book3 surface testing

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Well TestingServices


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Schlumberger 2000

Schlumberger225 Schlumberger DriveSugar Lan d, Texas 77478

All rights reser ved. No part of th is book may be re produced ,stored in a r etrieval system, or tra nscribed in a ny form orby any mean s, electron ic or mechan ical, including photo-

copying and record ing, without prior written perm issionof the pu blisher.

SMP-7086-3B

An asterisk (*) is used throughout this document to denote a mark of Schlumberger.

Barton is a registered t rade mar k of Barton In strum ent Systems, LLC.Daniel is a registered t rade mar k of Daniel Industries, Inc.


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Well Testing Services Contents iii

Contents

Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .1Surface testing equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .1

Standard set of equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .2Equipment layout . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .2Safety . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .3

Classified zone s . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .3Zone 0 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .3Zone 1 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .4Zone 2 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .4Clean zone . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .4

Safety standar ds for equipmen t layout . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .4H2S service requirements and safety . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .9

Operation guidance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .10Equipment safety . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .10

Heat radiation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .11Noise . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .12Electrical safety . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .12

Advanced Well Test Design . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .15General standards . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .15Well te st design . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .17Equipment safety barriers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .21Surface safety systems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .22

Emer gency shutd own system . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .23Surface safety valve . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .26

Flowhead . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .2921 8-in. lightweight flowhea d . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .3121 4-in. flowhea d . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .3331 8- and 31 16-in. flowhead s . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .3561 8-in. flowhea d . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .37

Data Header . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .39Sand-Handling Equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .43

Dual-pot sand filter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .43Sand separator . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .46Cyclonic desan der . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .49

Choke Man ifold . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .53Heat Exchanger . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .55

Heater types and applications . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .55Hydrat e pr evention . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .55Viscosity red uct ion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .55Emulsion breakdown . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .55

Steam-heat exchangers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .56Indirect-fired heater . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .61Plate-steam exchanger . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .65

Test Separ ator . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .69Separator vessel . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .70


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Type N te st sepa rator (48 in. 12.5 ft, 1440 psi) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .74Horizontal test separa tor ( 42 in. 10 ft, 1440 psi) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .76Type G te st sepa rator (42 in. 15 ft, 720 psi) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .79Vert ical gas sepa rat or (2200 psi) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .80

Oil an d Gas Manifolds . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .83Oil man ifold . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .83Gas manifold . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .85

Tanks . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .87Surge tan k . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .87Atmosph eric gauge tank . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .91

Tran sfer Pump . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .93Centrifugal transfer pump . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .94Screw-type tran sfer pump . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .96Gear-type transfer pum p . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .98

Oil Burners and Booms . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .101Applications . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .101Benefits and features . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .101Operation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .102EverGreen bur ner . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .102Green Dragon h igh-efficiency burn er . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .105Mud burn er . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .108Burner boom . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .110Standard burner boom . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .112Heavy-duty burner boom . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .113

iv


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Well Testing Services Introduction 1

This second se ction of the th ird book in the Schlumber ger Testing Services set describes welldesign, safety considerations an d th e feature s and selection of surface well testing equipme

When performing well tests, the following items m ust be addr essed:requirements of dynamic conditionstype and layout of surface testing equipm entequipment needed to collect samples at the surfacesafety requirements.

A reservoir test can b e performed only unde r dynamic conditions, which mea ns tha t the r evoir must be exposed to a disturbance that will cause the reservoir pressure to change. T

pressur e chan ge is recorded an d interpr eted in conjunction with the mea sured flow rates to yinforma tion about th e para met ers and geome try of the well and r eservoir.

Creation of a pressure disturbance depends on whether the reservoir is producing shut in:

If the well has bee n shut in for a long time, the b est way creat es a pressur e disturban ce iflow the reservoir; this is called d rawdown.If the well has been flowing for a long time, shutting in th e well to create a p ressure disban ce; this is called buildup. A pressur e disturba nce ca n also be crea ted in a flowing weleither increasing or decreasing the flow rate .

Surface testing equipmentThe reservoir engineering term for the time period in which the well experiences changespressure is called the pressure transient. At the surface, the fluids produced during presstransients must be handled using temporary installations of surface testing equipment becaperm anen t product ion facilities usually have not yet bee n installed. This equipmen t must saand reliably perform a wide range of functions:

quickly control pressure a nd flow rates at th e surface and sh ut in the well (app licable to bexploration well testing and developmen t testing, such as cleanup)separate the resulting effluent into three separate fluids (oil, gas and water), accuratemet er th e fluids and collect and separ ate solids as applicablecollect surface sam plesdispose of the resulting fluids in an environment ally safe mann er.

