600-37 37 Significant Sulze Sulzerr MPP MPP Installations Installations (Information Courtesy of Sulzer

Cu s t o m er


Mo d e l

Capacity Each (bpd)

Press. Boost (psi)

GVF (%)

D at e

No .

Dr i v er

HP

F rance

E lf

Onshore

1994

1

MP P 3

50,000

600

100

E lectric

600

S iberia

J SC Chernogornefi

Onshore

1997

2

MP P 7

42,000

200

86

E lectric

540

(1) Nautilus(1)

Tot Total al

Subse Subsea a

1998

1

MPP4

50,00 ,000

600

71

Elect Electrric

1,75 ,750

Duri, Indonesia

Caltex Pa Pacific

Onshore

1998

1

MP P 7

125,000

150

100

E lectric

700

North Sea

Dunbar Dev.

Offshore

1999

2

MP P 5

90,000

1,100

90

E lectric

6,000

Saudi Arabia

Aramco

Onshore

2000

1

MP P 7

47,000

300

59

E lectric

750

Siberia

Yukos

Onshore

2001

2

MP P 11

280,000

540

91

E lectric

8,800

S iberia

TNK Nizhnevartovsk

Onshore

2001

2

MP P 7

75,000

210

90

E lectric

2,650

Siberia

Yukos

Onshore

2002

2

MP P 11

280,000

540

91

E lectric

8,800

S iberia

TNK Nizhnevartovsk

Onshore

2003

1

MP P 7

150,000

210

90

E lectric

3,210

Siberia

TNK BP

Onshore

2004

1

MP P 7

260,000

110

90

E lectric

3,210

Algeria

Agip

Onshore

2006

2

MP P 7

60,000

1,100

90

E lectric

3,350

BP

Offshore

2007

1

MP P 8

180,000

1,200

95

E lectric

2,650

Lotte Dassan

Onshore

2007

2

MP P 6

14,000

340

20

E lectric

70

Location or Fi el d

North Sea Korea 1

Nev Never dep deplo loy yed. ed.

One of the pumps listed in Fig Figure ure 600 600-37 -37 is the Chevron Duri helico-axial pump, installed for testing in 1998. It was run for only a few months. (Refer to Sectio Sec tion n 613 6138 8.) Like all the other MPPs, the Sulzer installations were predominately used to transport multiphase fluid long distances. Sulzer also has some that increased production by reducing reducing wellhead backpressure, backpressure, where it claims the economic economic payouts are usually less less than 2 years. Finally, Finally, Sulzer claims it has re-activated re-activated dead wells using their MPPs.

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Orientation and Drivers Sulzer can supply pumps that are horizontally or vertically mounted. All pumps supplied to date are electric motor driven.

Packaging To date, Sulzer has not packaged its pumps on skids.

Testing Facilities Sulzer has an existing test loop in France and another loop under construction in the UK. Both will be able test an MPP with a mixture of nitrogen and water. Each one has the same maximum capacity of 4,000 m3/hr (600,000 bpd), but the UK unit is considered larger because it will be able to pump more water at 700 m 3/hr (11,000 bpd) and nitrogen nitrogen at 3,500 m 3/hr (530,000 bpd). Sulzer can test at just about any suction pressure up to 430 psi. Because Sulzer tests with a water/nitrogen mixture, it needs to make adjustments to match the pump’s characteristics to that of a proposed crude oil/natural gas mixture. Sulzer does this by adjusting the pump suction’s water/nitrogen water/nitrogen density such that it is the same as that expected under crude oil/natural gas.

Particulate Handling and Speed Speed If sand is present, Sulzer coats its impellers and diffusers with a proprietary coating, called Sulzer Metco, “SUME”. Sulzer claims the coating is 5 to 10 times more wear resistant to sand than stainless steel and/or carbide coatings. Sulzer has a couple of installations in Siberia where the sand content is 300 ppm. Like Framo helico-axial pumps, Sulzer MPPs run fast, up to 6,800 rpm. With this speed, if sand is present, erosion would be expected, even with a SUME coating.

Materials Materials and Coatings Sulzer makes its pump cases out of carbon steel for onshore applications and either duplex or super duplex for f or offshore platform installations. For applications that involve particulate in the incoming flowstream, Sulzer will coat the impellers and diffusers with SUME. (Refer to Particulate Handling and Speed in Sec Sectio tion n 663 663.) .)

664 664 Recomme Recommenda ndations tions and Comme Comments nts On several occasions, Chevron has requested that Framo demonstrate or present data to show that its pump’s wear from particulate is indeed minimal, but Chevron has not received much supporting evidence from Framo, other than statements that the wear is minimal. Framo claims that the angle at which the flowstream particulate hits the the impeller vane has been optimized, optimized, minimizing the the wear. (This angle is usually found to be roughly 30 degrees.) The problem is that the angle of the incoming flowstream particulate (as it leaves the case and contacts the impeller) will change, depending on its speed and density. Thus, in reality, a variable angle is required, such as perhaps, one provided by a variable inlet guide vane.

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Framo has tested its MPP with quartz sand in water using a tungsten carbide coating on the leading edge of the impellers, the wear rings, and other potentially wearing parts. The pump eroded somewhat somewhat with a significant significant reduction in efficiency efficiency.. Chevron has no operational experience with sand erosion in a helico-axial pump and, to date, does not recommend these pumps be used in particulate containing streams. Anyone who considers a helico-axial pump for use where sand is present should investigate the erosion issue more thoroughly before proceeding with any purchase. The reliability of helico-axial pumps is suspect. Some applications have MTBFs on the order of 5 years, but many have MTBFs of only 2 years. At a presentation, Framo listed a number of installations, but when questioned about their reliability, reliability, Framo often found fault with the installation, the application, or the operation of the equipment for the failures which often occurred within 2 years.

670 Manufacture nufacturers— rs—P Progressing rogressing Ca Cavity MPP MPPss 671 Genera nerall There are two major manufacturers of progressing cavity pumps (PCPs) that can be designed for multiphase applications. They are Moyno and seepex. Bornemann, Netzsch, Mono, and Tarby Tarby also manufacture PCPs, PCPs, but they have not actively actively tried to gain MPP business and are not discussed in this section. As discussed in Sec Sectio tion n 620 620,, a PCP is a single, hardened steel alloy serpentine rotor that revolves inside and seals against a stationary stator, usually manufactured of an elastomeric material. Lubrication between the two is absolutely necessary. necessary. The pumped fluid enters the the pump near the coupling coupling and is discharged discharged axially at the end of the screw. Most of the PCPs used in multiphase service are installed on the surface, lying horizontally. Some are also installed vertically, downhole, run by a long shaft from an electric motor on the surface. Also, their speed is often controlled by an ASD. PCP manufacturers claim they can pump multiphase fluids up to 100 percent gas. Despite this, and because a PCP must never run dry, surface PCPs should be limited to a GVF of 30 percent, unless an adequate and reliable external or recycled liquid stream is introduced into suction that keeps the GVF at or below 40 percent. The maximum GVF for PCPs deployed down hole should be 40 percent. Finally, Finally, PCPs should not be used if slugging will occur, because it is likely that the GVF will exceed 40 percent under these conditions. As mentioned earlier, slugging always leads to a GVF of 100 percent. Chevron’s Chevron’s experience to date indicates that, even if pumped fluids are restricted restricted to GVFs in the 40 percent percent range, the MTBFs for PCPs will typically run in the 2 year to 3 year range.

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672 Mo y n o Appl Ap pl icati ic ati ons on s The Moyno MPP is called the “Moyno Tri-Phase System”. Moyno claims to have manufactured 150. Most of the Moyno installations are in Canada and the United States. A lesser number are installed in Venezuela, Venezuela, Trinidad, Mexico, and Colombia. All Moyno machines are installed on the surface. Most are onshore, with a few on offshore platforms. Moyno has not deployed any pumps subsea. Moyno claims it can pump up to 60,000 bpd of multiphase fluid to 900 psi with a GVF up to 95 percent. Moyno claims that its PCP MPPs are reliable, running up to 10 years with minimal maintenance. Fig Figure ure 600 600-38 -38 is a list of some of the Moyno installations. As can be seen from Fig Figure ure 600 600-38 -38,, most Moyno pumps are small, with only one having a flowrate as high as 60,000 bpd with a 125 HP electric motor. motor. What is unusual is that many of Moyno’s earlier pumps used packing. The later Moyno installations use a modified single or dual pressurized mechanical seal. Packing or even a conventional single mechanical seal, without a close clearance bushing, is not recommended for environmental and safety reasons. The modified single mechanical seal typically uses an API flush plan 11, 21, or 32 to the seal chamber, entering the pump through a close clearance throat bushing. This type of single seal is described in Single Mechanical Seals in Sec Sectio tion n 632 632.. (1) Fig. 600600-38 38 Significant Moyno MPP Installations Installations (Information Courtesy of Moyno)

Location or Oi l Fi el d

C u s t o m er

D at e

No .

M o d el

Capacity (bpd)

Seal or Pac k i n g

Dr i v er

HP

Canada

Renaissance E

J an-97

1

BF D-2

29,000

P acking

E lectric

100

Canada

P robe E xplor

J an-98

1

BP D-4

7,000

P acking

E lectric

30

Venezuela

Maxus

J ul-98

1

BP D-4

12,000

P acking

E lectric

75

Canada

TriLink

Apr-99

1

BP D-5

7,000

P acking

E lectric

20

USA

Mobil E xp

Aug-99

1

BP D-2

29,000

Dual S.

E lectric

125

Canada

BP Amoco

Nov-99

1

BP D-4

7,000

P acking

E lectric

30

USA

U of Tulsa

S ep-00

1

BP D-6

11,000

Single S.

E lectric

75

Canada

P ancanadian

Dec-00

1

BP D-4

12,000

P acking

E lectric

50

Canada

AE C Oil/Gas

Mar-08

1

BP D-4

7,000

Single S.

E lectric

60

Canada

Triumph E .

Apr-08

1

BP D-2

3,000

P acking

E lectric

10

USA

E xxon/Mobil

Aug-08

1

BP D-2

29,000

Dual S.

E lectric

125

BP E xp

Apr-00

1

BP D-2

29,000

Dual S.

E lectric

125

Control CTR

S ep-08

1

BP D-1

60,000

Single S.

E lectric

125

Trin Trinid idad ad

Ony Onyx Res

J an-0 an-08 8

1

BPD-4

5,00 ,000

Dual Dual S.

Elect Electrric

50

Mexico

P emex

-

1

BP D-4

15,000

Dual S .

E lectric

100

Colombia USA

1

Note: Information Information for Location (onshore, (onshore, offshore offshore or subsea), Delta P, and GVF is not available

Most of the Moyno pumps reduce wellhead backpressure to increase production and extend the life of oil wells. Moyno also points out that its pumps have, in some cases, brought back to life “dead” wells.

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Orientation and Drivers Moyno can supply pumps for use in the horizontal position. The drivers to date have all been electric motors, most driven through ASDs.

Packaging Moyno will provide packaged pump skids with valving and instrumentation if requested.

Testing Facilit Facilit ies Moyno does not own a test loop testing facility. facility. It has used others in the U.S. and internationally.

Particulate Handling and Speed Moyno MPPs run with a maximum speed of 550 rpm. Moyno claims it has experience pumping sand at concentrations up to 5 percent. The Moyno MPPs have also pumped salt, which can be just as abrasive.

Materials Materials and Corrosio n The standard material for Moyno pumps is 316 SS for the rotor and a nitrile based elastomer for the stator. Moyno coats its rotors with tungsten carbide if particulate is in the fluid stream. Other materials are available upon request.

Distinct ive Features Features Moyno pumps are conventional, with an elastomer stator and metal rotor. They have no unique features.

673 s eepex pex Ap plic pl ic ation ati on s seepex has factories in Ohio and Germany. Before 2004, seepex supplied approximately 50 MPPs through another company to extract water and methane gas from coal bed seams. Since 2004, seepex has made 16 PCP MPPs with 12 still installed—all onshore. Currently, Currently, seepex has an order for two additional pumps to be deployed on offshore offshore platforms. seepex does not have any subsea pumps yet, but one is scheduled for development by 2010. seepex installations include reducing wellhead backpressure to gain more production. seepex also claims to have successfully replaced other suppliers’ pumps that were gas locking. A complete list of seepex installations is not currently available.

The maximum flowrate available for a single seepex MPP is currently 50,000 bpd. The pump’s maximum pressure boost is 600 psi. However, seepex claims a higher pressure boost can be obtained obtained by connecting connecting pumps in series. A system system that uses PD pumps in series is very difficult to control and often leads to failure. PCP pumps, as has been mentioned mentioned several times earlier, earlier, cannot run dry, dry, thus the control system for series operation is very complicated. Unless a pressure vessel is installed

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between the pumps to provide provide a cushion of fluid fluid for the second pump, pump, the second pump can easily run dry if the the flow from the first pump pump is not adequate. Series operation of PCPs should be avoided, unless there is just no other pump or pumping system that can meet the application need, and the pressure vessel between the two pumps is included in the system design. design.

Orientation and Drivers They are all motor driven, usually using ASDs.

Packaging seepex does not provide packaged pump skids with valving and instrumentation.

Testing Facilities seepex claims it has tested its pumps in its flow loop in Ohio at a continuous GVF of 99 percent and up to 100 percent for a short duration. seepex uses nitrogen for testing. seepex claims that 1 percent nitrogen or less is enough to keep the pump lubricated and running without damage. seepex further claims that nitrogen and also natural gas, directly from an oil well, provide better lubrication than air. To date, Chevron has no experience with these tests or the testing facilities. Until more information is available, these pumps should be operated at a GVF of 40 percent or less. seepex further claims that its pumps exhibit good reliability because it uses:

•

A compli complicated cated computer computer program program to to optim optimize ize the exact interferen interference ce fit fit betwee between n the rotor and stator, which minimizes the contact surface;

•

A propri proprietary etary elastomer elastomer,, hydrog hydrogenate enated d nitri nitrile le (HNBR) (HNBR) for for stator stator material, material, which is further chlorinated to reduce friction and heat generation;

•

An “Equ “Equal al Wall Wall Stat Stator” or” that that has has a unifor uniform m rubber rubber thic thickne kness ss all all around around each each cavity. cavity. This is different than a conventional stator, where the elastomer has a varying thickness. seepex claims this design allows higher pressure boosts, dissipates heat more efficiently, efficiently, and allows the pump to handle higher GVFs. It is also much shorter than a conventional stator, stator, which is an advantage, especially on an offshore platform where space is a premium.

Particulate Handling and Speed Speed seepex pumps run at a maximum of 350 rpm.

Materials Materials and Coatings seepex makes its PCP cases out of various materials, including carbon steel, stainless steel, and duplex. The rotors can be made out of these same materials, plus titanium. For a high GVF, seepex recommends coating the rotors with its proprietary hard chrome material, material, called Duktil. In addition addition to being good good at a high GVF, the Duktil material offers good abrasion resistance. Additionally, if pumping high GVF streams, seepex recommends chlorinated HNBR as stator material to reduce friction.

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Distinct ive Features Features Having an elastomeric stator and metal rotor, the seepex basic pump designs are conventional. However, the seepex “Equal Wall Stator”, described in Testing Facilities in Sect Section ion 673 and Equal Wall Stator in Sec Sectio tion n 61 6144 44,, is unique in the industry.

674 674 Recomme Recommendat ndations ions and Comme Comments nts Chevron has had success with PCPs but only in services that have approximately 40 percent GVF or less. Historically, Historically, Chevron has had field problems pumping higher GVF streams due to poor lubrication between rotor and the stator. stator. As mentioned before, the MTBF of PCPs in multiphase service is typically 2 years to 3 years.

680 Manufacture Manufacturers—E rs—Electric lectric Submersible Submersible (ESP (ESP)) MPPs PPs 681 Genera nerall Most ESPs are installed downhole. They must fit in the well casing, and for this reason, the diameter of the pump’s pump’s body is small, and there are many pump stages to develop the head. Thus, the pumps are very long and thin. The ESP consists of several impellers in series with sleeve type bearings between each impeller (in the more robust designs), all lubricated by the fluid being pumped. An ESP assembly for a multiphase application, from bottom to top, consists of a motor, a protector (also called the seal), usually a gas separator, sometimes a gas handler, and the ESP itself. A cross section of an ESP is shown in Figu Figure re 600-2 600-20 0. The two most common ESP manufacturers are Centrilift and Schlumberger (Reda). Each has been active in trying to capture additional MPP business. Both claim that their units can handle high concentrations of gas, 90 to 100 percent, with gas separators and gas handlers. Even with these devices, ESPs should not be used if the GVF exceeds 60 percent. With slugging, the MPP will experience a 100 percent GVF stream at times, and if this is anticipated, ESPs should not be used.

682 Centri ntrililift ft Ap plic pl ic ation ati on s Centrilift ESPs are common throughout the oil industry. Centrilift defines an MPP as one that has a GVF of over 20 percent. More than 25 percent of Centrilift installations meet this definition. The maximum capacity of Centrilift MPPs is 14,000 bpd, with a maximum pressure boost of 5,000 psi. psi. These maximums, based on a fairly low GVF, GVF, decrease as the GVF increases. Note that, since an ESP is usually installed downhole, 14,000 bpd represents the production from a very large well.

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An installation list, such as the one that describes Schlumberger ESPs in Figure Figu re 600-3 600-39 9 , is not available. Centrilift ESPs are deployed as MPPs in at least three Chevron installations: in Thailand, New Mexico, and California. The installation in New Mexico involves 27 ESPs that pump an unknown quantity of gas but probably less less than 40 percent. They have have been operated for only 2 years, years, but to date, no failures have occurred. Centrilift applies its MPPs in oil wells that are onshore, on offshore platforms, and subsea. Centrilift has installed a few onshore and on platforms in the horizontal orientation. As with many MPPs, Centrilift MPPs have been used to increase production by decreasing decreasing wellhead backpressure. backpressure. If applied subsea, the pumps typically are installed in a subsea well(s) and pump the well’s well’s fluid to the ocean’s surface. To To decrease the pressure boost, the ESP can discharge into a skid on the seabed floor. The skid collects fluid from several ESPs or wells and uses another ESP to send the fluid to the surface. In these cases, they offer a complete design for the subsea installation. Centrilift has the ability to apply its pumps at temperatures up to 400°F (204.4°C). Their MPPs are sized as any other multistage ESP. ESP. Centrilift uses a proprietary computer program, AutoGraphPC, that analyzes the fluid volume in each stage as the fluid progresses up the pump.

Orientation and Drivers As stated in Sec Sectio tion n 681 681,, Centrilift ESPs can be positioned vertically or horizontally in a well or horizontally on the surface. All Centrilift pumps are electrically driven.

Testing Facilities Centrilift has a test facility in Claremore, Oklahoma, where it can test ESPs up to 10,000 bpd and vary the GVFs up to a maximum of 50 percent.

Particulate Handling and Speed Speed Centrilift usually runs its pumps at 3,600 rpm but has the ability to run them up to 4,800 rpm, using an ASD to increase the electrical frequency. frequency. If sand or other abrasives are present, Centrilift coats its impellers and bearings with a surface treatment called Armor I or Armor X. Note that the bearings are lubricated by the produced fluid. If the bearings bearings were uncoated, the sleeve sleeve bearings between each impeller (in the robust design) would wear quickly in the presence of sand. Centrilift claims the Armor X is harder than Ni-Resist or even silica sand. Armor X is almost as hard as tungsten carbide. The intent is to crush the sand getting into the bearings and flush it it through the bearings bearings with the pumped stream stream without damage. This becomes problematic as the GVF of the stream increases, since gas will not effectively flush particulate away or provide lubrication.

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Materials Materials and Coatings Centrilift offers a wide variety of materials, depending on the production fluid chemistry and the environment. As mentioned in Materials and Coatings in Sectio Sec tion n 682 682,, Centrilift coats its bearings with Armor X to extend the life of the bearing when sand is present. present.

Design Improvements Centrilift claims it has a unique MPP impeller design that avoids gas locking, and this alone can pump up to 70 percent free gas. Gas locking is common for centrifugal pumps and, especially, ESPs, if fed a high GVF. To avoid gas locking, Centrilift impellers deploy a steep vane angle with large balance holes. Centrilift offers two types of gas separators: rotary and vortex. One or the other is used and attached ahead of the inlet to their ESP. ESP. The separated gas is vented into the annulus between the pump or tubing and the casing, above the liquid level. Centrilift claims that its pumps can handle 90 percent free gas with the vortex separator.

683 Schlumbe chlumberge rgerr (Re (Reda) da) Ap plic pl ic ation ati on s Schlumberger ESP MPPs are installed downhole in an oil well. They are not deployed horizontally on the surface. Their maximum flowrate is 9,000 bpd, with a maximum pressure boost of 4,000 psi. As with Centrilift, these numbers decrease as the GVF increases. As of 2004, Schlumberger deployed 17 MPPs, as shown in Fig Figure ure 600 600-39 -39.. Schlumberger) (1 of 2) Fig. 600 600-3 -399 Significant Schlumberger Schlumberger ESP ESP MPP MPP Installations Installations (Information Courtesy of Schlumberger)

Cu s to m er


Dat e

No .