Introduction


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2

Standard set of equipmentA stand ard set of surface testing equipmen t consists of

flowheadsafety valvesand filterschoke m anifoldemergency shutdown (ESD) systemheat e xchangerseparatorgauge or surge tanktransfer pumpoil and gas m anifoldsburners and booms.

Equipment layoutThe surface equ ipment and its layout for performing well tests vary considerably depen dingthe environment, well conditions and test objectives. Considerations dictating the equipmlayout include the following:

location land or offshore operat ionwell conditions flow ra te and pressure effluent properties (oil properties and hydrate formation) sand pr oduc tion presence of corrosive f luids (H2S, CO2, acid) .


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Safety is a major factor in designing and conducting a well test. Schlumberger general safconsiderations th at per tain to the type and layout of surface testing equipme nt ar e as follow

Equipme nt layout an d spacing must be in accorda nce with classified zones.All pieces of surface testing equipme nt m ust be grounde d.The electrical connection required for certain pieces of surface testing equipment, suchtransfer pum ps or laboratory cabins, must be safe and app roved according to industry standaPiping used for high-pressure wells must be anch ored.Piping must be color coded t o identify the working pressure of the pipe. It is also helpfulabel the piping to identify the fluids passing thr ough it.

The dominant wind direction must be identified to properly orient equipment that ventsburns gas.

Classified zonesThis section describes why classified zones were established, defines classified zones an d idtifies the surface testing equipment associated with each zone.

A wellsite is classified into zones or are as based upon t he p robability tha t flammable gasevapors may be present around a specific piece of equipment. For safety purposes, both tAmerican Petroleum Institute (API) and French Association of Oil and Gas Explorers aProduce rs have defined zones.

The following classified zones ar e listed in ord er from m ost to least h azardous. Schlumbersafety procedures r ecomme nd no overlap of classified zones within a well testing layout. Zrestrictions do not dictate the placement of all well test equipment. For example, the Esystem and oil and gas manifolds, although usually placed in Zone 2, are not restricted to tspecific zone. However, the location of othe r well test equipme nt defines certa in zones. For the r informat ion on th e zone classifications, see API p ublication 64B.

Zone 0Zone 0 is defined as an a rea or e nclosed space wher e any flamm able or explosive substan ce (vapor or volatile liquid) is continuously presen t in a con cent ration within t he flamma ble limof the substan ce. Thus, the borehole an d th e well below the wellhead ar e classified as Zone

Safety

Well Testing Services Safety 3


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4

Zone 1Zone 1 is defined as a n ar ea wher e an y flamma ble or explosive substa nce ( gas, vapor or volaliquid) is processed, handled or stored, and where, during normal operations, an explosiveignitable concentration of the substance is likely to occur in sufficient quantity to produchazard.

The location of the gauge tank is classified as Zone 1 because the presence of flamable gases in th e immed iate vicinity of the gauge tank vent is norma l.Most of the e lectric-driven t ran sfer pump s are designed for use in Zone 2; however, their in Zone 2 m ay be subject to geographical restrictions or client a pproval.At t he choke m anifold, samples of well effluen t ar e ta ken, typically at t he beginning of a tBecause sampling causes some gas release to the atmosphere, the choke manifold is desnat ed as Zone 1.Because th e flowhead is used as a m eans of introducing tools into th e well during a well tthe area around the flowhead is classified as Zone 1; when tool introductions are not bemade , the are a aroun d th e flowhead is classified as Zone 2.

Zone 2

Zone 2 is defined as a n ar ea wher e an y flamma ble or explosive substa nce ( gas, vapor or volaliquid) is processed and stored under controlled conditions, but the production of an explosor ignitable concentration in sufficient quantity to constitute a hazard is likely to occur oduring abnormal conditions.

The separator is designated as Zone 2 because it releases flammable gases or vapors ounder abnormal conditions, such as a leak.Diesel-driven tran sfer pumps ar e classified as Zone 2 if they are e quipped with a utomat ic sdown devices, spark arrestors, inertia star ters or special electric starter s.The indirect-fired heater is classified as Zone 2 because it uses a naked flame to heat weffluent. The steam exchanger is also Zone 2 because its surfaces can reach higtemperatures.Piping is defined as a Zone 2 area.