Mo d el

Capacity (bpd)

Delta P (psi)

GVF (%)

Dr i v er

HP

Colombia

Hocol

Onshore

Apr-02

1

538

-

-

60

E lectric

-

New Mexico

Devon

Onshore

Aug-03

1

538

-

-

65

E lectric

-

New Mexico

Devon

Onshore

Apr-04

1

538

-

-

65

E lectric

-

Midland, TX

Aethon

Onshore

Mar-04

1

400

-

-

30

E lectric

-

New Mexico

Devon

Onshore

Mar-04

1

400

-

-

>60

E lectric

-

Midland, TX

Oxy

Onshore

Apr-04

1

400

-

-

-

E lectric

-

Garden Grove

Oxy

Onshore

Aug-04

1

400

370

3,000

-

E lectric

250

Garden Grove

Oxy

Onshore

Aug-04

1

538

-

-

-

E lectric

-

Garden Grove

Oxy

Onshore

-

1

538

-

-

-

E lectric

-

New Mexico

Devon

Onshore

-

1

400

-

-

-

E lectric

-

New Mexico

Devon

Onshore

-

1

400

-

-

-

E lectric

-

New Mexico

Devon

Onshore

-

1

400

-

-

-

E lectric

-

New Mexico

Devon

Onshore

-

1

400

-

-

-

E lectric

-

New Mexico

Devon

Onshore

-

1

538

-

-

-

E lectric

-


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Fig. 600 600-3 -399 Significant Schlumberger Schlumberger ESP ESP MPP MPP Installations Installations (Information Courtesy of Schlumberger) Schlumberger) (2 of 2)

Cu s t o m er


D at e

No .

Qatar

QP D

Offshore

-

Colombia

Hocol

Onshore

Occidental

Onshore


E lk Hills, CA

Mo d el

Capacity (bpd)

Delta P (psi)

GVF (%)

Dr i v er

HP

1

538

-

-

-

E lectric

-

-

1

538

-

-

-

E lectric

-

F eb-05

1

-

-

-

>50

E lectric

-

Schlumberger has installed MPPs in oil wells that are onshore, with at least one associated with an offshore platform. Schlumberger has not deployed any in subsea locations. The pumps are used primarily to decrease a well’s downhole backpressure, thereby increasing increasing production. production. Schlumberger has also replaced conventional ESPs with its MPP version, using their gas handler, after the previous conventional ESP gas locked. Schlumberger ESPs are manufactured by its subsidiary, subsidiary, Reda. Schlumberger also owns Framo, who makes helico-axial MPPs. (Refer to Sec Sectio tion n 623 for a discussion on helico-axial pumps in general and Section 062 for specific information on Framo). As a result, Schlumberger offers a gas handler that is based on Poseidon technology. technology. It is a helico-axial pump called the Poseidon ESP that is 6.3 meters long and is attached ahead of the suction of a Reda ESP. ESP. With this helico-axial gas handler, Schlumberger Schlumberger claims it can pump a GVF up to 75 percent. Schlumberger’s first gas handler unit was installed in 2003, designed to handle approximately 60 percent gas. Since 2003, Schlumberger Schlumberger has installed installed 16 similar machines at various locations, none of which involve a GVF as high as 75 percent. Schlumberger claims that its Poseidon gas handler can pump such a high GVF because it homogenizes the the mixture, puts some of of the gas back in solution, solution, and increases the fluid pressure, reducing the gas volume and bubble size as the stream enters the conventional ESP, ESP, the next section after the Poseidon. Schlumberger has several MPPs with the Poseidon gas handler installed in fields that experience a GVF from 45 to 65 percent. One of them listed in Fig Figure ure 600 600-38 -38,, in Colombia, involved its Poseidon MPP replacing a conventional ESP. Schlumberger claims that the new MPP eliminated gas locking and increased production by 100 100 percent, pumping a fluid fluid with a GVF of 60 percent. Another Another installation in Elk Hills included a Poseidon MPP installed in the vertical portion of a well that also includes a horizontal segment. Schlumberger claims that the MPP increased production by 40 percent. Finally, Finally, a Poseidon pump was installed in the Garden Grove field. This field is a CO2 injection field, and the Poseidon pump was installed to replace a conventional ESP that gas locked from CO2 breakthroughs. Schlumberger claims the new MPP increased production production by 130 percent. Schlumberger uses its proprietary software to size their MPPs. During this process, it derates the pump to offset a high GVF. GVF.

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Orientation and Drivers As mentioned, Schlumberger pumps are deployed downhole in wells in the vertical and horizontal positions. The pumps have not been deployed on the surface. All Schlumberger pumps are electrically driven. Schlumberger MPPs are controlled to shut down on high motor temperature, as opposed to the conventional approach of using motor current. If the GVF is high, motor current is not a reliable indicator of motor problems.

Packaging Schlumberger packages its pumps itself. It packages them to be installed in pods, under packers, and in series (two ESPs in one well).

Testing Facilit Facilit ies Schlumberger has a testing facility in Bartlesville, Oklahoma, and another in Rosharon, Texas. Texas. Schlumberger test facilities include two test wells that can test pumps requiring up to 1,500 HP. HP. Schlumberger does not not test with natural gas, gas, using air and water instead. Schlumberger also tests bearings without liquid lubrication to evaluate conditions with slugs of gas.

Particulate Handling and Speed Schlumberger tries to mitigate the erosive affects of sand with a proprietary hard material called 5530. Schlumberger can run its pumps up to 80 hz or approximately 4,800 rpm, using an ASD to control the frequency. frequency.

Materials Materials and Coatings The materials used in Schlumberger MPPs depend on the fluid chemistry and the environmental conditions conditions in the well. It offers a wide variety of materials, including 5530 metallurgy. If CO 2 is present, Schlumberger offers a material called “Redalloy”. In addition, Schlumberger uses a silicon carbide for the bearings. Schlumberger claims that this silicon carbide bearing material is self-lubricating, offsetting the effect of poor lubrication from the gas-laden multiphase fluid.

684 684 Recomme Recommendat ndations ions and Comme Comments nts ESPs are considered to be reliable for applications having GVFs of approximately 40 percent. However, even liquid only ESPs have MTBFs of only 2 years to 3 years. It is difficult to get information on ESPs that demonstrate even this reliability when the GFV exceeds 60 percent. Despite claims by Centrilift and Schlumberger that they can do better, actual proven reliability to date is not impressive. As mentioned earlier and Centrilift agrees, the average ESP is pulled every 2 years to 3 years for maintenance. Some of the reasons are described in Driver in Sectio Sec tion n 625 625.. ESP reliability will decrease further if the pumped fluid is a multiphase fluid having a substantial amount of particulate and a GVF over 60 percent.

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Based on operating experience throughout Chevron, ESPs should not be used horizontally, horizontally, above grade, in place of an API 610 pump. Chevron has several examples of this orientation, and the reliability has been poor, requiring frequent maintenance, with availability sometimes being only a few months.

690 690 Sizing Sizing of the MPP MPP,, Its Its Driver, Driver, and Associated Associated Facilities Facilities (Upstrea (Upstream m Appl Ap plii c ation ati ons) s) 691 691 Twin Screw Screw MPP MPP Design Design Guide Guide for Upstrea Upstream m Applications Figure Figu re 600-4 600-40 0 shows the MPP design guide for upstream applications.

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Fig. 600 600-4 -400 Twin Screw MPP MPP Design Design Guide for Upstream Upstream Applications

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692 Sizi izi ng The following are required to size an MPP: •

Average verage and maximu maximum m antic anticipa ipated ted gas volume volume fracti fraction on (GVF (GVF); ); The GVF is simply the percent gas in the total flow. (The units for gas flow are standard cubic feet per day or actual cubic feet per day, with the suction pressure and temperature provided.) provided.) GVF percentage will will determine if a screw sealant is necessary. Screw sealant is discussed in Sec Sectio tion n 633 633.. Gas oil ratio (GOR) can also be provided in place of GVF, but the liquid water must then be provided.

•

Liqu Liquid id oil oil flo flowr wrat atee (bb (bbll per per day) day);;

•

Liqu Liquid id wate waterr flow flowra rate te (bb (bbll per per day day); );

•

Constitue Constituent nt breakdown breakdown of the the liqui liquid d (e.g., (e.g., percent percent compositi composition on of water water,, oil, oil, natural gasoline, gas/oil fraction, and sand);

•

Suct Suctio ion n pres presssure ure to pump pump;;

•

Suct Suctio ion n temp temper erat atur uree to pump pump;;

•

Discharge pressure;

•

Liquid viscosity;

•

The sand or partic particulat ulatee quantit quantity y by weight weight and and volume, volume, size distribut distribution, ion, its composition (i.e., is it quartz or any other hard mineral), and its shape (sharp or rounded edges); This affects the size of the inlet screen mesh, the types of coatings for the internal parts, and the pump’s internal clearances. (Refer to Sec Sectio tion n 637 637.) .)

•

Wax or para paraff ffin in cont conten entt and and clou cloud d poi point nt;; Solid wax particulate in the inlet stream will plug up the MPP suction strainer or filter. Either a duplex strainer or duplex filter is always recommended to catch particulate and debris in the inlet stream, including applications in which wax is not expected. If wax is present, a duplex filter (not the coarser mesh duplex strainer) should be used. The filter must be sized to have a larger area and a greater collapse differential pressure than the duplex strainer. The duplex design is always recommended to enable switching screens while operating. Specific recommendations are given in Suction Strainer in Sec Sectio tion n 639 639.. For example, refer to Sec Sectio tion n 61 6135 35,, Princess Field Lessons Learned, item B and Sectio Sec tion n 613 6136 6, Main Pass 313 Lessons Learned, item F.

•

The flow flow regim regimee (in (in parti particul cular ar,, the the tende tendency ncy for sluggi slugging) ng);; Slugging may not be a significant problem if the pump is located near the well(s). However, slugging slugging could be severe if the pump is located a distance away with the suction line traversing hilly terrain. Slugging is discussed in Sectio Sec tion n 635 635.. It is often recommended that the suction and discharge pipe be simulated to determine the extent of slugging. Refer to Sec Sectio tion n 639 for additional information on this subject on Mitsue Field, Lessons Learned.

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•

Type of driver driver:: electri electricc motor motor direct direct drive (with (with or without without an adjust adjustable able speed drive), a diesel engine driver, natural gas engine driver, hydraulic turbine drive, belt drive, etc.; –

–

– –

–

•

An electric motor direct drive drive runs the MPP at the speed of of the driver, but but the speed can be varied if an adjustable speed drive (ASD) is installed. An ASD allows the operators to change speed to compensate for a field’s changing flow conditions or to increase the speed to maintain the same production rate as the the pump wears or to simply make up for unanticipated conditions that show up after the pump is installed. By design, the diesel engine, engine, natural gas engine, and hydraulic turbine drives are all adjustable speed drives. These drives can all be used to vary the speed of the MPP by operating the pump speed off a specified set suction pressure. Hydraulic drives are available available and sometimes very appropriate, especially if a field is being water flooded. Belt drives, though not not recommended due to maintenance maintenance problems, are much cheaper than the others, and with them, speed can be changed in steps by replacing sheaves and belts. Note that belt drives are limited to approximately 250 HP. Additional criteria for for choosing the type type of drive are the size and weight weight allowed by the application (especially if downhole, on a platform, or subsea), its reliability, reliability, and the type of fuel available (e.g., diesel, natural gas, or electric power).

Estimated Estimated variation variation of flow flow conditio conditions ns over over the the desig design n life life of the field or the the pump, realizing that there there are many unknowns that cannot cannot be determined prior to purchasing the MPP, such as: – –

–

What production rate will will be possible possible as the field ages? What composition composition changes (e.g., percentages of water, water, gas, particulate, H2S, and crude) can be anticipated in an existing field after the installation of an MPP? (Changes in the percentage of H 2S will affect the pump’s material selection.) An estimate of the recycle, slip, slip, and flashing factor. factor. The pump’s pump’s recycle liquid is usually hotter than the feed to the MPP. MPP. Therefore, it may flash into gas, occupying the capacity of the pump. If this is expected, the pump may need to be designed larger. Flashing is discussed in Sec Sectio tion n 638 638.. Recycle, slip, and flashing are discussed in Sec Sectio tion n 695 695..

Due to these uncertainties, the MPP should be designed with flexibility in mind. If the MPP is electric motor driven (and most are), an ASD is strongly recommended such that the speed of the MPP can be adjusted to compensate for potential production increases increases or decreases. If practical for additional additional flexibility, flexibility, an API 682 Seal Flush Plan 32 is recommended, rather than relying on a Seal Flush Plan 11 or 31. Sec Sectio tion n 610 6100 0 also offers some assistance in estimating future production flow conditions.

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693 Pump Siz Sizing ing Ca Calcula lculation MPP suppliers rate their pump capacities in barrels per day of mixed flow at suction conditions. Mixed flow means the combined flow of oil, water, particulate, and gas in barrels per day. Normally, Normally, gas is described as either standard cubic feet per day (SCFD) or actual cubic feet per day at suction conditions (ACFD). Sometimes, it is described by the GOR. The following equation shows the conversion of the flow of gas to equivalent barrels per day (BPD) at suction suction temperature and pressure: Actual cubic feet per day (acfd) = (Gas rate, scfd) (14.7/Actual suction press in psia) (Actual suction temp/520°R) temp/520°R) Z, (Eq. 600-1)

where: Z is the compressibility factor and 520°R = 460°F + 60°F (Z is often taken as 1). After the gas rate is converted to actual cubic feet per day, it must be further converted to bpd using the following conversion: Actual barrels per day (abpd) = (Actual gas flowrate, acfd) (7.481 gal/ft 3) (1 bbl/42 gal) (Eq. 600-2)

Example: Given: oil production rate = 1,000 bopd GOR = 400 scf/bbl Water cut (wc) = 25% of the liquid rate (water and oil) Suction pressure = 50 psig Suction temperature = 150°F Discharge pressure = 350 psig API gravity = 24 Gas compressibility, compressibility, Z = 0.98 Steps: 1.

Dete Determ rmin inee the the gas gas rate rate as as foll follow ows: s: (1,000 bpd) (400 scf/bopd) = 400,000 scfd 150°F + 460°F = 610°R 50 psig + 14.7 = 64.7 psia Actual gas flowrate = ( 400,000 scfd ) (14.7 psia/64.7 psia) (610°R/520°R) (0.98) = 104,870 acfd Actual bpd of gas = (104,870 acfd) (7.481 gal/ft 3) (1 bbl/42 gal) = 18,680 bpd of gas

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2.

Dete Determ rmin inee the the wate waterr rate rate:: Water rate = (wc/(100



wc)) (oil rate)

= (25/(100  25)) (1,000 bopd) = 330 bbl of water per day (bwpd) 3.

Dete Determ rmin inee the the tota totall liqu liquid id rat rate: e: Total liquid rate = 1,000 + 330 = 1,330 bbl of liquid per day (blpd) = 40 gpm

4.

Determ Determine ine the the total total mixe mixed d flowra flowrate te of all all substa substance nces: s: Total flowrate to the pump suction = (18,680 + 1,330) bpd = 20,010 bpd (at 50 psig and 150°F)

694 694 Gas Gas Volume Volume Frac Fraction tion (GVF (GVF)) Suppliers use the term gas volume (or void) fraction (GVF). This is simply the actual gas flowrate (by volume, determined at suction conditions) divided by the total mixed flowrate (by volume). For the above example: GVF = 18,680/20,010 = 0.93 (or 93%) (Eq. 600-3)

695 695 The Recycle, Recycle, Slip, Flashing Flashing Factor Factor for Twin Screw MPP MPPss An MPP must be sized to handle more that just the design capacity obtained from Sectio Sec tion n 691 because of both external and internal losses. These losses can come from external liquid recycle, which may flash into gas or internal slip (flow from discharge back to suction). Flashing is discussed in Sec Sectio tion n 63 638 8. Refer to Recycle, Slip, Flashing Factor in Sec Sectio tion n 638 for specific values for the recycle, slip, flashing factor. As mentioned in Recycle, Slip, Flashing Factor in Sect Section ion 638 638,, one simply multiplies the design capacity obtained in Sec Sectio tion n 691 by the recycle, slip, flashing factor to get the actual pump capacity ca pacity.. In the above example, if the factor is 1.15 percent, the design flowrate of the pump would be: Design flowrate = 20,010 bpd (1.15) = 23,011 bpd or 670 gpm (Eq. 600-4)

Section Sectio n 638 recommends that once the MPP flow diagram is determined, the streams be simulated using HYSIM or PRO II. This simulation will provide a good estimate of the amount of flashing and, thus, a better estimate of the increased pump capacity one needs to add. Sec Sectio tion n 691 6910 0 shows and describes a typical flow diagram.

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696 696 Pump Efficie Efficiency ncy for Twin Twin Screw Screw MPPs MPPs “Slip” for a twin screw pump is defined as fluid that flows backwards through the screw clearances. As slip increases, the pump efficiency is reduced. Slip increases as the pump differential pressure increases or if the internal pump clearances increase due to wear. Slip decreases as the viscosity of the fluid increases and as the pump speed increases. increases. If pumping a pure incompressible liquid, the volume of the pumped fluid does not change, and the increasing pressure difference across each lock is constant. (Refer to Figure Figu re 600-4 600-41 1.) In this pure liquid application, the pump’s efficiency is maximized. Fig. 600600-41 41 Pressure Pressure Distribution Distribution when Pumping Pumping Only Only Liquid DISCHARGE PRESSURE

E R U S S E R P G N I S A E R C N I

SUCTION PRESSURE

DIRECTION OF FLOW

SLIP

SCREW LOCKS LIQUID ONLY

If pumping a multiphase fluid with a substantial GVF, GVF, however, most of the pressure rise occurs in the final stages of the pump. (Refer to Fig Figure ure 600 600-42 -42.) .) This is due to the compressibility of the large volume of gas at the inlet, where the gas volume is substantially reduced, with relatively low pressure increases. The low pressure rise across the first few locks means that, in relative terms, a reduced amount of slip exists there, with an increased amount of slip across the latter locks (those near the outlet). This reduced amount of slip across the first few locks is somewhat offset by the fluid’s lower viscosity there, which is due to the relatively large amount of gas in the stream. This reduced viscosity allows the fluid to slip easier through the first few locks, versus later in the pump, where the volume of gas is greatly reduced, and the multiphase fluid becomes more viscous. The bottom line is that the pump efficiency will will be lower if pumping pumping a multiphase fluid than if pumping a pure liquid.