Clean zoneA clean zone is an area where no flammable or explosive substances are processed, handledstored. Clean zones are also referred to as nonhazardous or safe areas. An example of a clzone is the living quarters of an offshore drilling rig.

Safety standards for equipment layoutThe onshore and offshore safety standard s illustrat ed in Figs. 1 and 2, respectively, can be smarized as follows:

The area aroun d th e flowhead is classified as Zone 2 with a radius onsh ore of 45 ft [15 m] a ra dius offshore of 30 ft [10 m].If a separator vessel becomes overpressured, the rupture disc will burst and release effluto the a tmosphere. Because of this risk, the t op area around the separa tor rupture disc pis classified as Zone 1 with a radius of 15 ft [ 5 m] and Zone 2 with a ra dius from 15 to 3[5 t o 10 m]. For both offshore and onshore layouts, the are a within 15 ft above th e roof ofgauge tank is classified as Zone 1.


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Recommended distances among equipment pieces also affect onshore and offshore surftesting layouts (Figs. 3 and 4, respectively).


Figure 1.Onshore testing layout.

Separator: 30-ft [10-m] around

Tank: 45-ft [15-m] aroundIndirect heater: 30-ft [10-m] around

Flowhead: 45-ft [15-m] around

Zone 2Zone 1


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6

Figure 2.Offshore testing layout.

Separator: 10-ft [3-m] around

Heat exchanger: 30-ft [10-m] aroundSurge tank: 45-ft [15-m] around

Flowhead: 30-ft [10-m] around

Zone 2Zone 1


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Figure 3.Onshore recommended distances (figure not to scale).

a = 90 ft [30 m]b = 90 ft [30 m]c = 75 ft [25 m]d = 90 ft [30 m]e = 90 ft [30 m]f = 75 ft [25 m]

ab

cd

e

f


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8

Figure 4.Offshore recommended distances (figure not to scale).

a = 30 ft [10 m]b = 75 ft [25 m]c = 45 ft [15 m]d = 10 ft [3 m]e = 45 ft [15 m]f = 40 ft [13 m]

a b

cd

e

f


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H2S service requirements and safetyHydrogen sulfide ( H2S) is dangerous because it has a wide explosive range and is highly toxi(Table 1). Although H2S has a distinctive offensive odor at low concen trat ions, the sen se of smecannot be relied upon to detect i ts presence because the olfactory center of the brain deadover time an d at higher conce ntr ations and can no longer detect th e odor. If inhaled in sufficquan tities, H2S paralyzes the r espiratory center in th e bra in, resulting in a loss of consciousnerespiratory failure and death (Table 2).


Table 1. H2S Properties

Properties Description

Color None

Odor Extremely offensive, often characterized as rotten eggs

Density 1.189, heavier than air (1.000)

Explosive limits 4.3% to 46%

Ignition temperature 500F [260C]

Water solubility Four volumes of gas in one volume of water at 32F [0C]

Table 2. H2S Toxicity

Concentration Toxic Effects

1 ppm [0.0001%] H2S can be smelled. Caution: If H 2S concentration exceeds 1 ppm, immediately leave the areaor use personal protective equipment (breathing apparatus).

10 ppm [0.001%] Maximum 8-hr work period allowed.

100 ppm [0.01%] Odor disappears in 3 to 15 min as sense of smell is deadened; eyes and throat burn.

200 ppm [0.02%] Odor disappears quickly; eyes and throat burn.

500 ppm [0.05%] Sense of reasoning and balance lost; respiratory problems develop within 2 to 15 min; promptresuscitation required.

700 ppm [0.07%] Loss of consciousness occurs quickly and breathing stops; death occurs unless the affectedperson is removed and immediately resuscitated.

1000 ppm [0.1%] Immediate loss of consciousnesspermanent brain damage or death results unless theaffected person is removed and immediately resuscitated.


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10

Operation guidanceWhen you are working in conditions in which H2S can be encountered, always follow theseguidelines:

Conduct a man datory prejob safety meeting for all personn el involved.Maintain constant supervision of the job and use a minimum of two experienced, H2S-certified engineers or technicians.

Always carry a ma sk.Do not a llow H2S to escape into the atmosphere in an y place where it can accumulate.Monitor th e wind direct ion constant ly.Wear breathing apparatus when sur face s ampling measuring gas gravi ty changing Dan ie l orifices changing chokes bleeding off lubricators or sand t raps walking on burner booms.