697 697 Overall Overall Mechanica Mechanicall Efficiency Efficiency Calculation Calculation Mechanical efficiency is defined as the theoretical horsepower required for pumping liquid and gas, divided by the actual horsepower delivered to the shaft. This is shown in the following equation:

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Fig. 600600-42 42 Pressure Pressure Distribution when Pumping a Multiphase Fluid DISCHARGE PRESSURE

E R U S S E R P G N I S A E R C N I

SUCTION PRESSURE

DIRECTION OF FLOW

SLIP

GAS PHASE

LIQUID PHASE

Overall mechanical efficiency = (Theoretical gas HP + Theoretical liquid HP)/shaft HP (Eq. 600-5)

where: Theoretical liquid hp = [liquid rate (gpm)] [pump DP (psi)]/1,714 Theoretical gas HP = (Inlet press, press, psia) psia) (Gas rate, acfm) (ln [(1+ [(1+ pump DP/inlet pressure)/229.7]) Actual shaft HP = [equivalent mixed flowrate (gpm)] [pump DP (psi)]/1,714 (the mechanical efficiency factor) The mechanical efficiency factor is usually 1.1 to account for inefficiencies due to bearings, gear boxes, seals, etc. For the above example: Theoretic Theoretical al liquid liquid HP = (40 gpm) gpm) (300 (300 psi)/1 psi)/1,714 ,714 = 5.0 HP Theoretical gas HP = (64.7 psia) psia) (73 acfm) [ln(1+ (300 psi/64.7 psi/64.7 psia))/29.17] psia))/29.17] = 35 HP (Note that both equations are rounded to nearest 5 HP.) Actual Actual shaft shaft HP = [(670 gpm) (300 psi)/1,71 psi)/1,714] 4] (1.1) (1.1) = 130 HP HP Overall mechanical efficiency = (Gas HP + liquid HP)/shaft HP = (5 + 35)/130 35)/130 = 0.31 or 31%

698 698 Volumetric olumetric Efficie Efficiency ncy Calc Calcula ulation tion Volumetric efficiency is the delivered pump capacity divided by its theoretical capacity. Mathematically, it is expressed as: Volumetric efficiency, Ev = Qc/Qt (Eq. 600-6)

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where: Ev = volu volume mettric ric ef effici ficien ency cy Qc = actu actual al deli delive vere red d capa capaci city ty,, gpm gpm Qt = theore theoretic tical al capac capacity ity,, gpm (pro (provi vided ded by by the vend vendor or after after a give given n model is specified)

699 699 Pump Sizing Sizing Sprea Spreadshee dsheett for Twin Twin Screw Screw MPPs MPPs An example of the Excel twin screw pump sizing spreadsheet is shown in Figure Figu re 600-4 600-43 3. The following example problem is included on the Fig Figure ure 600 600-43 -43 spreadsheet to demonstrate the use of this tool. As mentioned in the example spreadsheet, information that has to be input into the spread sheet is in the gray shaded area (red font color), whereas the calculated quantities are blue and yellow font colors. The spreadsheet calculates: • • • • • • • • • • • • • • • • • • •

600-88

Water rate (bwpd) Total liquid (blpd) Form Format atio ion n or prod produc uced ed gas gas rate rate (msc (mscfd fd)) Z (the (the gas gas compress compressibil ibility ity factor factor of approximat approximately ely 1 for for suction suction pressures pressures less than 100 psig) Total ga gas ra rate (m (mscfd) Delta P (psi) Gas rate ate (ac (actual bpd) Gas rate (acfm) Total otal pump pump throug throughpu hputt (abp (abpd, d, gas, gas, and and liqui liquid) d) Total otal pum pump p thro throug ughp hput ut (gp (gpm, m, gas gas,, and and liqu liquid id)) Gas fraction (%) Theoretical li liquid HP HP Theoretical gas HP Theoretical total HP The The rec recyc ycle le,, sli slip, p, and and fla flash shin ing g fac facto tor r Equiva Equivalen lentt pump pump capac capacity ity (gpm (gpm and and bpd, bpd, incl includi uding ng the the recyc recycle, le, sli slip, p, and and flashing factor) Required bhp Mechanical ef efficiency Power (kW)

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Fig. 600 600-4 -433 Example Example of a Multiphase Pump Pump Design Sizing Spreadshe Spreadsheet et Input data into the gray shaded fields. The spreadsheet calculates the blue and yellow colored numbers. Yellow shaded columns are calculated capacity and power required required to meet given case flows and conditions.

Case 1 2 3 4 5 6 7

Case

API Gravity 24 24

Oil Rate (bopd) 1,000 1,000

Gas Rate

Gas Rate

abpd*

acfm*

Water Cut (%) 25 25

Water Rate (bwpd) 330 330

Total Pump Thruput*

Total Pump Thruput*

abpd, gas & liq 24,690 20,010

gpm, gas & liq 720 580

Total Liq. (blpd) 1,330 1,330

Gas Fraction

GOR 400 400

Form. Gas (mscfd) 400 400

Lift Gas (mscfd) 100 0

Gas Com. Fact. (Z) 0.98 0.98

Project Name Engineer Date

Total Gas (mscfd) 500 400

Recycle, Slip, Flashing Factor

Pump Suction (psig) 50 50

Equivalent Pump Capacity

The heor ore eti tica call

The Th eor oret etic ical al

Theo Th eore reti tica call

liquid hp** 5 5

g as h p * *

total hp

(%)

GPM

50 40

15% 15%

830 670

1 23,360 91 95% 45 2 18,680 73 93% 35 3 4 5 6 7 *Calculation is based on the pump suction conditions listed. **Calculation is based on the fluid theoretical horsepower to pump the liquid or gas fraction only. ***Leistritz believes the bhp is the same as pure liquid when pumping a mixture of gas and liquid.

Suction Temp. (°F) 150 150

Pump Dsch. (psig) 350 350

Delta F (psi) 300 300

Req

Mech

Power

BPD

*** BHP

Effcy

kW

28,390 23,010

160 130

31% 31%

120 95

Contacts: Bob Heyl


Updated:

6 0 0 - 8 9


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The recycle, slip, and flashing factor was developed from field trials. It is used to increase the total pump throughput to account for slip in the pump and gas flashing out of the solution from the recycle stream. Minimum recommended value for this factor is 15 percent. The spreadsheet uses the following guidelines guidelines for calculating the factor to be used: •

15 perc percent ent for API grav graviti ities es less less than than or equa equall to 25 25 and having having any GVF GVF percent;

•

25 perce percent nt for for API grav graviti ities es great greater er than than 25 25 and GVFs GVFs less less than than 50 50 percen percent; t;

•

33 percen percentt for API gravit gravities ies greater greater than 25 and and GVFs GVFs greater greater than 50 percent percent..

For example, the background and need for the recycle, slip, and flashing factor is explained thoroughly in Sec Sectio tion n 613 6134 4 Lessons Learned, item J.

6910 6910 Piping and Instrum entation Diagram (P&ID) (P&ID) for a Twin Twin Screw MPP MPP Early in the decision process, a “draft” P&ID of the MPP and its associated


Pu m p Man u al

The recycle, slip, and flashing factor was developed from field trials. It is used to increase the total pump throughput to account for slip in the pump and gas flashing out of the solution from the recycle stream. Minimum recommended value for this factor is 15 percent. The spreadsheet uses the following guidelines guidelines for calculating the factor to be used: •

15 perc percent ent for API grav graviti ities es less less than than or equa equall to 25 25 and having having any GVF GVF percent;

•

25 perce percent nt for for API grav graviti ities es great greater er than than 25 25 and GVFs GVFs less less than than 50 50 percen percent; t;

•

33 percen percentt for API gravit gravities ies greater greater than 25 and and GVFs GVFs greater greater than 50 percent percent..

For example, the background and need for the recycle, slip, and flashing factor is explained thoroughly in Sec Sectio tion n 613 6134 4 Lessons Learned, item J.

6910 6910 Piping and Instrum entation Diagram (P&ID) (P&ID) for a Twin Twin Screw MPP MPP Early in the decision process, a “draft” P&ID of the MPP and its associated equipment should be developed. Fig Figure ure 600 600-44 -44 shows a typical diagram. The type and number of alarms, shutdowns, and various devices required for a twin screw MPP installation should follow the requirements of appropriate Chevron and industry specifications. Each installation is somewhat different, and each should be reviewed to determine the proper devices. The diagram in Fig Figure ure 600 600-44 -44 is considered a typical representation of such devices for a typical electric motor driven MPP installation: installation: Fig. 600 600-4 -444 Piping and Instrumentation Instrumentation Diagram (P&ID) (P&ID) of an MPP MPP Installation Installation (Courtesy (Courtesy of Leistr itz Corporation)

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The various devices shown in the P&ID are:

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1.

Suction Suction strainer strainer or or filter: filter: The dual dual straine strainerr or filter filter install installed ed in the the suction suction line line can be switched from one basket to the other while continuing to run the MPP. A high differential pressure alarm and shutdown are required. The shutdown is required to be set lower than the collapse pressure of the basket strainer/filter. Each basket’s surface area in the dual strainer is required to have an area 150 percent of the inlet pipe pipe area. A mesh size of 1/8 inch square square is recommended. If wax is present, a dual filter should be used instead of the dual strainer with each basket’s filter having an area 200 percent of the inlet pipe area. (Refer to Sec Sectio tion n 613 6135 5 Lessons Learned, item B and Sec and Sectio tion n 613 6136 6 Lessons Learned, item F.)

2.

Instrumen Instruments ts on the suction suction line: line: A high high temperatu temperature re and a high/lo high/low w pressure pressure alarm should be installed in the suction line, immediately ahead of the pump.

3.

MPP instrume instruments: nts: The The MPP shou should ld have have an RTD RTD or thermo thermocoup couple le touching touching the outer race of each antifriction bearing. It should be connected to a monitor to alarm at 200°F (93.3°C). As an alternate, a RTD or thermocouple could be installed in the lube oil reservoir set to alarm at 180°F (82.2°C). Refer to Lubrication in Sec Sectio tion n 622 622.. Additionally, an accelerometer should be installed on the case, over each bearing, to be connected to a vibration monitor. monitor.

4.

Pressure Pressure safety safety relief relief valve: valve: A pressure pressure safety safety relief relief valve valve is required required on the pump discharge line line ahead of any valve to avoid avoid overpressuring the the positive displacement MPP and the discharge piping. The safety valve should relieve back to suction entering entering the suction line line upstream of the alarms/shutdowns alarms/shutdowns described in item 2. Chevron prefers the safety valve relief to be routed to a suction tank or as far upstream as possible. A separate safety valve located on the discharge piping is required, as opposed to a safety valve built into the pump.

5.

Instrumen Instruments ts on the dischar discharge ge line: line: A high high temperat temperature ure alarm alarm and a high pressure alarm/shutdown on the pump discharge discharge are required upstream upstream of any block valve.

6.

Liquid Liquid knockou knockoutt boot or vessel vessel on the the discharg discharge: e: If the the GVF is ever expecte expected d to be above 95 percent, a liquid knockout knockout boot or vessel vessel is recommended. It is to be located on the MPP discharge discharge piping upstream upstream of any block valve. It is required to supply screw sealant and seal flush fluid to the MPP. MPP. Note that, if slugging conditions are expected, the GVF will exceed 95 percent, and the knockout boot or vessel is required. The knockout boot can be a wide spot in the line, or it can be a separate vessel. Either one should include a high/low level gage with a low level alarm. (Refer to Sec Sectio tion n 633 and Sec and Sectio tion n 635 635.) .)

7.

Instrumen Instruments ts on the screw screw sealant sealant/seal /seal flush flush line: line: A flow flow indicato indicatorr with with a low flow alarm on the screw sealant/seal flush line from the knockout boot to the MPP inlet. If the crude oil is light, more than 30 degrees API, a cooler (not shown) is recommended to minimize flashing inside the MPP. Flashing will occupy much of the MPP capacity and will limit the amount of production from the field. This cooler is not shown in Fig Figure ure 600 600-44 -44.. (Refer to Sec Sectio tion n 613 6134 4 Lessons Learned, item K.) 


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8.

Bypass/rec Bypass/recycle ycle line: line: Piping Piping shoul should d be installe installed d between between the sucti suction on of the the MPP and its discharge to allow the multiphase fluid to bypass the pump before startup to relieve the wellhead shut-in pressure. It may also be necessary to use it during startup of the system to control the amount of fluid the MPP is pumping through through the entire discharge discharge line, reducing the discharge discharge backpressure backpressure that the pump is pushing against. This bypass line should be blocked during normal operation.

9.

Electric Electric motor motor instrum instrumentat entation: ion: RTDs RTDs are required required for for the motor motor stator stator windings, two per phase. Additionally, Additionally, the motor should have vibration sensors, either proximity probes for sleeve bearings or an accelerometer on the motor bearing cases for antifriction antifriction bearings. The sensors sensors should be connected to a vibration monitor. Finally, an RTD or thermocouple should be mounted on the outer shell of each sleeve bearing or touching the outer race of each antifriction bearing. The vibration sensor and temperature indicators indicators for the bearing are not shown in Fig Figure ure 600 600-44 -44..

10. ASDs: ASDs are highly recommended with an MPP electric electric motor driver driver to allow the MPP to vary its speed. A separate computer with a variety of alarms and indicators is deployed to monitor the ASD and the motor driver. driver. 11. Seal drain tank: A seal drain tank tank with associated associated piping is is shown in the P&ID to collect mechanical seal leakage. It should have a high level alarm.

691 6911 Separator Separator Sizing f or Twin Screw MPPs MPPs The following is a guide for sizing the downstream separator: •

If the the GVF is is less less than than 95 perce percent nt and and no slugg slugging ing is is expect expected, ed, the the exter external nally ly supplied screw sealant is not needed, and a downstream separator is not necessary. sary. (Note that, if no slugging is expected, but an API Seal Flush Plan 32 has been chosen, an external source source [a source other than the MPP pumped pumped stream] of liquid, such as water or oil is required.)

•

If the the GVF will will exce exceed ed 95 perc percent ent,, the screw screw sealan sealantt needed needed is is 4 percen percentt of the the pump capacity using the the following formula: formula: Amount of screw sealant (bpd) = 4 percent of the MPP capacity (bpd) (as calculated in Sec Sectio tion n 69 693 3.)

If the pump’s final capacity is 23,011 bpd, the screw sealant would be 4 percent of that or 920 bpd. If the MPP suction line is simulated using Olga and Olga indicates that a gas slug will occur for 1 hour, the downstream separator’s capacity would be: Separator capacity = 950 bpd/24 hr per day, or approximately 38 bbl/hr (1,600 gal/hr or 27 gal/min). A 38 bbl storage volume would be a vessel approximately 6 feet in diameter by 8 feet in height. This is a fairly large vessel, but its size size can be decreased if the MPP is moved closer to the well(s). If this closer location is practical and another simulation is performed, Olga will indicate a reduced possibility for slugs, and the slugs will be of a shorter duration. This, of course, allows the downstream vessel to be reduced in size.

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6100 100 Typical MPP MPP Application Opportunities Opportunities 6101 6101 General General There are many opportunities for MPP applications in upstream and a few in downstream. In upstream, an MPP is often compared to a conventional system that consists of a production separator separator vessel, transfer pumps, a gas compressor, compressor, possibly possibly a test separator, associated metering/instrumentation, metering/instrumentation, and usually two pipelines—one for the gas and another for liquid. By contrast, an MPP installation is simpler, simpler, consisting of the MPP itself and a single production pipeline pipeline to transfer both both gas and liquid. liquid. MPPs boost pressure pressure without the the need to separate, costing less to purchase and install, plus saving space and weight.

6102 6102 Upstream Upstream Application Opportunities—Listing The following is a list of the opportunities for upstream applications. applications. Each opportunity is detailed further after this listing: 1.

Reducing Reducing the the back back pressure pressure on on the well( well(s) s) or taking taking suction suction from from an oil oil well(s) well(s) to increase the production and extend the life of the well(s);

2.

Replac Replacing ing old, old, worn worn out out conve conventi ntiona onall facilit facilities ies;;

3.

Bringi Bringing ng aban abandon doned ed well wellss back back to to life life;;

4.

Produ Produci cing ng marg margin inal al fiel fields ds;;

5.

Transpo Transporting rting productio production n several several miles through through one pipeline; pipeline;

6.

Producing Producing subse subseaa reservoirs reservoirs with with a more cost cost effecti effective ve installat installation ion and and ease of retrieval;

7.

Overco Overcomin ming g the stat static ic press pressure ure from from a deep deep subsea subsea well well;;

8.

Redu Reduci cing ng emis emissi sion ons; s;

9.

Produc Producing ing into into a high high pres pressur suree heade headerr.

Ad van tage tag e MPPs also have a particular advantage in many applications—saving applications—saving weight and space compared to a conventional system, especially on a platform.

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6103 6103 Upstream Upstream Application Opportunities—De Opportunities—Details tails The following describes in more detail each of the MPP upstream application opportunities: 1.

Taking sucti suction on from an an oil well(s) well(s) to to increase increase producti production on and extend extend the the life of of the well(s); The value of increased production is used to pay out the MPP installation. An MPP can be installed to take suction from one or more oil wells. This is probably the most common common of all MPP applications. applications. The MPP reduces the wellhead backpressure. In addition, an MPP can be economical when it takes suction from the discharge of almost any type of artificial lift, including gas lift, electric submersible pumps (ESPs), progressing cavity pumps (PCPs), and rod pumps (where the flow line is tied to the casing). (An MPP taking suction from a well(s) that has a downhole progressive cavity pump [PCP] installed will not usually increase production.) –

Gas Lift Gas lift involves natural gas injected into the tubing string at intervals from the bottom to the top. Gas bubbles decrease the fluid density, density, which helps move the fluid to the surface. Installing an MPP at the surface will increase production, because because it essentially lowers lowers the bottom hole flowing flowing pressure by the same amount as the the wellhead backpressure. An MPP could could also reduce the amount of gas lift required, saving energy costs. The quantity of gas involved in gas lift is often considerable. The MPP has to process this gas, along with any increase in production from the well. This often requires the MPP to be large and, perhaps, uneconomical. As stated many times, each installation must be evaluated on its own merits.

–

Electric Submersible Pumps Pumps (ESPs) The capacity of an ESP depends on its speed and the diameter of its impellers. It follows a normal centrifugal pump performance curve of differential pressure (head) versus capacity. Production could be improved by replacing the ESP with with a larger capacity ESP. ESP. The replacement pump would have to be one that operates at a higher speed or has larger impellers. Increasing its speed may not be feasible or, at least, expensive. Increasing the impeller size is often not feasible, because the impeller diameter is limited by the casing. An MPP at the surface reducing the discharge pressure of the ESP will decrease the ESP differential pressure. This moves the ESP operating point on its performance curve and increases capacity.

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–

Rod Pumps A rod pump consists of a motor, speed reducer, reducer, and “chicken head” on the surface next to the wellhead. The “chicken head” moves a downhole positive displacement displacement pump up and down down at the bottom of a long rod, rod, usually 1,000 feet or so long. Since the pump is a positive displacement type, theoretically its capacity remains constant for any discharge pressure. For this statement to be entirely true, slip has to be ignored. The downhole pump is connected to the well tubing string. The casing surrounds the tubing. Crude oil, water, etc., enters the casing annulus through perforations. Fluid in the casing annulus feeds the downhole pump. The pump can be be sped up to produce produce more, if the level remains high enough. If the level gets too low, low, the rod pump is shut down or slowed down to wait for more fluid to enter the casing. If one can lower the pressure in the casing annulus, the level will rise and the rod pump can be sped up to produce more. This is often accomplished by installing installing a casing gas gas collection system. system. A casing gas gas collection system consists of a vacuum pump connected to a piping network that is connected to several well casings at the surface. It keeps the casing pressure low and, thus, the downhole casing level as high as possible. An MPP connected immediately downstream of a rod pump with this type of system will not appreciably increase production. It merely lowers the discharge pressure of the downhole pump without affecting the level in the casing. Occasionally, Occasionally, if rod pumps are spread out with a considerable distance between them, a casing gas collection collection system is not not installed, and the casing at the surface is connected to the flow line. Here, the casing pressure is fairly high, and the downhole downhole level in the the casing is substantially substantially lower. lower. In this case, an MPP taking suction from the discharge of a rod pump will increase production, production, because the casing casing gas pressure is reduced along with the rod pump discharge pressure. Note, however, to get more production out of the the well, the rod pump has to to have the capability to increase its speed. The logic that an MPP will not increase production if the rod pump has a casing collection system is not entirely correct. Production will increase a little because the MPP lowers the downhole pump discharge pressure. These pumps wear out and are operated almost until complete failure. During a large part of their operating life, they circulate much of their capacity back to suction (“slip”). Slip increases as they wear. An MPP installed at the surface lowers the discharge pressure of these pumps, which in turn, increases their capacity by decreasing slip. The pump life is thereby increased. Connecting an MPP to several wells like this extends the Mean Time Between Failures (MTBFs) of these pumps, saving a considerable amount of maintenance cost and down time.

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2.

Replac Replacing ing old, old, worn worn out out conve conventi ntiona onall facilit facilities ies;; A cost effective MPP can replace old, worn out conventional facilities and often keep a marginal field operating longer. Its cost is almost always less than replacing the conventional facility. facility. For example, several Bornemann MPPs were installed in older German oil fields taking suction from wells in different fields. The MPPs increased the production, extending the life of the fields. Without the MPP, the oil field would have been shut in.

3.

Bringi Bringing ng aban abandon doned ed well wellss b back ack to life; life; MPPs have brought back to life wells that were shut in, because they were considered too uneconomical due to the amount of gas and water produced. In these cases, the cost of the conventional system was too expensive to make reopening the wells profitable. The lower cost MPP made these wells profitable again.

4.

Prod Produc ucti tion on fro from m margi margina nall field fields; s; A common application for an MPP is to move multiphase fluid from a remote, marginal, or satellite oil field to a processing facility several miles away. Without Without the MPP pressure boost, the wellhead pressure is often not enough to transport enough fluid to make the remote marginal well profitable. A more expensive conventional system could do this, as well. However, the MPP is less expensive and requires only one pipeline, whereas the conventional system usually requires two. a.

In Californ California, ia, the the MidwayMidway-Suns Sunset et field field needed needed to increase increase productio production n from some remote wells. A twin screw pump was installed, and the production increased dramatically. dramatically. Refer to the pump installation in Fig Figure ure 600 600-45 -45 and the strip chart results in Figu Figure re 600600-46 46.. As can be seen in Figu Figure re 600600-46 46,, the total oil and water production increase due to the installation of the MPP was 1,750 bpd, that is, from 1,000 bpd to 2,750 bpd. The wells involved were located in a remote location and by installing the MPP, the back pressure on the wells was reduced significantly, significantly, causing the increase in production. Note that, when a second pump was installed, another increase of 650 bpd was seen (from 2,750 bpd to 3,400 bpd). The production increase was so cost effective that Midway-Sunset now has four twin screw MPPs in operation. (Refer to Sectio Sec tion n 613 6138 8 .)

b.