Operate instruments with compressed air or nitrogen. Do not allow H2S to be sucked intocompressors.

Equipment safetyIn ad dition to its adverse h ealth e ffects, H2S is highly corrosive to met als. Service re quirem ent svar y by system .

Gas-only system Below 65 psia [4.5 bar] , no H2S requirements Above 65 psia [4.5 bar] , H2S requirements.

Oil and gas system

Below 265 psia [18.3 bar] an d below 15-ppm concentration of H2S, no H2S requirement s Above 265 psia [18.3 bar], everywhere upstream of the tanks H2S-rated equipment is

required. H2S requirements must also be met for any equipment whereP C > 50,000(P = pressure in psia andC = concentration of H2S in ppm) .

All components upstream of the tanks should be rated for H2S service. Basic rules for H2Sservice ar e a s follows:

Equipme nt not p ositively identified as H2S service must be assumed to be not rated for H2Sservice.Welding performed outside a qualified shop on H2S equipment invalidates the H2S rating, andthe equipment must be used in non-H2S service only.Piping with threaded connections is not rated for H2S service.

Use only a surge tank offshore; never use an a tmosph eric gauge tan k offshore.


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Heat radiationProblems associated with heat radiation arise primarily during burning operations and arserious concern, particularly offshore for both personnel and equipment. The data in Tabldemonstrate how critical it is to compute radiated heat before burning and to identify approate actions for avoiding excess heat. Table 3 m ust be available onsite for the testing cre w toto estimate the radiated heat in consideration of variables such as the wind direction astrength, type of boom and burners, and quantity of hydrocarbons to be burned.

Easy solutions for m anaging excess heat are t oinject water into the flame

install additional water screens behind the burnersinstall water ramps alongside the hull where excess heat can be radiateduse longer booms (85 ft [26 m]).


Table 3. Heat Radiation

Quantity Description

330 Btu/hr/ft2 Greatest solar radiated heat at soil level

440 Btu/hr/ft2 Upper limit for harmless exposure of bare human skin

1500 Btu/hr/ft2 API RP 521 recommended upper limit for an oilfield worker wearing work clothes and intermittentlysheltered or sprayed with water

3000 Btu/hr/ft2 Upper limit for unprotected structures and equipment; personnel may escape harm by leavingquickly

4000 Btu/hr/ft2

Heats wood to 800F [427C] and ignites it1000 bbl oil per Radiates 93 MMBtu/hrday (BOPD)

1 MMscf/D Radiates 13 MMBtu/hr

1000 bbl water per Injected into the flame absorbs 6 MMBtu/hrday (BWPD)


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12

NoiseEar protection is critical for all personnel exposed to noise during well test operatioInte rna tional Stan dard s Organization (ISO) recomm enda tions for perm issible noise exposurehumans (not wearing hearing protection) are listed in Table 4.

For exam ple, a sepa rator flowing 4000 BOPD with a gas/oil ratio ( GOR) of 300 generat enoise le vel of 62 dBA. For a listen er 100 ft from t he flowline, a 10-MMscf/D flow in a 6-in. gasgene rat es a n oise level of 96 dBA an d a 35-MMscf/D flow gen era tes a noise level of 107 dBA

Electrical safetyElectrical equipment located in hazardous areas must meet protection standards definedComit Europen de Normalisation Electrotechnique (CENELEC) or International Electrotenical Commission ( IEC). In North America, equipment m ust m eet Commission for EnvironmeCooperation ( CEC) and National Electrical Code ( NEC) standar ds. The sta ndar ds define

protection m ethodstemperatu re classesclassification of ha zardous ar eas ( different designations for CENELEC and IEC and for CECanada an d NEC in the United State s)classification of gases.

Only equipme nt cer tified by an auth orized cert ification body and t hat ca rries the approprmar king may be used in h azardous area s. The most commonly used means of protection are

intrinsic safety (EEx ia or EEx ib): EN50014 and EN50020 or IEC 79-0 and 79-11explosion pr oof (EEx d) : EN50014 and E N50018 or IEC 79-0 and 79-1.

Table 4. ISO Noise Exposure Recommendations

Noise Level (dBA) Permissible Exposure

90 8 hr/D

95 4 hr/D

100 2 hr/D

105 1 hr/D

110 1 2 hr/D

115 10 min/D


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Table 5 indicates which m eth od of protect ion may generally be used in various hazardous aaccording to European standards (EN) an d IEC standards. Further consideration must be mof the temperature marking of the electrical apparatus versus the classified gas type presenexpected in the ha zardous area.