600-96

In Duri during the the field testing of the helico-axial helico-axial MPP versus the twin twin screw MPP, MPP, the production increased from 10,900 bopd to 12,500 bopd when the twin screw pump was put online. When the helico-axial MPP was put online, the increase, though smaller, was still significant, increasing from 10,900 bopd to 11,900 bopd. (Refer to Fig Figure ure 600 600-47 -47 and Figure Figu re 600-4 600-48 8.)

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Fig. 600 600-4 -455 Bornemann Twin Twin Screw Pump at at Midway-Sunse Midway-Sunsett

Fig. 600 600-4 -466 Strip Chart Chart Showing the Increase Increase in Production at Midway-Sun Midway-Sunset set

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Fig. 600 600-4 -477 Duri, Indonesia Indonesia,, MPP MPP Field Field Testing Testing

Fig. 600 600-4 -488 Strip Chart Chart Showing the Increased Increased Oil Production with MPPs during Field Testing Testing in Duri, Indonesia Indonesia

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5.

Transpo Transporting rting producti production on several several miles through through one pipeline; pipeline; An MPP can pump fluid to an existing processing facility several miles away, through a single pipeline. This is attractive compared to a conventional facility, facility, which would require more equipment to perform the same task, including a possible second pipeline. pipeline. For example, the Mitsue Mitsue pump, mentioned several times in this manual, was moved to the Princess Oil Field in Canada, where it moved multiphase fluid from several wells to the processing facility, facility, 18 miles away, away, through one pipeline. (Refer to Sect Section ion 613 6135 5 for further details.) The capability to pump mixed fluids through miles of pipeline can also be important for a new offshore platform, eliminating the need for a second pipeline to shore. Another good application for an MPP is to boost pressure from subsea wells that are far from an existing platform. Often, preliminary analysis shows that the recoverable reserves for the new field are too small to justify a stand-alone full production platform that is closer to the wells. A subsea MPP has the capability to eliminate the need for a new platform.

6.

More cost effectiv effectivee subsea subsea insta installat llation ion and and ease ease of retrieval; retrieval; For a subsea installation, space is valuable, and an MPP requires a much smaller, simplified seabed support structure than a conventional system. Lifting an MPP pump from the seabed for maintenance is easier and less expensive than a conventional pump and compressor, because it weighs less than their combined weight.

7.

Overco Overcomin ming g the stat static ic press pressure ure in in a deep subs subsea ea well; well; Deep subsea oil wells often have their production limited because of the static pressure needed to transport transport the fluid from the wellhead wellhead to the surface. This becomes worse as the well depletes, depletes, and its wellhead pressure pressure decreases. If located a mile below the surface, the pressure required to move fluid to the surface would be approximately 2,300 psi. A subsea MPP, MPP, taking suction from such a wellhead, can increase the fluid pressure significantly to get the fluid to the surface, reducing the wellhead backpressure and greatly increasing production.

8.

Redu Reduci cing ng emis emissi sion ons; s; MPPs reduce pollution by eliminating the emissions from the many pieces of equipment needed for a conventional system. For example, in California, the Midway-Sunset field needed to add a few new wells, but the permitting process for the vent for the atmospheric collection tank had stalled the field’s production. An MPP MPP, which required no no emission permit, permit, was installed to pump the gas and liquids to the existing permitted collection facilities several miles away.

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9.

Produc Producing ing into into a high high pres pressur suree head header er.. Occasionally, a well’s pressure is not sufficient to transfer its production into a distribution header supplied by higher pressure wells. An MPP, MPP, taking suction on the well and boosting its pressure, allows the lower pressure well(s) to produce into the higher higher pressure line, thus increasing increasing the field’s field’s total production. Refer to the Sec Sectio tion n 612 6125 5 example for Main Pass 59A, Gulf of Mexico (2007).

Advan Ad van tag e MPPs also have the following particular advantage, which is extremely useful in many applications: Reducing offshore platform costs by reducing weight and space. An MPP weighs less and involves a smaller footprint than a conventional system. This is important for an offshore platform, where the additional weight and space would be costlier if a conventional separation system were installed. An MPP occupies approximately 25 percent of the area and weighs approximately 25 percent as much compared to a conventional system.

6104 6104 Downstream Downstream Applications There are several downstream applications that are important to consider: 1.

Flar Flaree gas gas knoc knocko kout ut drum drum pum pumps ps.. MPPs have successfully replaced flare gas KO drum pumps in refining. Since the pumps can handle gas, water, particulate, and oil, the pumps are well suited for this application. They are particularly more reliable than the old reciprocating pumps often used in these situations. The MPPs also use mechanical seals instead of the packing required by the recips, thus reducing emissions. In new installations, the old required flare gas pits are no longer required, since unlike the recips that required the pit to provide their high NPSHr, the twin twin screw MPPs require little little or no NPSHr. Since Since the KO pits can contain and confine the often hazardous vapors leaked by the recip packing, locating the pump at ground level where vapors are not confined, allows for a much less expensive installation, providing providing a safer work place, as well.

2.

Pumping Pumping high high vapor vapor containi containing ng streams streams or or boiling boiling hydroca hydrocarbon rbon stream streams. s. Since twin screw MPPs have little or no requirement for NPSHr, they can handle these streams very well. Twin screw MPPs are especially well suited in this regard and will soon be covered by API 676 standards when the 3 rd edition of that standard is published (expected 2009).

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6110 6110 Technology Qualification Process (TQ (TQP) P) 611 6111 Introduction Introduction MPP technology is being used in applications with ever more challenging environments and process conditions. To To determine the risk involved in using MPPs in such applications, the pumps must be evaluated for operability and reliability. reliability. Chevron has developed a TQP to assist in making this determination. Chevron’s system is a process initially developed by Det Norske Veritas (DNV).

6112 6112 Chevron Chevron TQP TQP The following is taken from the Chevron TQP home page. TQP is a versatile and scalable process to formally assess new (and existing) technology and make high quality, quality, risk based decisions regarding the technology’s technology’s further development or deployment and utilization on projects. TQP also provides a common language for the understanding and communication of a technology’s “readiness for use”. The logic diagram in Figu Figure re 600-4 600-49 9 gives an overview of the major process elements. Fig. Fig. 600600-49 49 Logic Diagra Diagram m

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“… We will have demonstrated leadership in deploying technology to create value across the company, company, both high impact and where multiple opportunities for application create high impact. It will be measurable and widely recognized. Leaders will put a priority on enterprise behavior so that we can take full advantage of the intellectual capital of an integrated company, quickly deploying best practices and technology.” - Dave O’Reilly, The Next Five Years. The link to the home page of TQP is provided for further reference: http://etc.chevron.com/team-tqp/default.asp Contact Chris Chaplin of the TQP team for additional information: [email protected].

6113 6113 Definition Definition of Qualification Qualification Qualification is the process of providing the evidence that a technology will function within specific operational limits with a specified level of confidence.

6114 6114 Machinery Machinery TQP TQP Mark Weatherwax Weatherwax of the ETC Machinery and Power Systems team has developed a general overlay for the general TQP discussed above. The overlay is intended to be used as a guideline for evaluating the specific risks involved with a specific set of project conditions. conditions. The following following logic diagrams, Figur Figuree 600600-50 50 and Fig and Figure ure 600 600-51 -51,, taken from the overlay, are logic diagrams of how the process should be used to evaluate risks associated with machinery technologies. At the time this MPP manual is being published, the machinery TQP is in development. Figure 600-5 Figure 600-52 2 is an example of the use of this machinery TQP in flowsheet format. The example is for a General Electric LM6000PF gas turbine mechanical drive application. For more information contact Mark Weatherwax Weatherwax by email at [email protected].

6115 6115 Technology echnolo gy Development Development Stages Stages (TDSs) (TDSs) for MPPs MPPs MPP technology is composed of four different pump types: twin screw, helico-axial, progressing cavity pumps (PCPs), and electric submersible submersible pumps (ESPs). Each pump type is developing developing at its own rate, and each has expanding application application and performance envelopes, where where pump manufacturers are increasing increasing current limits on capacity, capacity, differential pressure, gas volume, reliability, and operating environment (onshore, on platforms, or subsea). Each has a history of proven experience onshore and in association with platform installations. Each pump type design and current limitations have been covered in this manual, but regarding subsea in particular, each pump type is developing rapidly.

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Fig. 600 600-5 -500 Logic Diagram—Ma Diagram—Machinery chinery Technology Technology Qualification Qualification Process (Part (Part A)

Typically the potential equipment selection is a specific supplier model or train configuration. Other cases may include a process specification and development of equipment to meet the process conditions. In either condition, the process operating conditions and any unusual ambient conditions should be identified during the qualification process.

Potential Equipment Selection

YES

In Chevron Fleet?

NO

Used Within Existing Chevron Operating Parameters?

All Sub Components Within Experience?

YES

YES

Do Lessons Learned Exist?

NO NO

Used Within Industry?

Are Operating Parameters Within Existing Industry Operation?

YES

NO (TC4)

YES

Identify Individual Components That Are Step-outs

YES YES Review of Industry Experience

Is Industry Experience Considered Acceptable?

Are Lessons Learned Incorporated?

NO

YES

All Sub Components Within Experience?

NO (TC3)

NO

YES

YES (TC2) NO

Do Lessons Learned Exist?

Document References Classified as a TC1

Document References Classified as a TC2

YES

NO YES

NO (TC4)

Are Lessons Learned Incorporated?

NO A Threat Assessment is Required.

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Fig. 600 600-5 -511 Logic Diagram—Ma Diagram—Machinery chinery Technology Technology Qualification Qualification Process (Part (Part B)

The level of effort for the Technology Technology Qualification Process should be based on magnitude of the step-outs being considered. The attendees at the Risk Assessment Assessment Workshop should also be determined based on the magnitude of the step-outs.

Potential outcomes from the Risk Assessment Workshops include determining that the risks exceed the potential benefits and therefore abandon the qualification process. 1. 2. 3. 4. 5. 6.

Risk Assessment Workshop

Identify individual risks and create create an overall Threat Register. Create a Threat Risk Table for each component identified. Create action items to address individual individual risk items. Identify alternate solutions or risk mitigation mitigation options. Use a Risk Matrix to rank each risk. Agree on Acceptance Acceptance Criteria for identified actions.

Note: Equipment risks can range from operational reliability and equipment failures to schedule risks from testing or manufacturing delays.

NO

Technology Qualification Plan

This plan is a detailed document that addresses the risks and action items identified during the Risk Assessment Workshop. The plan will become the basis for performing the Technology Qualification.

Are the risks fully addressed by the actions identified?

During this phase all the activities outlined during the Qualification Plan will be addressed. For equipment packages, packages, this typically entails the following types of activities:

NO

rd

1. Analytical analysis by Suppliers Suppliers or 3 Parties (Torsional, Lateral Rotordynamics, Stress Calcs, CFD, FEA, etc.) 2. Model testing of components. components. 3. Full scale testing of components. components. 4. Etc.

YES

Technology Qualification Execution

Individual activities may be completed at various stages in a project depending on the associated risks.

Perform a GAP Analysis. Was the Performance Criteria Satisfied?

YES

Document Qualification Process

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Fig. 600-52 600-52 General General Electri Electri c LM6000 LM6000PF PF Gas Turbi ne Mechanical Drive Drive Applic ation

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Performing a rigorous TQP evaluation to develop a TDS or Maturity Rating for a specific project requires the engineer to have a specific set of operating conditions. Since, in this manual, there is no specific application to judge against, it is not possible to provide provide definitive numbers or ratings. In each specific MPP application, application, a TDS assessment should be made of the specific pump type(s) to be considered. If the stage number assessment indicates the development stage is lower than TDS 9, a TQP evaluation should be initiated. The general TDS definitions, associated with the TDS numbers, are provided in Figure Figu re 600-5 600-53 3. Fig. 600 600-5 -533 Technology Development Development Stage Stage (TDS (TDS)) Definitions


Pu m p Man u al

Performing a rigorous TQP evaluation to develop a TDS or Maturity Rating for a specific project requires the engineer to have a specific set of operating conditions. Since, in this manual, there is no specific application to judge against, it is not possible to provide provide definitive numbers or ratings. In each specific MPP application, application, a TDS assessment should be made of the specific pump type(s) to be considered. If the stage number assessment indicates the development stage is lower than TDS 9, a TQP evaluation should be initiated. The general TDS definitions, associated with the TDS numbers, are provided in Figure Figu re 600-5 600-53 3. Fig. 600 600-5 -533 Technology Development Development Stage Stage (TDS (TDS)) Definitions

Onshore and Platform Platform Installatio ns As has been described in earlier sections of this manual, all four MPP pump types are well established, as represented by multiple surface installations both onshore and on platforms, and the technology can be assigned a TDS number of TDS 9 (field proven). The current limits of MPP technology, technology, proven in project applications, were presented (Sec (Sectio tion n 650 650,, Sec Sectio tion n 660 660,, Sec Sectio tion n 670 670,, and Sec and Sectio tion n 680 680), ), and certain aspects of the commercially available MPP technologies were compared. (Refer to Sectio Sec tion n 621 621,, Fig Figure ure 60 600-7 0-7 and Fig and Figure ure 60 600-8 0-8.) .)

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Subsea Applications Subsea applications are developing very rapidly for all the MPP designs. As was stated in the manual, these applications are in various stages of development and are for various environments and operating conditions. While ESPs in dry tree applications (pump is downhole subsea, but the driver is on a platform deck) have a significant history, history, those applications where the pump and driver are all on the seabed floor are in a much lesser stage of development ( TDS 5). Wet tree helicoaxial pumps also have a reasonable rea sonable history ( TDS 9), while wet tree twin screw pumps to date have a very limited limited number of subsea applications applications ( TDS 9). Wet tree applications of PCP MPPs are still being developed ( TDS 5).

Table of TDS Ratings Ratings f or Various Pumps f or Various Various Appli cations Figure 600Figure 600-54 54 shows in tabular form some general TDS number guidelines and important qualification limits for the various MPP designs. Note that these guidelines are based on each e ach technology’s technology’s development at the time of publication. Fig. 600 600-5 -544 TDS Ratings Ratings for Various Various MPP Pumps Pumps for Various Various Applications Pump Type Twin screw

Helico-axi al

PCPs

ESPs

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Application

TDS Number

Onshore

TDS 9

Differenti al pressure limited to 1,400 psi, flowrates limited to 370,000 bpd, GVF unlimited.

Platform

TDS 9

Differenti al pressure limited to 1,400 psi, flowrates limited to 370,000 bpd, GVF unlimited.

Subsea Seabed

TDS 9

Differential pressure limited to 750 psi, flowrates limited to 170,000 bpd, GVF unlimited, water depth limited to 5,500 ft.

Onshore

TDS 9

Differenti al pressure limited to 1,200 psi, flowrates limited to 290,000 bpd (Framo), 560,000 (Sulzer) GVF unlimited.

Platform

TDS 9

Differenti al pressure limited to 1,200 psi, flowrates limited to 290,000 bpd (Framo), 560,000 (Sulzer) GVF unlimited.

Subsea Seabed

TDS 9

Differential pressure limited to 800 psi, flowrates limited to 290,000 bpd, GVF limited to 90%, water depth limited to 3,000 ft.

Onshore

TDS 9

Differential pressure limited to 900 psi, flowrates limited to 60,000 bpd, GVF limited to 40%.

Platform

TDS 9

Differential Differential pressure limited to 900 psi, flowrates limited to 60,000 bpd, GVF limited to 40%.

Subsea Seabed

TDS 5

Considerable development required before commercial application in a subsea environment.

Onshore

TDS 9

Differenti al pressure limited to 4,000 psi, Flowrates limited to 10,000 bpd, GVF limited to 60%.

Platform

TDS 9

Differenti al pressure limited to 4,000 psi, flowrates limited to 10,000 bpd, GVF limited to 60%.

Subsea Seabed

TDS 9

Dry tree applicati ons: differential pressure limited to 4,000 psi, flowrates limited to 10,000 bpd, GVF limited to 60%, water depth limited by dry tree applications.

Subsea Seabed

TDS 5

Differential pressure limited to 900 psi, flowrates limited to 60,000 bpd, GVF limited to 40%.

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Population Chart The population chart in Fig Figure ure 600 600-55 -55 is provided to show the current common usage range of the various types of MPPs. Fig. 600 600-5 -555 Population Population of Various MPP Types Types and Their Their Operating Operating Regions

6116 6116 TQP TQP Summary Summary In general, all of the MPP technologies can be considered as proven for applications involving surface onshore and surface platform installation. It is only in subsea seabed applications that some of the technologies are currently considered less than proven, and limitations limitations are still significant. significant. Having said this, this, it is still important important to remember that, even though a technology is proven, it doesn’t necessarily mean that the technology has a high level of reliability for a specific project application. Each pump type must be evaluated evaluated for the specific environment environment and range of operating operating conditions, and its reliability must be estimated in order to make the proper selection that provides the lowest cost of ownership for the application.

6120 Economics conomics 6121 6121 General General In the past, Chevron has often avoided MPPs because the risks associated with a “new application” were considered too great to offset the benefits. The decision makers often installed conventional complex and costly facilities instead, consisting of a separator, compressor, pump, etc., as described more fully in Sect Section ion 614 614.. This was done even though the MPP alternative was more economically attractive. Such concerns are no longer valid. As shown in Secti Section on 61 6110 10,, MPPs should no longer be

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considered a “new product”. Hundreds of MPPs now function reliably throughout throughout the world, operating with great success.

6122 6122 Existing Facilities Facilities Options Often Chevron is faced with existing facilities that require extensive maintenance and repair. In such cases, Chevron needs to consider no longer replacing these facilities in kind but to install an MPP instead. There is a basic process that can be used to help the decision. The process involves comparing the economics of the following options: • • •

Cont Contin inui uing ng with with main mainte tena nanc ncee and and rep repai airs rs;; Instal Installin ling g dire direct ct replac replaceme ement nt conven conventio tional nal facili facilitie ties; s; Installing an an MP MPP.

Calculations Associated with the Options 1.

Contin Continuin uing g with with main mainten tenanc ancee and and repai repairs; rs; List the value of the current revenue, expenses, and profits for the gas and oil produced or recovered and the the cost to maintain and repair. repair. Prepare a balance sheet of annual income versus expenses, and determine if it is economical to continue in this mode of operation.

2.

Installin Installing g direct direct replacement replacement conventio conventional nal facilities facilities;; List the benefits of installing a conventional facility that includes the cash generated. Also, list its capital cost and operating expense. Compare this to option 1 to obtain a rate of return, payout period, and NPV for the conventional system.

3.

Inst Instal alli ling ng an MPP MPP. List the benefits of installing an MPP, MPP, including the cash generated. Also list its capital cost and operating expense. Compare this to “No Improvement” case to obtain a rate of return, payout period, and NPV for the MPP. MPP. Compare this to the Conventional Facility case to decide which is the most attractive.

The alternative that has the best economic outcome, taking into account risk, is the one that should be chosen.

6123 6123 New New Facilities Facilities For a new facility, facility, compare the MPP case to the conventional facility case.

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6124 6124 Factors Factors to Consider The following factors need to be considered in determining the economic payout of an MPP installation: •

MPP cost, equipment weight, foundations, foundations, possible support support systems, spare spare conducted several years ago parts inventory, inventory, and space —A paper study conducted confirmed that an installed MPP is less expensive than a conventional system, in that the MPP costs approximately 70 percent less, occupies approximately 25 percent less area, and weighs approximately 25 percent fewer pounds. The MPP has the following advantages:

– – – – – – – –

No separation vessel vessel (twin screw MPP); No compressor; Fewer instruments; One foundation; One baseplate grouted grouted (if at an onshore facility) facility) into place or one skid installation (if on a platform or subsea facility); One electrical power power supply line, line, one electrical connection, one one starter, and and other electrical components; Required spare parts for the the MPP versus those required for for the conventional system’s pump and compressor; One multiphase mixed mixed flow discharge discharge line.

•

conventional facility, facility, an MPP will MPP energy energy consumption consumption —If compared to a conventional likely cost less, but it may require more energy to operate. If power costs are high, such as at some onshore locations, and the application has a high GVF, GVF, a conventional system may be more economical. Offshore (especially if gas has no value and is intended to be flared), the MPP is likely to be more cost effective.

•

—A PI is used to measure the ability ability of the well to Productivity Productivity index (PI) —A produce, and it is defined as the ratio of the total liquid liquid rate to the pressure pressure drawdown. The PI should be a valid measure of the well productivity potential only if the well is flowing under pseudo-steady state conditions. During a transient period, the productivity index will vary, depending on the measurement of the flowing bottom hole pressure (Pwf). PI is given by the following expression: PI = Q/(Pr  Pwf) (Eq. 600-7)

where: Q = Total otal flui fluid d rate rate,, stb stb/d /day ay PI = Prod Produc ucti tivi vity ty Inde Index, x, stb/ stb/da day/ y/ps psii Pr = Rese Reserv rvoi oirr stat static ic pre press ssur ure, e, psi psi Pwf Pwf = Flow Flowin ing g bot botto tom m hol holee pre press ssur ure, e, psi psi

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•

For exam example ple,, if the the bottom bottom hole hole flowin flowing g pressu pressure re can be reduc reduced ed by 50 50 psi and and a well has a PI of 0.1, a production increase would be expected to be 5 bpd (0.1 x 50 = 5). When considering a new MPP to reduce a well’s backpressure, one must assume the bottom hole pressure is reduced by the same amount as the back pressure. This is not always always true. However, However, most of the time, the assumption assumption is accurate enough. When applying PI, make sure its definition is understood. Some people define PI as an increase in crude oil production, while others define it as the total liquid produced, meaning that the PI could include both crude oil and water.

•

—An MPP may become large if the the existing wellhead Pressure reduction limit pressure is low. low. Gas occupies a very large large volume at a low pressure. Therefore, Therefore, to reduce the wellhead pressure further, the MPP has to be very large and quickly becomes uneconomical. This can better be explained in the following example: The Mitsue pump handled 25,000 bpd of gas at 50 psig suction pressure and 10,000 bpd of liquid. If the pump were designed for a suction pressure of 0 psig, the gas volume would rise to 110,000 110,000 bpd, while the liquid rate would stay essentially the same. The pump would have to pump approximately 120,000 bpd or almost 5 times the original capacity. capacity. Under these conditions, a potential MPP may be too large large to pay out from the expected expected production increase. Many oil fields, especially older ones, have maximized their production by reducing the wellhead pressure. It is not uncommon to see a 10 psig or 20 psig wellhead pressure. If one wishes to install an MPP under these conditions, the size may be too large to be economical. Though this is generally true, there are exceptions, and each installation needs to evaluate its own economics. Note that most most subsea wells wells have a high high wellhead pressure because they need to overcome the static pressure to get the fluid to the ocean surface. Because the initial wellhead pressure is high, an MPP could reduce it significantly, significantly, making a huge impact on crude oil production, all with a reasonably sized pump.

6125 6125 Examples Examples Both of the Chevron MPP field tests (Main Pass 313 offshore platform and the Mitsue Field in Alberta, Canada) completed in early 1996 decreased wellhead backpressure and increased crude crude oil production. production. The economics for these these tests are described as follows:

Main Pass 313 Offshore Platform (1993) Extended well performance information was collected on the best performing well on the platform, well A-23D. The well showed a boost in production from 70 bopd before the MPP to more than 600 600 bopd with the pump. Later, Later, the pump maintained maintained an average increase of approximately 200 bpd.

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The installed cost of the MPP was approximately $150,000 (in 1993 dollars). The economics on an annualized basis are listed in Fig Figure ure 600 600-56 -56.. It is assumed that well A-23D was always lined up to the pump with an operating factor of 0.9 (which means that the pump is operational 90 percent of the time). The economic calculations are shown in Figu Figure re 600-5 600-56 6. Fig. 600600-56 56 Main Main Pass Pass 313 313 Economics Rev en u e/Co s t

Cal c u l at i o n

$/Yr

Oil Revenue

(200 bpod) x (330 days/yr) x ($15.00/bbl oil)

Gas R evenue

(200 bpod) x (1000 scf/bbl oil) x (330 days/yr) x ($0.12/bbl fluid)

132,000

Liquid Liquid Trea Treati ting ng Costs

(200 (200 bpod bpod)) x (1 (1 bbl bbl flu fluid id/0 /0.6 .6 bbl bbl oil) oil) x (330 (330 days/ days/yr yr)) x ($0 ($0.12 .12/b /bbl bl fluid)

(13,200)

Energy Consumption Costs

(56kw) x (2730 btu/hr/kw) x (24 hr/day) x (1/scf/ 1000 btu) x (330 days/yr) x ($0.06/mscf)

(8,100)

Added Gas Compression Cost

(200 bpod) x (1000 scf/bbl oil) x (330 days/yr) x ($0.06/mscf)

(4,000)

Net Rev en u e

$990,000

$1.097 MM/y r

Aft After Ta Tax Prof Profit

(Takes in into ac account royalties, op operating ex expenses, ses, an and depreciation.)

$570M/yr

NP V

$2.8 MM

P ayout

3 Months

Note that the analysis analysis in Figu Figure re 600-5 600-56 6 was done in 1996. Assumptions used then would be quite different today. The assumptions used then were: • • • • • • • • • • • • •

Oil price rice is $15. $15.0 00/bb 0/bbl; l; Opera peratting ing fact facto or is 0.9; 0.9; Gas pri price is $2.0 2.00/ms 0/mscf cf;; Tax ra rate is is 38 38 pe percent; Liqu Liquid id tre treat atin ing g expe expens nsee is $0. $0.12 12/b /bbl bl flu fluid id;; Roya Royalt lty y rate rate is 13.0 13.0 perc percen ent; t; Depr Deprec ecia iati tion on life life is 7 year years; s; Effic Efficien iency cy of gas gas eng engine ine power power gene generat rators ors is 30 percen percent; t; Disc Discou ount nt rate rate is 11.0 1.0 per perce cent nt;; Infl Inflat atio ion n rate rate is 3.0 3.0 perc percen ent; t; Gas Gas comp compre ress ssio ion n cost cost is is $0.0 $0.06/ 6/ms mscf cf;; Proj Projec ectt life ife is 10 years ears;; Compo Composit sitee water water cut is is 40 perce percent nt (for (for calcula calculatio tion n of total total liqui liquid d rate rate from known oil rate).

Mitsue Mitsu e Field, Slave Lake, Alb erta, Canada (1993) (1993) At approximately the same time as the Main Pass 313 pump was installed, another, larger MPP was installed in the Mitsue Field, Slave Lake, Alberta, Canada. In this situation, the economic analysis was based on accelerated production, not new production. The resulting resulting rate of return, based on Canadian economics, was 11 percent, making it a marginal project. The project went ahead anyway, anyway, partially because it was a field trial to to obtain important technical information. Later, Later, this

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pump was moved to the Princess Princess Field, also in Alberta, Alberta, Canada, at a cost of approximately $100,000 (U.S.). The economics of that installation are not currently available. However, However, the project was economical, and a conventional system was not installed. Besides being more expensive, the lead time for the conventional system components was much longer, costing considerable production.

Escravos 3B Platform, Nigeria (2004) During the Escravos 3B Flares Out project in Nigeria, the Malu, Opolo, Ewan, and Isan platforms were evaluated for MPPs as opposed to a conventional separation system. Initially, Initially, based on economics, it was determined that MPPs would be installed on all the platforms. Unfortunately, Unfortunately, it was only then realized by the project that the gas lift gas volume would also be handled by the MPP. MPP. This significantly increased the gas volume to 95 percent GVF and resulted in the MPPs becoming uneconomical on all but the Opolo platform. On this platform, the capital expenditure savings alone was approximately $6 million. However, operations wanted to have similar facilities on all the platforms, and the MPP for Opolo was dropped.

Main Pass 59A, Gulf o f Mexico (2007) (2007) GOMBU’s GOMBU’s Main Pass 59A platform handled a field consisting of 18 wells, some of which produced at a higher pressure than others. The higher pressure wells prevented the lower pressure pressure wells from producing producing through the tieback tieback pipeline. When they were able to produce, the low pressure wells produced oil, water, and gas (95 percent GVF). After researching several options, including larger diameter lines, other piping configurations, and the cost of a conventional system, the largest Leistritz MPP manufactured was purchased for $3 million (installed for $5 million). It is driven by a 1,700 HP natural gas engine to take advantage of the low cost gas available on the platform. (Refer to Figu Figure re 600-5 600-57 7 and Fig and Figure ure 600 600-58 -58.) .) The MPP was chosen over a conventional separation system based on capital expenditure cost savings and a smaller footprint. Production has increased by 1,000 bpd so far (in 2007) and is expected to increase further as more of the low pressure wells are brought online. online. Based on only the increased production production seen thus far, the simple simple payout is 0.17 year with oil valued at $80/bbl. $80/bbl. Refer to Comparison #2 in Sectio Sec tion n 612 6126 6 for additional information.

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Fig. 600 600-5 -577 Main Main Pass 59A 59A Leistritz Leistritz MPP on Test Test (Courtesy (Courtesy of Leist ritz Corporation)

Fig. 600 600-5 -588 Leistritz MPP MPP Installed Installed on Main Main Pass 59A 59A

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6126 6126 Cost Comparison Study f or an exceeding exceeding ly high hig h GVF GVF of 98 98 Percent— Percent— MPPs MPPs versus a Convention al Separation Separation System Comparison 1 During the late 1990s, a cost analysis (paper study) was made to determine the conditions in which MPPs should be used and in which a conventional separation separation system should be used. Conclusions from that study are: 1.

The capital capital cost of of an MPP facili facility ty is typic typically ally appro approximat ximately ely 70 percent percent that that of a conventional system. This was the same for all flowrates and pressures.

2.

An MPP facility facility weigh weighss approxim approximately ately a quarter quarter of a conve conventio ntional nal system, system, and and it occupies approximately a quarter of the space of a conventional system.

3.

A conventi conventional onal system system usually usually uses uses less energy energy,, especially especially if if the GVF GVF is exceedingly high. Under these conditions, there could be an economical payout for a conventional system.

The following operating conditions were used in this study:

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•

Three Three flow flow cases cases were were conside considered red:: 40,000 40,000 bpd, bpd, 80,00 80,000 0 bpd, bpd, and 120,0 120,000 00 bpd. bpd.

•

Three, Three, six, six, and nine wells were assumed assumed to to be involved involved in the the three three flow cases, respectively.

•

The test test sepa separat rator or and and multip multiphas hasee meteri metering ng capac capacity ity are are adequ adequate ate for for one well well at a time.

•

Gas comp composi ositio tion n of the the multip multiphas hasee mix is is (GVF) (GVF) 98 perce percent nt by volu volume me at pump pump suction conditions. This equates to a GOR of 500.

•

Three electrical electrical rates were considere considered: d: $.03/kW $.03/kW-hr -hr,, $.05/k $.05/kW W-hr, -hr, and and $.07/kW-hr.

•

All All mach machin iner ery y is elec electr tric ical ally ly driv driven en..

•

No spare spare equip equipmen mentt capaci capacity ty was was includ included, ed, excep exceptt for the the crude crude tran transfe sferr pumps pumps associated with the conventional system. Here, two pumps are included.

•

Both Both system systemss operat operatee at a suction suction pres pressur suree of 15 psig. psig. The The disch dischar arge ge press pressure ure varies, depending upon the three cases considered for differential pressure: 100 psi, 400 psi, and 800 psi.

•

Oil Oil grav gravit ity y is 30 degr degree eess API. API.

•

Gas gravity is 0.7.

•

Wellh ellhea ead d tem tempe pera ratu ture re is is 1 100 00°F °F (37. (37.8° 8°C) C)..

•

Additi Additiona onall deck deck costs costs are are based based on $5,00 $5,000/s 0/stt and 0.06 0.065 5 st/sq. st/sq.ft. ft. Note Note that that a conventional system occupies more space, and its cost on an offshore platform would be greater.

•

The gas and liquid liquid separated separated in a convent conventiona ionall system system are re-com re-combine bined d into into one one discharge pipeline.

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To simplify the analysis, a few items were not considered. They are the utility costs (air, water, etc.), lights, safety equipment, office or shop costs, and transportation. At the high GVF (98 percent), the energy costs played a significant role and were 25 to 50 percent lower for the conventional separation system, compared to the multiphase energy costs. The 25 percent figure was associated with the 100 psi differential case, while the 50 percent figure was associated with the 800 psi case. Therefore, the higher the differential pressure, the greater the difference in energy consumption for the MPP. MPP. This is due to the decreasing efficiency of the MPP with the combination of high GVFs and high differential pressures. The higher additional energy costs associated with a multiphase system can be used to pay out the more efficient conventional conventional system. This could be a factor for onshore applications in which energy costs are high, but it may not be a factor for offshore applications in which the electrical costs are low due to power generated on the platform itself.

Comparison 2 In 2006, a potential MPP application existed on the Main Pass 59A platform in the Gulf of Mexico. An analysis was performed by Greg Sinclair of GOMBU to compare the cost of the conventional system versus an MPP. MPP. The application involved taking the discharge of several wells and increasing the pressure of these wells to match the discharge pressure of other wells served by the platform. The low pressure wells needed boosting boosting so that they they could produce an economic economic flow, flow, while using the same tieback line to the coast. The analysis showed the following results: 1.

Several Several scenarios scenarios were evalua evaluated. ted. The The MPP solut solution ion was was the most econo economic mic for the Main Pass application, even when compared to numerous other alternate solutions.

2.

In spite spite of the the 95 percen percentt GVF, GVF, the MPP MPP solutio solution n had a simple simple payout payout of 0.17 year. (Note (Note that, at the time these calculations calculations were performed, all the the low pressure wells had not been been brought online online yet. Based on only those those wells already brought online, the simple payout was still found to be only 0.17 year.)

3.

In the econo economic mic analyse analysess performed performed for for platform platforms, s, MPPs have the the advantag advantagee of less weight and a smaller footprint than conventional separation systems.

Appendix Append ix I contains Greg Sinclair’s presentation at the 2007 Mechanical Equipment Round Table Table (MERT). His presentation was given after the startup of the Leistritz twin screw natural gas driven MPP. This pump is the largest twin screw MPP in the Gulf of Mexico. The second presentation is a shortened version of the first, sticking to the comparisons and the economic details. As mentioned several times in this document, each potential installation must be evaluated economically on its own merits, using assumptions and conditions related to that specific installation. The sample analysis is good only for general considerations and should not be considered for anything else.

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6130 6130 Selected Selected MPP MPP Installations (includi ng Lessons Learned) Learned) 6131 6131 General General As mentioned in Section 2, almost all of Chevron and legacy-Texaco legacy-Texaco MPP experience has been with twin screw pumps. Chevron has experience with one helico-axial pump that was part of a 1 month Indonesian trial in Duri (refer to Sectio Sec tion n 613 6138 8). Since 1990 and as of the printing of this manual, Chevron and legacy-Texaco legacy-Texaco have installed at least 94 MPPs. A list of these installations is included in Fig Figure ure 600 600-1 -1.. The installations presented in this section were carefully monitored by specialists to learn as much as possible about MPPs. Though many of these installations have been referred to throughout throughout this manual, this section section is specifically devoted devoted to covering these installations in detail and discussing the “Lessons Learned” from each application.

6132 6132 Humble’s Fluid Flow Test Test Facility MPP This motor driven Leistritz L4MK 82-40 MPP was tested in the legacy-Texaco Humble Flow Loop MPP test facility from 1992 through 2002 on heavy and light oil, with different water, sand, and gas volume fractions. The maximum flowrate was 120 bpd, with a designed maximum of 225 psi differential pressure. The pump performed admirably, admirably, and its success was the driver driver for other applications throughout the company.

Lessons L earned earned Twin screw MPPs were proven to be flexible in handling different ranges of oil, water, gas, and particulate.

6133 6133 Trinidad The Leistritz twin screw pump was installed in 1992 at this facility. facility. The pump was one of the first twin screw pumps installed on an offshore platform by legacyTexaco. The pump took suction from one or more wells that were essentially shutin, and the MPP brought them back into production. The MPP successfully pumped heavy crude oil, water, and gas with a substantial quantity quantity of particulate.

Lessons L earned earned MPPs can pump heavy crude oil, water, gas, and particulate at the same time. MPPs are effective in bringing shut-in wells back into production economically. economically.

6134 6134 Mitsue Field, Slave Slave Lake, Canada Canada (later (later mov ed to Princess Field in Canada) In 1992, a 700 HP, Leistritz L4H twin screw pump was tested for a joint industry project at the Texaco Texaco Humble Fluid Flow Flow facility. facility. The test was sponsored by by Chevron, legacy Texaco, and several other major oil companies. It successfully demonstrated that the MPP could pump multiphase fluids in the controlled environment of the test facility. The next phase was to determine if an MPP could successfully pump multiphase fluids in an actual oil field environment. Chevron purchased this pump in 1993 and

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installed it in the Mitsue oil field (Slave Lake, Alberta, Canada). This MPP was installed at a pipeline junction for the purpose of increasing production from several wells by lowering wellhead backpressure. Fig Figure ure 600 600-59 -59 shows a simplified flow diagram of this arrangement. Fig. 600600-59 59 Mitsue MPP MPP Field Field Trial Trial 10,000 FEET TO BATTERY

FROM SATELLITE

6 WELLS 600,000 SCFD 400 BPD

100 FEET FR

FROM SATELLITE

T E S T S E P A R A T O R

2 WELLS 80,000 SCFD 130 BPD

LC

FR MULTIPHASE PUMP CHEVRON MULTIPHASE METER LOOP (CMML)

RECYCLE

FIC

At Mitsue, flow from several wells fed the pump simultaneously. simultaneously. One was free flowing, one used an ESP, ESP, and the remainder used rod pumps. As shown in the figure, most of the production came from wells approximately 2 miles upstream of the MPP. The suction piping ran through several hills and valleys that caused severe slugging as described in Lessons Learned example D. Note from the figure that the MPP discharged into a dedicated vessel in which the gas and liquid phases were separated and measured. Liquid was recycled from this vessel to supply screw sealant for the pump. The 800 psi pressure boost capability of this pump was not required for this oil field. However, because one of the goals was to push the pump to its design limits, the pump discharge was throttled to achieve this differential pressure. The process conditions for the Mitsue field trial are summarized as follows: • • • • • • • •

600-118

At 1,80 1,800 0 rpm, rpm, flow flow was was 25,0 25,000 00 bpd bpd (485 (485,00 ,000 0 scfd, scfd, 845 845 bpd bpd of of liqui liquid); d); At 3,000 3,000 rpm, rpm, flow flow was was 42,00 42,000 0 bpd (845,0 (845,000 00 scfd scfd gas, gas, 1,765 1,765 bpd bpd of liqu liquid) id);; Pump Pump dif differe ferent ntia iall = 800 800 psi; si; Pump Pump disch discharg argee = 850 850 psi psi (upst (upstrea ream m of pres pressur suree letdow letdown n valve valve); ); 96 perc percen entt GVF GVF to 97 perc percen entt GVF GVF;; Wellh ellhea ead d pre press ssur uree dro drop p = 150 150 psi; psi; Incr Increa ease sed d oil oil pro produ duct ctio ion n = 100 100 bpd bpd @ 300 3000 0 rpm; rpm; Crude Crude oil oil gravit gravity y = 40 degree degreess API API to 43 degrees degrees API. API.

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The duration of the field trial was to be 6 months, but it ran for 10 months. The pump was then shut down for inspection. inspection.

Goals and Results A summary of goals and results follows, and additional details are provided in the “Lessons Learned” section. Goal 1. The primary goal was to demonstrate the technology in an actual oil field, its robust design, and its reliability. Results. Many unanticipated challenges were corrected to allow the pump to operate reliably, reliably, with no mechanical failures for the pump’s pump’s entire run. After 10 months, the pump was shut shut down and inspected. inspected. The pump showed almost almost no wear, and it was estimated that the pump could have operated reliably for at least another year. Goal 2. Another goal was to develop pump selection techniques. Results. The Chevron MPP sizing method was greatly improved due to experiences with this application.

pump’s economics. Goal 3. The final goal was to confirm the pump’s Results. Crude oil production was expected to increase by 130 bpd to 270 bpd. Even with this additional production, the financial justification for a “commercial” application was marginal. The project broke even, with the value of money near 11 percen percent. t.

While the pump was being operated, Chevron Canada Resources was unable to determine any incremental crude oil production, and the pump was shut down and moved to a more profitable location, the Princess Field.

Lessons L earned earned 1.

To accommodate the higher temperatures associated with pumping a high GVF fluid, the pump clearances should be increased to accommodate a 300°F (150°C) rise above the highest suction temperature.

During the 1992 JIP test, rotors on the MPP seized while pumping a high percent gas. Because all MPPs are more inefficient inefficient while pumping pumping high percentages of gas than pure liquid, liquid, the rotors heat up up and expand. During the Mitsue test, the screws did just that—they expanded, rubbed, and seized. Leistritz increased the clearances between the two screws and also between the screws and the the case, such that the pump could could expand without rubbing. It was designed to accommodate a 392°F (200°C) rise. Later, after being deployed at Mitsue, Mitsue, the MPP saw a 284°F (140°C) rise. rise. 2.