Table 5. Hazardous Area Electrical Protection

EN or IEC Zone0 1 2

EEx ia Yes Yes Yes

EEx ib No Yes Yes

EEx d No Yes Yes


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All Schlumberger t esting operations, togeth er with all Schlumbe rger-manufacture d surface ting equipmen t, obey a set of recognized stan dards ( Fig. 5) an d inter nal guidelines. The genstandards and Schlumberger specifications are described in this section. Additional regulatrequ iremen ts issued by local auth orities that re late to well testing operat ions are

Det Norske Verit as ( DNV) r ules for mob ile offshore u nits P t. 6 Drill ( N)UK Statutory Instr ume nts No. 289 and HSE Guidance NotesNorwegian Petroleum Directorate (NPD) regulations for drilling, etc., for petroleum Norwegian internal waters.

General standardsSurface testing equipment used by Schlumberger must comply with the following genestandards:

API Specificat ion 6A, Wellhea d an d Christm as Tree E quipm en t, for flowhead s, surface savalves, choke manifolds and high-pressure flowlinesAPI RP 14E, Design and Installation of Offshore Production Platform Piping Systems,American Society of Mechanical Enginerrs (ASME) B31.3, Process Piping, for low-pressflowlines downstrea m of heat e xchangersAPI Specification 12K, Indirect-Type Oil Field Heate rs, for h eater s an d steam exchangeAPI RP 14C, Analysis, Design, Installation and Testing of Basic Surface Safety Systems

Offshore Production Platforms, for surface safety systemsAPI Specification 14A, Subsu rface Safety Valve Equip me nt , an d 14D, Specification Wellhea d Sur face Safet y Valves and Under wate r Sa fety Valves for Offshore Service, for sursafety shutdown valves an d ESD systemsAPI Specification 16A, Drill Through Equipment, for API hubsASME boiler an d pr essure vessel code Section VIII for pr essure vesselsNationa l Association of Corrosion Engine ers ( NACE) MR-01-75 for all H2S service equipmen t.

Advanced WellTest Design

Well Testing Services Advanced Well Test Design 15


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16

Figure 5.Schlumberger-Riboud Product Center ISO certification.


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18

Figure 6 shows a sam ple HAZOP a nalysis chart , which logs th e various levels of alarms an d tection by operational segment or eq uipmen t. The information is derived from the general sasystem philosophy (Fig. 7) and Safety Analysis Table (S.A.T.) (Fig. 8) for each segment.

Figure 6.Sample HAZOP analysis chart.

DELAY SHUT DOWN HORN MESSAGE RECOMMENDED PRESSUREFLOWLINE ON ON SET POINT RELIEF

CONTROL CONTROL CONTROLINTERNAL PLC FLOWLINE PANEL PANEL PANEL

TIME VALVE AUDIBLE MESSAGE PLC OPERATOR14th DEC 1993 Preliminary REV 1. ALARM INTERFACE

DEVICE SD V SDV PANELIDENT. SERVICE I.D. SAC NO. ALTERN. 001 002

FLOWLINE UPSTREAM PSL-001 N/A X X PSH NOT REQ AS MWHP bottom of sightglassLSLL-111 2 SEC X X X X 0 CM Bottom of sightglassLOOP X

D- 002 PRESSURE PT-401 ( 4-20m A SI GNAL TO CPU IN CONT ROL ROO M) THI S INSTRUMENT PERFORMS THE PSHH, PSL & PS LL PRESSURE FUNCTIONS.SURGE TANK PSHH-401 1 SEC X X X X 50 PSIG

PSH-401 1 SEC X X 35 PSIGPSLL-401 1 SEC X X 0 PSIG

PSV-006 50 PSIG XLOOP X

O IL LE VEL LT-411 ( 4- 20 mA SI GNA L T O CP U I N CO NT RO L R OO M) THI S I NS TRU ME NT PE RF ORM S T HE PSH H, PSL & PS LL PRE SS URE FU NCT IO NS.LSHH-411 2 SEC X X X X Top of sightglassLSH-411 2 SEC X X 20cm < top of sightglassLSLL-411 2 SEC X X Bottom of sightglassLOOP X

ESD MANUAL ESD ESD 1 N/A X X LOCATED ON DRILL FLOORPANEL-C001 PNEUMATIC SYSTEM

ESD MANUAL ESD ESD 2 N/A X X LOCATED AT CHOKE MANIFOLDPANEL-C002 PNEUMATIC SYSTEM

REMARKSALT. PROTECTIONPROCESS COMPONENT

API 14 CSAFETY ANALYSIS

FUNCTION EVALUATION CHART. . . .