Require Require the pump pump manufactu manufacturer rer to to design design the the twin twin screw screw pump pump rotors rotors with adequate stiffness.

The rotor design for a twin screw pump that pumps pure liquid allows the rotors to bend and touch. The liquid acts as a cushion and lubricates each screw’s interface with the other screw and with the case.

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In an MPP with a high GVF fluid, hardly any lubrication is available to lubricate the screws. Since the screws touching each other or touching the case would result in seizure of the screws, the screws in an MPP have to be stiffer than in a liquid pump. This condition is even more critical at higher differential pressures, since a higher higher discharge pressure causes causes the screws to deflect more than a lower discharge pressure. Based on this experience, the pump should be designed such that the maximum rotor deflection is less than half the internal screw clearance. 3.

A screw screw sealant sealant should always be provided provided if the the gas content content could could rise rise above 95 percent.

A screw sealant should always be provided if slugs are anticipated, even if the average GVF is less than 95 percent. An externally supplied screw sealant is one from a wide spot in the discharge piping, a separator vessel, or from an outside source. The Mitsue pump experienced many severe liquid slugs. Between these slugs, it pumped 100 percent gas for up to 2 hours, and a screw sealant became absolutely necessary. necessary. MPP installations might average less than 95 percent gas but still require a screw sealant. If slugs are possible, the alternating liquid and pure gas streams can occur while the overall average stream remains less than 95 percent. If pure gas is fed to the pump during slugging conditions, the pump must have an externally supplied screw sealant to prevent it from vapor locking, overheating, and failing. 4.

Twin screw screw pumps, pumps, properly properly designed, designed, will will operate operate reliably reliably under under severe severe slugging conditions.

The Mitsue MPP was fed from a satellite 2 miles away. Flow from several wells entered this satellite where the streams were tested. Fluid was then sent to the MPP through a common suction line traveling through hilly terrain. Before the MPP started, liquid collected in these pockets at the bottom of each hill. After the pump started, this liquid was flushed out and then partially filled again, with the cycle repeating itself. The net result was alternating slugs of pure gas and liquid. The most severe slugs occurred during the first 6 hours after startup. This initial slugging is called “terrain slugging”. During terrain slugging, the MPP was fed pure gas for 2 hours. The pump’s pump’s discharge discharge temperature temperature rose by 284°F 284°F (140°C). Note that the pump was designed to accommodate accommodate discharge temperatures temperatures of 392°F (200°C). After feeding the pump with gas, a liquid slug hit the pump, and the sound for the motor changed dramatically (sounding like wood being cut by a table saw). At the same instant that the liquid hit the pump, the suction pressure dropped by approximately 30 psi, while the discharge pressure rose by approximately 2,000 kPa because of a downstream pressure control valve nearby. nearby. (Later, this control valve was removed, and the discharge pressure surges became less severe.) Next, the separator level rose significantly. The liquid, being cooler, caused the temperature in the reservoir to drop by as much as 212°F (100°C).

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After approximately 6 hours, the terrain slugs diminished but were replaced with hydrodynamic slugs. This type of slug occurred more often but was less severe. A hydrodynamic slug was arbitrarily defined as one that slowed the pump down by approximately approximately 20 rpm. There were 17 of these occurrences occurrences counted in 5 minutes, which equates to approximately 5,000 slugs per day. Throughout all this, the pump operated reliably. reliably. After 10 months of operation, the pump was shut down. The inspection confirmed that the pump was in good condition, and it was determined that the pump would have operated for at least another year before requiring any maintenance. The pump remained undamaged by the slugs, because as the slugs enter a twin screw pump, they are split into two equal parts. These parts enter the screws from the opposite ends at exactly the same time, cancelling out the resulting forces. 5.

Do not locate a downstream downstream restricti restriction on (control (control valve, orifice, orifice, etc.) etc.) close close to the pump and preferably avoid av oid having any, if possible.

A control valve, orifice, etc., if necessary, necessary, should be located at least 10 feet downstream of the pump discharge flange. This distance provides a cushion to dampen any surges. In the Mitsue installation, the MPP’s discharge pressure spiked at 2,000 kPa when the control valve was in place. When the control valve was removed, the pressure spikes were almost nonexistent. 6.

Locate the MPP MPP as close close as possible possible to the wells wells to reduce reduce the the severity severity of slugging.

The severe slugging experienced by the Mitsue pump could have been reduced if the pump had been located closer to the wells, instead of 2 miles away, with the suction line traveling through hilly terrain. 7.

Model the MPP MPP inlet inlet and dischar discharge ge piping piping to to identify identify potential potential sluggin slugging g conditions and to design related equipment (piping, separator, separator, etc.).

For future installations, the multiphase simulator, Pipephase, should be run on the inlet and on the discharge piping from the pump to the downstream separator. separator. If Pipephase indicates slugging, a transient simulator, such as OLGA, should be used to predict the size and frequency of the slugs. With the results from these two programs, the facilities engineer will know if slugs are likely and understand the length of time one could expect the alternating 100 percent gas and 100 percent liquid slugs. This information will also be required to size the associated system equipment (piping, separator, etc.). 8.

Size the downstr downstream eam facili facilities ties to accommodat accommodatee the MPP flowrate flowrate as if it were pure liquid.

As mentioned, the Mitsue MPP experienced severe slugging, operating for at least 2 hours on 100 percent gas and then several minutes on pure liquid. While

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feeding pure liquid, the downstream separator could not dump the liquid fast enough. As a result, the MPP shut down due to a high separator level. If a liquid slug enters an MPP, MPP, the MPP pumps the liquid at its theoretical flowrate. For the Mitsue pump, this was 40,000 bpd, or approximately 1,200 gpm for the length of time the the liquid slug was present. present. The downstream separator in combination with the discharge flow line needed to be designed to handle this amount of liquid. However, in this case the discharge piping was originally designed for only 100 gpm, relying on a small separator vessel for surge capacity. capacity. Both had to be enlarged to accommodate the 1,200 gpm rate. 9.

For electri electricc motor motor drivers, drivers, check the motor’ motor’ss available available torque torque against against the the pump’s required required torque at all speeds but especially at a t the minimum operating speed.

The motor size selected to accommodate the pump at normal conditions was not large enough to supply adequate torque at the pump’s minimum speed. The motor horsepower had to be increased substantially to handle the minimum speed condition. 10. Use HYSIM or PROII to simulate the process conditions around the MPP and to identify where flashing will occur. Flashing liquid into gas decreases the pump’s total volumetric capacity. One of the most important lessons learned from the Mitsue trial was that flow from the Mitsue field amounted to only 60% of the MPP’s theoretical capacity. capacity. The decreased capacity was due to flashing of the hot screw sealant or crude oil, recycled from the downstream separator. Mitsue crude oil (40 degrees API to 43 degrees API) is light and flashes easily. easily. The flashed gas volume is much greater than the liquid volume and occupies several times the pump capacity. Figure 600 Figure 600-60 -60 was developed from the process flow simulator, HYSIM, to demonstrate where the flashing occurred. Referring to Figu Figure re 600600-60 60,, most of the flashing occurred across the flow control valve, where the recycle stream pressure dropped from 414 414 psi to 50 psi, flashing flashing 64 bpd of liquid into 4,171 bpd of gas. This stream stream mixed with the crude oil coming coming from other wells, and because the recycle was hotter, another 31 bpd of liquid flashed into 2,958 bpd of gas. The difference, in volume of over 7,000 bpd, represents approximately 27 percent of the pump’s theoretical capacity of 26,200 bpd at 2,000 rpm. The 7,000 bpd of gas occupied pump capacity and backed out the same quantity from the field. The HYSIM simulation also showed more internal slip than originally anticipated, approximately 12 percent of the theoretical pump capacity. capacity. The same pump during the Houston JIP test showed only an 8 percent slip, but that testing was done with a heavier crude oil (26 degrees API versus the 40 degrees API to 43 degrees API crude at Mitsue). Adding all losses together (flashing, internal slip, and the liquid that is recirculated), the internal losses amount to 43 percent. Thus, while the pump pump actually pumped 26,200 26,200 bpd, it was only pumping approximately approximately 57 percent of that amount or 14,867 bpd from the Mitsue field, with the remainder being recycled within the pump.

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Fig. 600600-60 60 Hysim Results, Mitsue MPP MPP Test

As mentioned earlier, MPPs handling GVFs above 95 percent need to be designed larger to compensate for these high losses. An additional 15 to 35 percent of the field requirements requirements should be added in sizing sizing an MPP: for heavy crude, use 15 percent, and for light crude, use 35 percent. The increased pump capacity is determined determined from the recycle, slip, flashing flashing factor, fully fully described in Recycle, Slip, Flashing Factor in Fig Figure ure 638 638.. 11. Install Install a cooler to decrease decrease anticipate anticipated d flashing flashing and to increase increase the actual production flow.

One possible approach to decrease flashing if MPPs are used in light crude oil service is to install a small cooler in the recycle stream. The HYSIM process simulator indicated that this would have increased the actual pumped production from the Mitsue Mitsue field by approximately approximately 10 percent. The cooler in in this case would have been small, approximately the size of a radiator in a diesel truck. 12. If slugging slugging is anticipated anticipated,, size the driver driver HP as though the MPP MPP were pumping pure liquid.

Finally, Finally, because of the Mitsue experience, MPP sizing criteria was reviewed and changed. It is recommended that, if slugging is anticipated, add up all the fluid volumes (liquid and gas) at suction conditions, and calculate the theoretical horsepower for that entire quantity, quantity, as if it were all liquid.

6135 6135 Mitsue Pump Pump Moved to the Princess Field Field As mentioned earlier, the Mitsue pump did not pay out economically. economically. It was, therefore, moved in 1997 to the Princess Field, also in Canada. There, it pumped crude oil, water, and gas from several wells through a pipeline approximately 18 miles long to an existing existing process facility facility..

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The cost of moving the pump to the Princess Field was approximately $100,000, which was considerably less than installing a conventional separation facility (separator, (separator, liquid pump, compressor, compressor, etc.) at the Princess Field. The process conditions for the Princess Field were as follows: • • • • •

40,000 40,000 bpd bpd (crud (crudee oil, oil, 3,000 3,000 bpd, bpd, 70 70 percen percentt GVF, GVF, 70 perce percent nt water water cut) cut) at at 3,000 rpm; Pump Pump dif differe ferent ntia iall = 725 725 psi; si; Pump Pump disc disch harg arge = 850 psi; psi; Wellh ellhea ead d pres pressu sure re = 125 125 psi; psi; API grav gravit ity y of of cru crud de oil oil = 23 23.

Note that the API gravity gravity in the Princess Field was heavier heavier (23 degrees) than at Mitsue (40 degrees to 43 degrees). Therefore, the Slip, Recycle, Flashing factor at the Princess Field was only 15 percent. The Princess Field was still being developed when the MPP was installed. As new wells were brought online, the pump capacity became inadequate. To gain more pump capacity, capacity, the MPP’s speed was increased to 3,600 rpm, rpm, the highest speed within the Chevron organization. The pump has run reliably under these conditions for several years.

Lessons Learned 1.

Leistritz Leistritz or Borneman Bornemann n twin twin screw pumps can operate operate reliably reliably at 3600 3600 rpm. rpm.

A Leistritz or Bornemann pump, if properly applied and installed, using the information presented in this manual, can run reliably at 3,600 rpm. The Princess Field application proved this. 2.

Instal Installl a dual dual filte filterr or strai strainer ner on on the MPP MPP suct suction ion..

If wax is present, a filter should be used. If a more coarse material is anticipated, a strainer should be used. The filter/strainer should include a differential alarm/shutdown alarm/shutdown where the filters can be changed while the MPP runs. Design the shutdown setting such that the filter collapse pressure is greater than the shutdown setting. The crude oil at Princess Field was very waxy. Thus, the inlet filter plugged several times, automatically shutting down the MPP. A dual filter was eventually installed with the capabilities mentioned above. 3.

Directly Directly contact the mechani mechanical cal seal seal suppli supplier er and carefully carefully review review the the seal’s design.

The pump manufacturer should not be relied on completely to communicate accurate data to the seal supplier. For the Mitsue pump, it was discovered that the pump supplier had planned to install a seal with an unacceptably low pressure rating. The pump supplier determined that the “static” rating of the seal, which was above the design

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requirement, was adequate. However, the “dynamic” rating, which is the rating of the seal while rotating, was actually higher, and therefore, the seal design was not acceptable.

6136 6136 Main Main Pass 313, 313, Offshore Offshor e Platform Platform in the th e Gulf of Mexico In 1993, a second Chevron MPP was installed on the offshore platform, Main Pass 313, in the Gulf of Mexico, as shown in Fig Figure ure 600 600-61 -61.. Fig. 600600-61 61 Leistritz Pump Pump at Main Main Pass Pass 313 313

This site included an unused well test header and test separator that could be dedicated to the MPP. The field trial equipment arrangement is shown in Figuree 600Figur 600-62 62.. With this arrangement, any well or combination of wells could be directed to the MPP, discharging into the dedicated test separator. The separator measured the gas and liquid phases accurately. The discharge pressure of the pump was regulated by the back pressure controller on the gas stream on the outlet of the test separator. The field trial at Main Pass 313 required a low pressure boost of 125 psi. The size of the pump in relation to the well output dictated handling only one well at a time. Most of the wells were gas lifted.

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Fig. 600600-62 62 Main Main Pass 313 313 Flow Diagram Diagram

GAS TO LP SYSTEM PUMP BYPASS

O I L / W A T E R T O L P S Y S T E M

FR

T E S T S E P A R A T O R

LC

FROM TEST HEADER

MULTIPHASE PUMP CHEVRON MULTIPHASE METER LOOP (CMML) FR LIQUID RECYCLE

FC

This field trial used a Leistritz twin screw pump (pump capacity: 26,000 bpd at 1,800 rpm). The process conditions changed, depending upon which well was tested. One of the wells on the platform produced the following: •

500 500 bpd bpd of liqu liquid id (mos (mostl tly y oil) oil);;

•

98 perce percent nt GVF GVF amoun amountin ting g to 385, 385,000 000 scfd scfd or 25,50 25,500 0 bpd of of gas at at sucti suction on conditions of 30 psig, 100°F (37.8°C);

•

26,000 26,000 bpd bpd total total of of mixed mixed flow flow (500 (500 bpd bpd of liqu liquid id and and 25,500 25,500 bpd bpd of gas) gas)..

The well normally produced into a separator at 100 psig. By reducing the wellhead pressure to 30 psig with with the MPP, MPP, incremental oil production production was expected to increase by 200 bpd.

Goals and Results Goal 1. Demonstrate that the pump can operate reliably. Results. During its run of 10 months, the double mechanical seals failed and were replaced with single seals, flushed with liquid from the downstream separator. separator. Also, debris (weld slag) damaged the pump before a suction strainer was installed. After these changes, the pump operation was considered reliable. Goal 2. Confirm the economics. Results. By decreasing the back pressure on various wells, the crude oil production increased. Well Well A-23D increased production by 200 bpd when the backpressure decreased from 100 psi to 60 psi. The economic payout was 3 months.

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Goal 3. Validate the selection and application process. Results. The pump and driver sizing criteria were revised based on the test.


Specify that the mechanical seals sea ls meet Chevron specification PMP 4662 that modifies API 682. (Using this standard will avoid many of the problems detailed below.) below.) If possible, use the less expensive, and perhaps more reliable, single seals with an external flush.

Most of the problems encountered with the Main Pass 313 pump were related to the four pressurized dual mechanical seals. The pressurized dual seal barrier fluid must operate at a higher pressure than the seal chamber. Pressure reversal occurs if the seal chamber pressure gets higher than the barrier fluid pressure. The original Main Pass 313 seals could not tolerate any pressure reversal. When this occurred, they failed. Chevron specification PMP 4662 that modifies API 682 was not used for the seals on this MPP. MPP. API 682 requires a pressurized dual seal to be able to withstand 40 psi pressure reversal without damage. The dual seals, because of poor reliability, reliability, were replaced with single seals with a flush from the downstream separator. separator. With this change, the seals were easier to operate and proved to be reliable. 2.

Spec Specif ify y balan balance ced d mech mechani anical cal seal seals. s.

The seals at Main Pass 313 were not balanced. Hydraulic forces closing the seal faces are lower with balanced seals, generating less heat and improving reliability. reliability. API 682 and Chevron PMP 4662 call for using balanced mechanical seals. 3.

For press pressurize urized d dual mechanical mechanical seals, seals, specify specify an an external external barrier barrier fluid fluid pump, not a shaft driven unit.

On Main Pass 313, the dual seals were supplied with barrier fluid that was delivered by a shaft driven pump. Therefore, until the pump started, the barrier fluid to the dual seals was 0 psi. Note that, in a pressurized dual seal arrangement, the barrier fluid must always be greater than the pressure in the seal chamber, which is slightly above the suction pressure. A hand pump was used to raise the barrier fluid pressure to a level above the suction pressure before starting the the MPP. MPP. An accumulator, accumulator, a small vessel containing containing barrier fluid fluid in one end and process fluid at suction pressure in the other, was installed to keep the pressure above suction while the pump operated. The two fluids were separated with a rubber bladder. With With this device, suction pressure was communicated to the barrier fluid controller to keep the barrier fluid above suction pressure. Since this test, the MPP manufacturers have deployed a more reliable pressurized dual mechanical mechanical seal that eliminates the the need for a hand pump and accumulator. accumulator. Modern seals are designed with an external barrier fluid pump,

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with its discharge pressure controlled high enough such that the seal chamber pressure stays constant constant and is always higher higher than suction pressure. pressure. An external barrier fluid pump also allows the barrier fluid system to operate if the MPP is shut down, preventing corrosion. Finally, the operator can be assured that barrier fluid is circulating at the proper pressure before attempting to start the MPP. 4.

Design Design the mechanical mechanical seals for an additional additional 200 psi psi to accommod accommodate ate pressure spikes.

At Main Pass 313, high pressure rushed into the pump when the inlet valve was opened, causing a pressure surge. The pressure was communicated to the seal system via the accumulator. accumulator. The pressure differential across the twin screw pump caused it to act like a motor and turn. turn. This motion motion rotated the shaft driven barrier fluid pump, producing producing a significant pressure pressure spike. This added pressure pressure was enough to blow a gasket in the seal oil filter. It is now recommended that the seals be designed for unanticipated spikes by adding another 200 psi to their design. The pressure spikes were caused by the shaft driven barrier fluid pump, which increased pressure faster than the control system could react. An external barrier fluid pump would decrease the possibility of spikes. However, However, even with the external pump, requiring additional pressure for the seal design is recommended. 5.

For pressur pressurized ized dual dual seal seal designs, designs, make sure sure the the barrier barrier fluid fluid cannot cannot leak leak into the lubricating system. Design for 5 gpm barrier fluid rate into the seal chamber of each seal.

Lubricating oil was used for the barrier fluid, instead of the preferred mixture of water and ethylene glycol. This water and ethylene glycol mixture was preferred for the barrier fluid, because because it dissipates heat better better than the lubricating oil. As stated, this mixture was not used, because it could have leaked from the outboard mechanical seal and contaminated the lubricating system. For future designs, the pump should be designed such that leakage of barrier fluid cannot contaminate contaminate the lubrication lubrication system, allowing the the barrier fluid to be a mixture of water and ethylene glycol. The barrier fluid flowrate to each mechanical seal was originally 1 gpm per seal. During the purchase order stage, the flowrate was raised to 5 gpm to allow for better dissipation of heat. 6.

Instal Installl a strai strainer ner in in the suct suction ion line line to to the MPP MPP..

The Main Pass 313 pump ran fine until early January 1995, when it began to rub. The pump was inspected and repaired at the Leistritz facility in New Jersey, Jersey, where damage to the rotors and the pump case bore was found. The damage was caused by a small piece of weld slag (1/4 inch) entering the

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suction of the pump. The damage could have been avoided if a suction strainer had been installed. MPPs are usually installed downstream from a crude oil well. It is common for well debris (weld slag, metal parts, etc.) to be flushed into the MPP. Therefore, a dual strainer is absolutely necessary. necessary.

6137 6137 Humble, Texas, Texas, Producti on Field This motor driven, Leistritz L4NG 126-98 MPP operated from 1997 until 2004, when a well rework overpressured the pump, destroying it. This pump’s maximum rate was 13,000 bpde at 92 percent GVF, GVF, with a differential pressure of 75 psi. Though the pump increased the production of the field, its main purpose was to give legacy-Texaco legacy-Texaco some operating experience with MPPs. Before being destroyed by the well rework, the pump had been the longest continuously operating MPP in the U.S. The pump was also used as a test pump for a new grease canister seal flush system installed, which is revolutionary in its development and application. (Refer to Grease Canister Seal Flush System in Sec Sectio tion n 61 6146 46.) .) Figu Figure re 600-6 600-63 3 shows a Leistritz pump at the Humble, Texas, field being removed for maintenance. Fig. 600 600-6 -633 Humble Field, Field, Texa Texas, s, Leistritz Pump Being Removed Removed for Routine Maintenance Maintenance


Twin screw screw MPPs can have a long mean mean time time between between failur failuree (MTBF). (MTBF).