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Figure 7.Safety system design philosophy.

Customer :Rig :Well : Job No.:Updated:

FIRST STAGEWell parameters ( pressure, temperature and flow rates ) are con tinuouslymonitored by the following :-

A) COMPUTER ACQUISITION SYSTEM1) Real time digital / analog output of well parameters2) Hi/lo settings for any well parameter giving audible/visual alarm (manual reset)

B) MECHANICAL PRESSURE/TEMPERATURE RECORDERS1) Foxboro pressure/temperature recorder for wellhead2) Barton pressure/temperature recorder for separator

C) MANUAL PRESSURE/TEMPERATURE MONITORING1) Dead Weight Tester, manual or electronic for pressure at wellhead.2) Dial pressure gauges/pencil thermometers throughout the well test equipment.

DURING WELL TEST OPERATIONS, THE WELL PARAMETERS ARE CONTINUOUSLY MONITOREDWITH CROSS CHECKS BETWEEN A, B AND C TO ENSURE ACCURACY.

SECOND STAGEEmergency shut down system

A) OVERALL SYSTEM CONTROLLING FLOWHEAD ISOLATION VALVE (SDV1)AND FLOWLINE ISOLATION VALVE (SDV2)THIS SYSTEM IS ACTIVATED BY : -1) Electrical ESD system.2) Manual pull buttons.3) Pneumatic hi pilots.4) Pneumatic ESD erosion probe.

THIRD STAGEPressure safety valves (PSV) venting to safe areas from the following points:

1) PSV3 located on flowline to burners to allow for pressure relief.2) PSV4& PSV5 located on the separator vessel to allow for pressure relief.3) PSV1,PSE1 and PSV 2 located on heat exchanger vessels to allow for pressure relief

in case of over pressure of steam vessels.4) PSV6 located on surge tank to allow for pressure relief.

This system is designed to protect from any blockage/rupture in the well test train betweenthe rig f loor and burners

SAFETY SYSTEM PHILOSOPHY


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20

Figure 8.Safety analysis table.

S AFETY COMPONENT : Customer :

ANALYSIS Rig :

TABLE FLOWLINE SEGMENTSWell : Job N :

Updated:UNDESIRABLE EVENT CAUSE DETECTABLE CONDITION PROTECTION

AT COMPONENT PRIMARY SECONDARY

15K FLOW SEGMENTOVERPRESSURE CHOKE FAILURE HIGH PRESSURE NONE NONE

ON HEAT EXCHANGER NOTE 1 NOTE 1BLOCKED LINE

LEAK DETERIORATION LOW PRESSURE PSL-001 ESDRUPTURE AND BACKFLOW PSL-201ACCIDENT SDV-002

1.1K FLOW SEGMENTOVERPRESSURE BLOCKED LINE HIGH PRESSURE PSH-301 PSV-003, ESD

LEAK DETERIORATION LOW PRESSURE PSL-301 ESDRUPTURE AND BACKFLOWACCIDENT

NOTE 1 : PSV NOT REQUIRED ON FLOWLINE SEGMENT PROVIDING MAWP>SITP

COMPONENT : Customer :

Rig :

SEPARATOR Well : Job N :Updated:

UNDESIRABLE EVENT CAUSE DETECTABLE CONDITION PROTECTIONAT COMPONENT PRIMARY SECONDARY

OVERPRESSURE BLOCKED OUTLET HIGH PRESSURE PSH-101,PSH-301 PSV-004, PSV-005PSV-003

UNDERPRESSURE OUTFLOW EXCEEDS INFLOW LOW PRESSURE PSL-101 ESD

OVERFLOW INFLOW EXCEEDS OUTFLOW HIGH LIQUID LEVEL LSH-111 ESDLEVEL CONTROL FAILURE NOTE 1

GAS BLOW-BY LEVEL CONTROL FAILURE LOW LIQUID LEVEL LSL-111 ESDNOTE 2

LEAK DETERIORATION LOW PRESSURE PSL-101 ESDAND BACK FLOW

NOTE 1 : EQUIPMENT DOWNSTREAM CAN SAFELY HANDLE MAXIMUM LIQUID CARRY-OVER. SEPARATOR CONTINUOUSLY MANNEDDURING OPERATIONS