2.

Mechanical Mechanical seals seals operating operating at 6 psig suction suction pressure pressure can be flushed flushed with with grease from an intermittently feeding grease canister.

This system can be very useful if the MPP stream is continuously high in GVF or particulate or both.

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6138 6138 Duri Trial, Trial, Indonesia In 1998, a Bornemann twin screw pump and a Sulzer helico-axial pump were installed side by side in Duri, Indonesia. They operated under the same conditions, pumping crude oil from 33 wells. The purpose purpose of this trial was to determine the best best pump type (twin screw or or helico-axial) that should should be used in the future future light oil steam flood (LOSF) project, also in Indonesia. The pump is shown in Figure Figu re 600-6 600-64 4 , and its simplified flow diagram is shown in Fig Figure ure 600 600-65 -65.. Fig. 600600-64 64 Test Facility Facility at Duri, Duri, Indonesia Indonesia

Fig. 600 600-6 -655 Simplified Flow Flow Diagram Diagram of the Duri Duri Test Test Facility Facility

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Duri is a typical steam flood oil field, where steam is continuously injected to reduce the viscosity of the heavy crude oil and pressurize it into the producing wells. Each Duri producing well used a rod pump to lift the crude and send it on to a processing unit. unit. The MPPs were installed installed between between the wells and and the processing processing unit. As mentioned, both pumps were designed to meet the same conditions. They are: •

Total otal mult multiph iphase ase fluid fluid flowra flowrate te = 125, 125,000 000 bpd bpd;;

•

Compos Compositi ition on = 20 20 percen percentt water water,, 5 perce percent nt API API 22 22 gravit gravity y crude crude oil, oil, 75 75 percen percentt gas, and 90 bpd sand; (Sand concentration was 0.3 percent by volume or 0.5 percent percent by weight.) weight.)

•

Inle Inlett tem tempe pera ratu ture re = 250° 250°F F (121 (121°C °C); );

•

Inl Inlet press ressur uree = 50 psig; ig;

•

Pres Presssure ure Boo Boost st = 15 150 ps psig. ig.

Twin Screw MPP Test Test Resul ts The twin screw MPP was a Bornemann pump, model MW 9.5zk-67, coupled directly to a 500 HP electric motor with speed controlled by an adjustable frequency drive (AFD). This allowed the pump to operate from 650 rpm to 1,950 rpm, although 1,800 rpm was used throughout the trial. The pump bearings were partially submerged in four self-contained lube oil reservoirs, cooled by a water jacket. Four single mechanical seals were installed in the pump at the end of each screw. screw. The seals were flushed with 5 gpm of fresh water (API Plan 32). The water went through the mechanical seal chamber into the pump through a close clearance throat bushing. The pressure pressure drop across the bushing bushing eliminated the possibility possibility of the pumped fluid being released released to the atmosphere. atmosphere. During a seal leak, only the the water flush was released. The flush not only cooled and lubricated the seal as flush, but it also acted as screw sealant for the pump. The Bornemann pump incorporated a discharge containment chamber that separated gas and liquid, retaining the liquid and letting the gas flow on. It also included a recycle valve to send a variable amount of retained liquid back to suction. The recycle valve was closed during the trial. However, because of a groove in the valve, it still transferred 3 to 4 percent of its capacity back to suction. This, plus the external seal flush, was more than adequate to supply the screw sealant needs. After operating 24 hours, the pump was shut down and partially inspected to determine if any wear occurred in the recycle valve or if any sand had collected in the containment chamber. There was no sign of wear or sand accumulation in either. The pump ran a total of 1 month and was shut down for a thorough internal inspection. During the first 25 days, the pump was fed crude oil from the wells. On the 26th day, the crude oil feed was stopped and replaced with steam. This was done to simulate steam breakthrough, a condition expected at the LOSF. LOSF. The pump’s slip was calculated daily, and it showed no significant wear during the first 25 days of operation. However, the slip increased during the steam injection test, indicating significant wear. After 3 hours, the steam was discontinued, and

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Fig. 600600-66 66 Twin Screw Pump Slip Slip versus Time Time

crude oil was again fed to the pump. The slip stayed high but constant, indicating that no additional wear was occurring. This is shown in Figu Figure re 600-6 600-66 6. The exact reason for the different wear patterns is not known. It was theorized that wear did not occur during the first 25 days because the sand in the crude oil stayed in suspension and passed through the pump without touching the rotors or case. It did not separate out and, therefore, did not cause erosion. Crude oil also lubricated and protected the metal. On the 26 th day, day, during the steam injection test, the pump suffered significant wear. It is believed that steam condensed in the suction line and/or inside the pump. The pump then processed steam, steam, condensate, and sand. The The sand in the steam and/or condensate centrifuged out and wedged between the screws and the casing, causing significant wear. As mentioned above, the pump ran a month and was then shut down and inspected. It confirmed the slip data that showed significant wear patterns. They are summarized as follows:

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•

The scre screws ws were were worn worn an an averag averagee of 0.012 0.012 inch inch.. Note Note that that they they were were origi original nally ly carbon steel, coated with Praxair Super D-Gun 2015 at 0.003 inch thick.

•

Much Mu ch of the the coa coati ting ng on the the scre screws ws was was wor worn n off. off.

•

A groove groove occu occurred rred at each each balan balance ce hole hole in in the scre screw w OD, thro through ugh the the coati coating ng into the parent metal, extending to the outside of the non-leading edge of each screw.

•

The leadin leading g edge edge of of each each screw screw was was roun rounded ded on the the OD. OD. This This is show shown n in Figure Fig ure 600 600-67 -67..

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Fig. 600600-67 67 Twin Screw Wea Wearr Patterns Patterns

Helico-Axial MPP Test Results A Sulzer helico-axial pump was tested for a month, after the twin screw test. As mentioned earlier, this pump was tested under the same process conditions. The pump, Model MPP 7/7, was a seven stage stage machine on one shaft, driven driven by a 700 HP electric motor. motor. Its speed was controlled by an ASD between 2,200 2,200 rpm and 3,600 rpm. During the test, the motor ran most of the time at 3,450 rpm. The Sulzer helico-axial pump was more complicated than the Bornemann twin screw pump. It contained two mechanical seals, one single and the other a pressurized dual seal. The The single mechanical seal was located at the outboard end and a pressurized dual mechanical seal at the motor end. A radial bearing was located outboard of the single seal on the outboard end, while another radial bearing was positioned between the two seals in the pressurized dual seal configuration. A thrust bearing was located on the motor end, outboard of the mechanical seal and the radial bearing. Unlike the twin screw pump, on which thrust was balanced, here, thrust from slugs, etc., was not balanced, and the helico-axial pump required a thrust bearing. With severe slugging conditions, the thrust force would become too large and overload this bearing. Therefore, a buffer tank is usually required to be installed ahead of the pump to smooth out the the slugs and minimize pump thrust. Because of the flat terrain terrain at Duri, severe slugging was not anticipated, and the buffer tank was not installed. This turned out to be the correct decision, because severe slugging did not occur. The pump ran for a month and showed little or no apparent process problems or wear. On the 26 th day, day, a steam injection test was attempted. During the initial phases of the test, the pump shut itself down several times, refusing to pump high gas fractions. For example, at 94 percent gas, the pump produced only 20 psi

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differential pressure instead of the desired 150 psi. The steam test was aborted after several attempts lasting 40 minutes, and the pump wear from a possible steam breakthrough could could not be determined. The helico-axial MPP was shut down after running 1 month because of a dual mechanical seal failure. Additionally, Additionally, a malfunctioning solenoid valve in the lube/barrier oil system caused the lube oil to overheat, creating several leaks. The seal and the solenoid valve were repaired, and the pump started again approximately 1 month later. It ran another 2 months, and the seals failed again. While the pump was shut down, an internal inspection was not attempted, because the LOSF project management had already decided to use the twin screw pump. The Bornemann twin screw pump was less expensive, less complicated, more efficient, could handle slugs better, and had a wider range of flowrates and pressures. Detailed reasons are presented in Fig Figure ure 600 600-7 -7 and Fig and Figure ure 600 600-8 -8 in Fig Figure ure 621 and Figu and Figure re 600600-68 68 in the following Lessons Learned section.

Lessons Learned 1.

Twin screw screw pumps can pump pump crude crude oil contain containing ing large large quantiti quantities es of sand, sand, with little or no wear, if the crude oil is heavy or viscous enough. Sand will pass through the pump and will not cause wear or settle out.

This is probably the most important lesson learned from the Duri test. Sand at 90 bpd was pumped by the Bornemann pump without any wear, and it did not settle out inside the containment chamber. chamber. This statement is based on the findings of an inspection after 24 hours of operation, the process data obtained throughout the test, and finally, the complete inspection after a month of operation. Also, the Sulzer helico-axial pump that operates at a much higher speed did not show signs of wear while operating. However, it was never opened and inspected for sand, as was done on the Bornemann pump. 2.

Pump Pump wear from from sand sand erosio erosion n will will likel likely y occur occur during during a steam steam breakthrough or if a lighter, less viscous crude oil is fed to the pump.

Duri’s Duri’s crude oil was 22 degrees API, which is fairly heavy. It is believed that, if it were less viscous, more wear would have occurred. Water is less viscous, and the twin screw pump suffered significant wear while attempting to pump steam, steam condensate, and sand. Additionally, Additionally, a study by the University of Erlangen in Nuremburg, Germany, with sand in water, confirmed significant wear, destroying a Leistritz twin screw pump in only a few hours. To better define the viscosity in which wear would occur, a computer simulation program was run. It showed significant wear from sand in water and light crude oil. There was virtually no wear when the crude oil was heavier than an API gravity of 30 degrees. 3.

The Borneman Bornemann n twin twin screw screw pump is a better choice than the Sulzer Sulzer helicohelicoaxial pump for most surface applications.

Figure 600 Figure 600-68 -68 compares the Bornemann twin screw pump to the Sulzer helicoaxial pump.

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Fig. 600 600-6 -688 Comparison—T Comparison—Typical Twin Screw MPP MPP versus the Helico-axial Helico-axial MPP It em

Tw i n s c r ew

Hel i c o -A x i al

P urchase price

$400,000

$600,000

Ability to ha handle slugs

E xc xcellent without additional equipment.

Requires additional equipment, a buffer vessel.

Lube oil system

Self-contained, each bearing.

Requires a circulating system (pump, cooler, filter, etc.).

Mechanical seals

Fou Four single seals with API Pla Plan 32. One single and one pressurized dual seal with a seal oil circulating system.

Abil Abilit ity y to wit with hstan stand d sand sand erosi erosion on

Good Good becau ecause se the sand sand was included in a heavy (22 degrees AP I gravity gravity or lower), lower), viscous (330 cp) crude oil.

Unknown

F low range (bpd)

4,000 to 125,000 (design = 125,000)

110,000 to 140,000 (design =125,000)

Suction pressure (psig)

50 (80 initially)

50 (80 initially)

Discharge pressure (psig)

100 (175 design)

100 (175 design)

Design speed

1,920 rpm

3,450 rpm

E lectric motor size

500 HP

700 HP

E fficiency during test

45%

22%

In Fig Figure ure 600 600-68 -68,, it is obvious that the twin screw pump was the better choice for the future LOSF project in Indonesia. The twin screw pump was less expensive, less complicated, more efficient, better at handling slugs, and pumped a wider range of flowrates flowrates and pressures. It is difficult to extrapolate this conclusion to other applications, although this conclusion is probably correct for most surface facilities, such as onshore installations or offshore platforms. Helico-axial pumps are installed extensively subsea and perhaps, there, they might be a better choice. Each installation must be evaluated on its own merits. merits. 4.

If sand is anticipated, anticipated, consider consider the the followi following ng to minimize minimize wear:

– – –

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Using a removable liner; liner; Rounding the leading leading edge of each screw; Coating the liner with satellite satellite or tungsten tungsten carbide, carbide, and boride boride or nitride the screws; (Refer to Sec Sectio tion n 640 640.) .) 


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– – –

Keeping the original original design speed as low low as possible; Using an ASD to allow allow the speed to increase if wear wear is indicated; Considering additional additional screw turns or locks locks to develop the the head required.

Balance holes should not be drilled on the OD of the screws.

6139 6139 COB Facili Facili ty, El Tigre Field, Venezuela; Venezuela; Bosc an Field, Venezuela; Venezuela; Kome, Miandoum; and B elobo Fields, Chad COB Facilit y, El Tigre Field, Venezuela This field had four twin screw transfer pumps that pumped a multiphase stream of crude oil, water, and gas from El Tigre to Hamaca. The manufacturer of the pumps was Flowserve, a manufacturer not recommended by Chevron. These pumps were purchased by Chevron’s Chevron’s Venezuelan Venezuelan partner. partner. The four pumps were motor motor driven NPS 14 HP pumps, capable of pumping pumping 75,000 bpd, bpd, with 10 to 20 percent GVF at 800 psig differential pressure and 1,800 rpm, using 1,600 BHP motors. The pumps were installed in 2002 and immediately became a continuous problem. These pumps were out of service so frequently that a machinist specializing in twin screw MPPs was hired full time to keep them operational. The pump’s primary failure mode was its mechanical seal system, but rubbing of the rotor against the stator bore was also common. The suction line was a significant distance from the suction tank and had a 30 foot high loop in it immediately prior to the suction flange of the pump. As a result, gas slugging was a problem. In 2005, the pumps were replaced by five Bornemann MW 10.6zk pumps. These pumps have been operating operating since then without without problems. They are shown shown in Figure Figu re 600-6 600-69 9. Fig. 600 600-6 -699 Bornemann Bornemann Pumps at El Tigre Field, Vene Venezue zuela la ( Courtesy of Bornemann Bornemann ) Corporation

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With the installation of the Bornemann pumps, the following corrective actions were taken: •

The pumps pumps were were loca located ted much much close closerr to to the the sucti suction on tank. tank.

•

The suctio suction n line line was was kept kept in in the the horizo horizontal ntal plane, plane, with with as little little rise rise as as possib possible le anywhere along the line.

•

The Bornemann Bornemann pump pumpss had had stiff stiffer er rotor rotors, s, which which prevented prevented contact contact between between the rotor and the bore.

Boscan Field, Venezuela Chevron had similar problems with Flowserve twin screw pumps in the Boscan field, Venezuela, Venezuela, prior to this application. Here, too, the pumps were purchased by the Venezuelan partner.

Kome, Miandoum, and Belobo Fields, Chad Chad is another example where Flowserve pumps failed. The MPPs repeatedly failed vibration limits on the Flowserve test stand. The order was cancelled, and Leistritz pumps were purchased instead. Today, Today, the Leistritz pumps are operating reliably. reliably. The installations are shown in Fig Figure ure 600 600-70 -70 and Fig and Figure ure 600 600-71 -71.. Fig. 600600-70 70 Leistritz Pumps Pumps in Kome Field, Field, Chad Chad (Courtesy (Courtesy of Leist ritz Corporation)


Purchase Purchase reliable reliable MPPs—do MPPs—do not not purchase purchase pump designs designs that that are are not recommended.

As mentioned above, the pumps at the COB facility experienced continuous maintenance problems, averaging an extensive repair each week. To solve the problem, all four pumps were replaced replaced with reliable Bornemann Bornemann pumps. As mentioned earlier, the two manufacturers of twin screw pumps recommended are Bornemann and Leistritz. As of this writing, no other

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Fig. 600600-71 71 Leistritz Pumps Pumps in Miandoum Miandoum Field, Field, Chad Chad (Courtesy (Courtesy of Leistr itz Corporation)

manufacturers are recommended. Perhaps, in the future, the other manufacturers will improve their design and have a reliable pump to offer. Flowserve’s Flowserve’s original pump design allowed for contact between the two rotors and between each rotor and the case. ca se. Each shaft was allowed to deflect under the discharge pressure. This design was originally for liquid only service but, in these applications, was being supplied for multiphase service. We We have seen some of the El Tigre shafts fatigue at the root of one of the screws, where the screw joins the shaft. The fatigue crack eventually propagated to the point where the working diameter of the shaft became so reduced that the shaft failed in torque. Flowserve has also provided extensive rework of its pumps at the Chevron Boscan, Venezuela, Venezuela, location. The work was unprofessional, and the pump soon failed. (Photos are available.) Flowserve has admitted problems with its workmanship and has vowed to redesign its pump, fabrication methods, and QA/QC methods. To date, no successful applications of Flowserve MPPs are known. 2.

Keep the suction suction line as short short as possible, possible, and avoid avoid vertical vertical loops.

The pumps at the COB facility were located several hundred feet from the suction tank. The suction line looped approximately 30 feet up and down to get over an elevated walkway. The pumps were unreliable by themselves, but the poor routing of the suction suction line aggravated aggravated the situation. The new new Bornemann pumps mentioned above above were installed closer closer to the suction tank without without any vertical loops.

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61310Main 61310Main Pass 59 A In 2007, a Leistritz MPP, MPP, Model 4HK-365-175, was installed on this offshore, unmanned platform in the Gulf of Mexico. It is driven by a 1,700 HP natural gas engine, the largest of any current installations. Its speed is approximately 1,200 rpm. The installation is shown in Fig Figure ure 600 600-72 -72.. The MPP was designed to meet the following process conditions: • •

Flow Flowra rate te = 150 150,0 ,000 00 bpd bpd wit with h 95 95 per perce cent nt GVF; GVF; Pres Pressu sure re boos boostt of of 640 640 psi. si.

The pump increased production from 18 wells by decreasing wellhead pressure from 350 psig to 150 psig, while the pump took over boosting the pressure into the higher pressure discharge line. Before the pump’s installation, installation, each well had to match the wellhead pressure from adjacent wells, such that the 18 wells could flow into a common production line. After various options were considered, the MPP was shown to be the most economic solution to the situation. The unit went online in September 2007. It is the only Chevron application driven by a natural gas engine. This driver was chosen since excess gas was being produced, and the gas was then “essentially free” for the application. (Refer to Fig Figure ure 600 600-72 -72.) .) Fig. 600 600-7 -722 Leistritz MPP MPP Installed Installed on Main Main Pass Pass 59A


If properly sized, natural gas engines eng ines can be used for driving MPPs.

Though natural gas engine drivers are not constant torque machines and twin screw pumps are, these engines can effectively be used, if sized for the maximum torque requirements of the pump.

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2.

Use “free” fuel when it is available.

If “excess” or uneconomical or hard to recover natural gas is available, such gas should be considered for use as fuel for the MPP driver. driver. 3.

Make certain that the mechanical seals are rated for the shut-in pressure of the well.

In the Main Pass 59A installation, it was determined after installation of the MPP that the mechanical seals were not designed to withstand the well’s shutshutin pressure. The suction piping to the well had to be modified by installing a pressure control valve valve in the suction line line and using it and the the bypass line to allow the shut-in pressure to be handled by the pump. (See Fig Figure ure 600 600-73 -73.) .) Fig. 600 600-7 -733 Main Main Pass Pass 59A—Addition 59A—Addition of the Suction Suction Control Valve Valve

6140 6140 New New Developments Developments (as (as of 2008 2008)) 6141 6141 General General This section describes technological developments from various MPP and mechanical seal manufacturers. Some are being researched by the manufacturer and are not yet commercially available. Others can be purchased but have not yet established a track record for reliability. reliability. These new developments, before being applied, should be thoroughly investigated, and all the information that is possible should be obtained from the manufacturer and the users, including a “user” list with names, phone numbers, and Internet addresses, such that the development’s reliability can be substantiated. Finally, Finally, an ETC expert should be involved before any of these new developments are used in any application.

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6142 6142 Twin Screw Pump Developments Developments Downhole Twin Screw Pump This type of twin screw pump is designed to be installed vertically in an oil well. Thus, its diameter is small, as are its screws. The larger the diameter of the well, the more likely this pump will be able to be used. CAN K, a company in Edmonton, Alberta, Canada, manufactures such a twin screw pump. Chevron installed one in 2002 at the Rangely field, but the results were poor, partly because the well’s well’s process conditions conditions were not adequately transmitted transmitted to CAN K. CAN K has had other failures, as well, although most of the failures were because the application was poorly defined by the user. (Technology (Technology development stage TQP rating of TDS TDS 6.) 6.) CAN K has a few other downhole pumps operating elsewhere, driven by a long shaft from a driver on the surface. The reliability of the shaft driven units is unknown. (Technology (Technology development stage TQP rating of TDS 7.) Flowserve and Colfax also have plans to develop a downhole pump and are looking for a partner with whom to develop the pump. (Technology development development stage TQP rating of TDS 3.) Bornemann and Leistritz, the two major manufacturers of twin screw pumps, are not actively developing a downhole pump. As of this writing, a reliable downhole twin screw pump is not available. This concept should be avoided until its reliability has been proven by actual field applications.

Digressive Screw Pitch Bornemann recently developed a “digressive screw pitch” for its twin screw pump rotor design, and it is commercially available. A digressive screw pitch rotor is one in which the pitch decreases as the flow moves from the inlet to the outlet. Bornemann claims the new pitch improves the pump capacity, capacity, efficiency, and reliability. Since 2007, Bornemann has produced several, and it has made the digressive screw pitch standard for its MW 8.5, MW 9.5, and MW 10.5 pumps. The digressive screw pitch concept makes technological sense. Screw pitch decreases towards the discharge, where the pressure increases and the volume of gas decreases. Thus, the pump efficiency should improve. Manufacturers of helico-axial MPPs have included this concept in their designs for years. Because of this and because Bornemann has decided decided to make the digressive digressive screw pitch standard on several of its MPPs, the digressive screw pitch should be considered for future Chevron applications. (Technology (Technology development stage TQP rating of TDS 9.)

Subsea Twin Twin Screw Pumps Subsea MPPs are usually economically attractive, because they can dramatically increase production by overcoming the huge static pressure needed to move the well fluid to the ocean’s ocean’s surface. However, installing them such that they are quickly and economically retrievable and increasing their reliability such that they will not need to be retrieved for a number of years is a difficult task. A reputable packaging

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company must be used, usually one other than the MPP manufacturer. Chevron should consider installing subsea pumps if the economics show they could be attractive. The Chevron TQP should be used to determine the equipment’s suitability for the specific application. There is currently only one commercial twin screw subsea pump installation, consisting of two Bornemann pumps, installed for the British Petroleum King Field in the Gulf of Mexico. The packaging was done by Aker Kvaerner. British Petroleum claims the pumps increase production by 20 percent and overall recovery by 7 percent, extending the life of the field. The pumps are on the ocean floor under 5,500 feet of water. The pumps are driven by subsea electric motors controlled by an ASD on a host platform. They supply 6.6 kv to the subsea pumps 15 miles away. (Technology development stage TQP rating of TDS 9.) A Leistritz subsea twin screw pump is expected to be operational soon, off the coast of Brazil. That pump, SBMS-500, will pump from the ocean floor (2,100 feet below sea level) to the surface, requiring 870 psi. This pump will experience an average GVF of 87 percent but is designed for 100 percent, with an external supply of screw sealant. Slugs are expected, because the pump is located 1.5 km from the well. Lubricating oil is supplied to the pump and motor from a tank located on the host platform. This system system has been extensively tested tested for years onshore at facilities facilities in Brazil. It is unique and patented. (Technology (Technology development stage TQP rating of TDS 8.) Finally, Finally, Flowserve initiated an effort to develop a subsea twin screw pump with Shell and an independent contractor, SubSea 7. The relationship with SubSea 7 has since been discontinued, and the future of the project is currently unknown. GE-Vetco GE-Vetco Gray is developing a new subsea twin screw pump, as well. It has been designed to overcome many of the current subsea MPP problems. It has not yet been field tested. (Technology (Technology development stage TQP rating of TDS 5.)

6143 6143 Helico-Axi Helico-Axi al Pump Developments Developments High Boost and/or Hybrid Pumps Framo has developed a “high boost” pump that extends its operating parameters. Framo has also developed a “hybrid” pump that extends the operating parameters even further. The hybrid pump is a helico-axial pump followed by a section of conventional centrifugal pump impellers. impellers. This concept is similar to the Schlumberger ESP gas handler, in which the helico-axial portion homogenizes the mixture, returns some of the gas into solution, and increases the fluid pressure to reduce gas volume and bubble size before the fluid enters the conventional centrifugal stages. (Refer to High Boost and/or Hybrid Pumps in Sec Sectio tion n 61 6143 43.) .) Framo claims its hybrid pump will develop a differential pressure up to 2,900 psi with a GVF of 50 percent. (Technology (Technology development stage TQP rating of TDS 6.) Sulzer and Aker Kvaerner are also developing a “hybrid” pump, similar to the Framo pump, with the first stages being helico-axial, followed by more stages of radial flow impellers. Their plan is to develop this pump to be installed subsea at

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deeper depths than are currently available. (Technology (Technology development stage TQP rating of TDS 6.)

Wet Gas Compressor Framo has recently developed a “wet gas compressor” that can pump a 90 percent GVF at a differential pressure of 600 psi. Framo is now testing its first unit at its Norway test facilities. facilities. The compressor has not yet yet been deployed in any field application. Therefore, applying one of these in a Chevron facility is not recommended until the concept has proven its reliability. reliability. (Technology development stage TQP rating of TDS 4.) Dresser has also recently developed a wet gas compressor. compressor. However, its wet gas compressor separates the liquid and compresses only the gas.

6144 6144 PCP PCP Developments Developments Equal Wall Stator seepex recently started to sell its PCP with an “equal wall stator” that has a uniform elastomer thickness. This is different than a conventional stator, in which the stator wall has a varying thickness. seepex claims this design delivers a higher pressure boost, dissipates dissipates heat more efficiently, efficiently, and allows the pump to handle handle higher GVFs. Finally, Finally, the “equal wall stator” is shorter than a conventional stator, stator, which is an advantage, especially on an offshore platform where space is a premium.

One known installation is in the Northern UK near the Shetland Islands, for Conoco. seepex is proud of this installation and wrote a paper entitled, “The Next Generation of Progressive Cavity MPP, MPP, Use of a Novel Design Concept for Superior Performance and Wet Gas Compression”, by Kamran Mirza of seepex. This concept appears technologically solid, and Chevron should consider using the “equal wall stator” if a PCP is being considered the most attractive MPP alternative. (Technology (Technology development stage TQP rating of TDS 9.) seepex is also currently developing a wet gas compressor using the “equal wall stator” concept to handle 100 percent gas indefinitely. indefinitely. The seepex unit has not yet been deployed. (Technology (Technology development development stage TQP rating of TDS 5.)

Metal to Metal PCP Kudo has developed a PCP with a metal rotor and a metal stator. stator. Kudo has approximately 40 operating PCPs but, as yet, has not sold any for multiphase service. In 2005, Kudo Industries developed this high temperature PCP for liquid phase only and has deployed deployed all its pumps in downhole, single single well applications. applications. Kudo calls its PCP the mm-PCP or PCM Vulcan. The main advantage of this type of PCP is that it can tolerate high temperatures, up to 570°F (300°C) that occasionally exist in oil wells. Conventional elastomeric stators are limited to 300°F (150°C). Also, the mm-PCP can handle wide swings in temperature that can be created from a steam flood operation.

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The mm-PCP also has promise in pumping particulate. To To date, wear caused from pumping particulate particulate has not been quantified, quantified, although the manufacturer manufacturer claims this pump should be able to to handle up to 5 percent (by weight) weight) sand. The mm-PCP has been field tested in France and Canada. During both tests, the pump wore with time, opening opening its clearances. This This wear was seen by observing observing the reduction of its volumetric efficiency that dropped from 70 to 90 percent, to as low as 35 percent, although the time it took for this efficiency drop is not known. During another test, it ran effectively for over a year without failure—a period considered a success by the pump manufacturer. manufacturer. The mm-PCP has not yet been applied in multiphase service, and therefore, the concept should be approached with caution, and this pump should not be applied in multiphase service until the concept has proven reliability. (Technology development stage TQP rating for multiphase of TDS 1.)

6145 6145 ESP ESP Developments Developments Helico-Axi Helico-Axi al Gas Handlers As mentioned in Sec Sectio tion n 683 683,, Schlumberger owns Framo, the manufacturer of helico-axial pumps and Reda, who makes ESPs. As such, it has developed a helicoaxial gas handler to be installed ahead of the suction to its ESP. ESP. (Refer to Sectio Sec tion n 623 for a discussion on helico-axial pumps in general and Sec Sectio tion n 662 for specific information on Framo). The gas handler is 6.3 meters long. The combination of gas handler and ESP is called the Poseidon ESP. With this configuration, Schlumberger Schlumberger claims the ESP can pump a GVF up to 75 percent, because it homogenizes the the mixture, returns some of of the gas into solution, solution, and increases the fluid pressure to reduce gas volume and bubble size to the inlet of the conventional ESP. Schlumberger’s first gas handler was installed in 2003, designed to handle approximately 60 percent gas. Since 2003, users have installed 16 similar machines. Gas handlers are fairly common. However, this application of a gas handler is unique. It should be considered for use only after the subject has been thoroughly investigated, which includes contacting users to determine the pump’s pump’s reliability. reliability. (Technology development stage TQP rating of TDS 9.)

6146 6146 Mechanical Mechanical Seal Developments Developments Diamond Faced Seals Mechanical seals with diamond faces on the rotating and non-rotating surfaces have been developed by John John Crane, Flowserve, and Burgmann. Burgmann. This type of seal face material may have promise for MPPs that handle sand or other types of abrasives. The John Crane diamond face material is called ca lled JCDiamond. It uses a proprietary diamond growth process that is a crystalline pure diamond film, consisting of ultranano sized crystals on a lapped surface of the seal face. The diamond facing material is very hard and smooth, building less heat between the faces. John Crane claims that, compared to a conventional seal face material, silicon carbide, the

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JCDiamond film’s wear resistance is higher, its power consumption is lower, its need for lubrication is reduced, and its operating range (temperature and pressure) is wider. JCDiamond is now available for use, but the material has not yet been applied commercially. commercially. It does not yet have a track record for reliability. reliability. John Crane is looking for someone to test the material. The Burgmann diamond faced seals are similarly grown diamond crystals on a base material. These seals have the potential to reduce the need for the large seal flush streams required today, today, the necessity to have a constant seal flush stream, and the potential to handle flush streams containing particulate. These seals could make a significant impact on MPPs located in remote areas, pumping a stream containing particulate. Diamond seal technology is new and not yet deployed. Although the concept sounds good, a potential application should be approached with caution until it has proven reliability. (Technology development stage TQP rating of TDS 5.)

Grease Canister Seal Flush System Chevron developed a grease canister seal flush system, as yet unpatented, that ran reliably for several years in a Leistritz twin screw MPP in the Humble production field. The system used grease canister lubricators to feed a stream of grease between the inner seal and the outer lip seal. The canister held the grease and used an extremely small integral pump with which to pump the grease from the canister to the seal faces, as required. So far, the seal system has been tried on only one MPP with an operating suction pressure of 6 psig. This system also has the potential to make a significant impact on MPPs located in remote areas, pumping a stream containing particulate. This seal should be tried in a future application, in which other, more proven seals are difficult to deploy. ETC should be involved in the application. (Technology development stage TQP rating of TDS 9.) Contact Bob Heyl at ETC: [email protected]. [email protected].

6150 Definitions and and Acronyms 6151 6151 Definitions Definitions Adjustable Speed Drive (ASD), also called Variable Speed Drive (VSD) —An electrical speed controller that varies the speed of an electric motor driver, thereby controlling the flowrate of the driven pump. A Variable Variable Speed Drive (VSD) is one common subcategory type of an ASD.

used by Centrilift to coat bearings, bearings, Armor I or Armor X —A proprietary material used usually specified if pumping a high GVF fluid, sand, or particulate. classification in which a pump uses centrifugal centrifugal force Centrifugal Pump —A pump classification to increase pressure at the pump discharge. Fluid flows into the eye of an impeller

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and is thrown outward by its rotation. ESPs and helico-axial or rotodynamic pumps are types of centrifugal pumps. equipment that can perform the same function function Conventional System —Separation equipment as a multiphase pump and consists of a separator, gas compressor, liquid pump, separate sand or particulate handling system, and perhaps two discharge pipelines (one gas and one liquid). overlay, installed to withstand withstand sand or particulate particulate erosion. Chrome —A material overlay, —A proprietary material used used by seepex to coat the rotors in its pumps Duktil —A designed for high GVF applications. or combination helicoElectric Submersible Pump (ESP) —A centrifugal pump or axial/centrifugal pump usually installed in an oil well, consisting of multiple small diameter impellers on one shaft. The pump assembly can be very long, consisting of an electric motor, protector, gas separator, and the pump itself. When applied downhole in a well, the motor is submerged in liquid. Equal Wall Stator —A proprietary stator configuration configuration by seepex that has a uniform thickness around each screw cavity. cavity. This design differs from the conventional stator in which the elastomeric thickness varies.

liquid near its boiling boiling point quickly quickly changes Flashing —The process in which a liquid phase to a gas, gas, if its pressure pressure is suddenly suddenly reduced. Note that the flashed flashed gas occupies several times the original liquid volume. coating to harden the surface surface of a metal in order Gas Hardening —A metallurgical coating to withstand erosion from sand or particulate. Two types are used in multiphase pumps, nitriding, and and boride gas diffusion, diffusion, or boriding. usually installed installed between the gas separator Gas Handler —An ESP subcomponent, usually and the pump itself, to increase the pressure of the suction stream. The gas handler homogenizes the mixture and re-liquefies some of the gas, lowering the GVF to the ESP. that uses centrifugal or rotary rotary motion to Gas Separator —An ESP subcomponent that separate gas from the pumped fluid and vent it into the annulus of an oil well. —Volume of gas as a percent of the total total volume of Gas Volume Fraction (GVF) —Volume all fluids (gas and liquid) at pump suction conditions, usually expressed as a percent of total flow. Helico-axial (Rotodynamic) Pump —A pump design having numerous impellers and diffusers with characteristics similar to a centrifugal axial flow pump and which is capable of pumping multiphase fluids.

point at which the edge of the the Lock or Screw Locks —In a twin screw pump, the point screw meets the inside diameter of the case or case liner. used by Schlumberger Schlumberger to withstand withstand the Material 5530 —A proprietary hard material used erosion of sand or particulate.

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or more phases (e.g., produced well well Multiphase Fluid —A fluid composed of two or fluids containing natural gas, crude oil, water, wax, natural gas hydrates, sand, and particulate). that is capable of of pumping at least two phases, phases, Multiphase Pump (MPP) —A pump that usually a liquid and a gas, but often includes a liquid, gas, and solids. the expected production production Productivity Index (PI) —A number that describes the increase from a crude oil well if the bottom hole flowing pressure is reduced. displacement rotary pump Progressing Cavity Pump (PCP) —A positive displacement consisting of a single, serpentine screw that contacts a stationary liner, called a stator. stator. The stator is pressed into the case and usually is an elastomeric material. Fluid is pushed along the shaft by the screw as the pressure is increased from the pump suction to its its discharge. —An ESP subcomponent that separates the pumped pumped fluid from the Protector (Seal) —An coolant in the electric motor. Recycle, Slip, Flashing Factor —A factor used to to increase the calculated calculated pump size size to allow for slip and flashing inside a twin screw pump.

by Schlumberger in pumps pumps designed for Redalloy —A proprietary material used by applications that contain an appreciable amount of CO 2. in which a circular Rotary Positive Displacement Pump —A pump classification in rotating pump traps a fixed volume of fluid and then pushes it through the pump, increasing its pressure along the way. way. Twin screw and PCPs are rotary positive displacement pumps. Rotodynamic (Helico-axial) Pump —A pump design having having numerous impellers and diffusers with characteristics similar to a centrifugal axial flow pump and which is capable of pumping multiphase fluids.

—In a twin screw pump, pump, the fluid that is is used to provide provide a liquid seal seal Screw Sealant —In between the edge of the screw and and the case and between the edge edge of one screw and the root of the adjacent screw. only liquid. Single Phase Pump —A pump that pumps only displacement pump, fluid that passes passes backward across the edge Slip —In a positive displacement of the screw from a high pressure area to a lower pressure area, expressed as a percent of total flow. flow. —Alternating of large large pockets of liquids liquids and gas. Slugging (Slugs) —Alternating withstand erosion from from sand or Stellite 12 Weld Overlay —A weld overlay used to withstand particulate. installed on the seabed floor. floor. Subsea Seabed Installation —Pumps that are installed withstand erosion from sand or SUME —A proprietary coating used by Sulzer to withstand particulate. installations located on the surface, either either onshore or Surface Installation —Pump installations on an offshore platform.

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—A Chevron process used to to assess new Technology Qualification Process (TQP) —A and existing technology, technology, enabling risk based decisions to be made by rating the appropriateness of a technology for a specific set of project conditions. metallurgical coating used to withstand withstand erosion caused by Tungsten Carbide —A metallurgical sand or particulate. displacement rotary pump, consisting consisting of two Twin Screw Pump —A positive displacement noncontacting screws installed installed side by side, in a case. One screw is driven by a driver, while the second screw is driven by the first through a set of gears. The screws are held apart and timed by the set of gears. controller that varies the speed speed Variable Speed Drive (VSD) —An electrical speed controller of an electric motor driver, thereby controlling the flowrate of the driven pump. A VSD is a particular type of Adjustable Speed Drive (ASD).

6152 6152 Acronyms Drive ASD —Adjustable Speed Drive BHP —Brake Horse Power ESP —Electric Submersible Pump

Technology Company (Chevron) ETC —Energy Technology Engineering Department (Chevron) FED —Facilities Engineering Business Unit GOMBU —Gulf of Mexico Business GOR —Gas Oil Ratio

Volume Fraction GVF —Gas Volume Flood LOSF —Light Oil Steam Flood MEPS —Machinery and Electrical Power Systems (Chevron) MPP —Multiphase Pump

Between Failures MTBF —Mean Time Between Value NPV —Net Present Value OD —Outside Diameter

Instrumentation Diagram P&ID —Piping and Instrumentation Pump PCP —Progressing Cavity Pump Displacement PD —Positive Displacement Index PI —Productivity Index PSA —Preferred Supplier Agreement

Assurance/Quality Control QA/QC —Quality Assurance/Quality Temperature Detector RTD —Resistance Temperature

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Steel SS —Stainless Steel Universal SSU —Saybolt Seconds Universal —Technology Development Development Stage TDS —Technology —Technology Qualification Qualification Process TQP —Technology —Variable Frequency Drive VFD —Variable —Variable Speed Drive VSD —Variable —Water Cut WC —Water

6160 160 Refere References nces 6161 6161 Company Company Specifications Specifications 1.

PMP-DG-46 PMP-DG-4662 62 CRN, CRN, Data Data Guide Guide for for API 682, Data Sheets Sheets for John Crane Mechanical Seal Selection

2.

PMP-DG-46 PMP-DG-4662 62 FS, FS, Data Guide Guide for API 682, 682, Data Data Sheets Sheets for for Flowserv Flowservee Mechanical Seal Selection

3.

PMP-SC-466 PMP-SC-4662, 2, Shaft Shaft Sealing Sealing Systems Systems for for Centrifu Centrifugal gal and and Rotary Rotary Pumps Pumps (Chevron’s (Chevron’s exception specification for API 682)

6162 6162 American Petrol Petrol eum Instit Institute ute (API) (API) 1.

API RP 11S, 11S, Operati Operation, on, Mainten Maintenance ance and and Troubl Troubleshoo eshooting ting of Electric Electric Submersible Pump Installations

2.

API RP 11S1, 11S1, Electr Electrical ical Submer Submersibl siblee Pump Teardown eardown Report Report (ANSI/A (ANSI/API PI RP 11S1-1998)

3.

API RP RP 11S2, 11S2, Elect Electric ric Subm Submers ersibl iblee Pump Test Testing ing

4.

API RP 11S3, 11S3, Electr Electric ic Submersi Submersible ble Pump Pump Install Installation ationss (formerly (formerly API API RP 11R) 11R)

5.

API RP 11S4, 11S4, Sizing Sizing and and Selection Selection of Electr Electric ic Submersib Submersible le Pump Insta Installati llations ons

6.

API RP 11S7, 11S7, Appli Applicatio cation n and Testing esting of Electr Electric ic Submersi Submersible ble Pump Pump Seal Seal Chamber Section

7.

API RP 11S8, 11S8, Electric Electric Submersib Submersible le Pump Pump System System Vibrations ibrations

8.

API 610, 610, Centri Centrifugal fugal Pumps for Petrol Petroleum, eum, Petrochemic Petrochemical al and and Natural Natural Gas Gas Industries (ANSI/API Std 610-2004) (also ISO 13709)

9.

API 676, 676, Positiv Positivee Displacem Displacement ent Pumps—R Pumps—Rotary otary (includes (includes Errata Errata dated dated June June 1994)

10. API 682, Shaft Shaft Sealing Sealing Systems Systems for Centrifugal Centrifugal and and Rotary Pumps Pumps

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6163 6163 Nation National al Associ ation of Corr Corrosion osion Engineers (NACE) (NACE) NACE MR 01-75, Petroleum and and Natural Gas Industries—Materials Industries—Materials for Use in H2S-Containing Environments Environments in Oil and Gas Production (also number as ISO 151 15156) 56)

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PMP 600 CVX Pump Manual - Multiphase Pumps

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