NOTE 2 : EQUIPMENT DOWNSTREAM CAN SAFELY HANDLE MAXIMUM GAS RATES THAT CAN BE DISCHARGED THROUGH LIQUID OUTLET

SEPARATOR CONTINUOUSLY MANNED DURING OPERATIONS

S AFETYANALYSISTABLE


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Equipment safety barriersSafety barriers and ESD systems must comply at a minimum with the Schlumberger interpressur e policy, as sum mar ized in Table 6.


Table 6. Minimum Safety Valve Configuration

Flow Rate or Shut-In Wellhead Oil Gas H2SPressure (psi) Oil Gas

High flow rate (gas: 30 MMscf/D, S2 + ESD S3 + ESD S3 + ESD S3 + ESDliquid: 8000 B/D) SS1 SS1 SS1 SS1

D1 D2 D2 D2

15,000 Production string mandatoryS3 + ESD S3 + ESD S3 + ESD S3 + ESDSCSSV SCSSV SCSSV SCSSVD0 D0 D0 D0

S2 = master valve + flowline valve; S3 = master valve + flowline valve + SSV (surface safety valve); SS 0 = subsurface valve, not mandatory; SS 1 = E-Z Valve orE-Z Tree* or SCSSV (surface controlled subsurface safety valve; D 1 = drillstem test (DST) valve; D2 = DST valve + DST safety valve; D0 = downhole valve, notmandatory with production string.


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Surface safety systemsA typical layout, shown in Fig. 9, for offshore surface well test e quipmen t includes items suca safety valve an d em ergency shutd own, which form the safety system.

Figure 9.Surface safety equipment overview.

1

23

4

6

58

9

10

11

12

13

14

7

1-Flowhead2-Safety valve3-Emergency shutdown4-Sand filter unit5-Choke manifold6-Steam exchanger7-Steam generator

8-Separator 9-Surge tank10-Transfer pump11-Oil manifold12-Gas manifold13-Burner boom14-EverGreen burner


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Emergency shutdown systemAn ESD system is recommended for all well testing operations to provide quick shutdownresponse to a pipe leak or break, equipment malfunction, fire or similar emergency (Fig. 1A remote station or ESD console (Fig. 11) is used to safely close flowline valves. A minimumtwo remote control stations is recommended at these locations:

at the separator

in an area away from all pressurized equipment, on an escape route.ESD system comp onent s cannot be share d with process control funct ions.


Figure 10.ESD console.


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24

In well testing operat ions, the ESD system controls th e h ydrau lically operat ed flowline von th e flowhead. If required by the sur face testing setup, it can a lso contr ol an additional savalve, which can be located upstream of the choke. Pressure is applied to open valves areleased to close valves.

An ESD is push-button activated from stations located at the separator, heater or steaexchanger, and tank. Another station is usually positioned at an escape route. Backing up ESD stations are high- and low-pressur e pilots on the flowline upstr eam of the choke ma nifupstream of the h eater or steam exchanger and upstream of the separator (Fig. 12). The hpressure pilot initiates well closure when the pressure in the flowline rises above a high-lethr eshold (line plugged), and th e low-pressur e pilot initiates well closure when t he pr essure below a low-level threshold ( flowline ru ptur e or leak) .

Figure 11.ESD system layout.

Actuatorcontrolline

Flowhead

ESDcontrolconsole

Pilot 010,000 psi

Floor chokemanifold

Surge tank

ESDstation

ESDstation

Separator

Airsupply

Steam exchanger

ESDstation

Surface safety valve

Erosion probe

Pilot02500 psi


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The ESD system for well tests remotely closes a flowhead hydraulic actuator and surfasafety valve (SSV) equipped with hydraulic actuator simultaneously. Alternatively, it closesingle-action fail-safe hydraulic actuat or, provided t hat the hydraulic operating p ressure is than 6000 psi [416 bar].

The ESD-C system con sists of ESD control console with air-driven hydraulic pump, hydraulic tank, storage reels with hoses, and hydraulic hoses for actu ators

ESD stationsHigh- and low-pressur e pilots ( 010,000 and 0 2,500 psi [0690 an d 0172 bar ], re spectiv


Figure 12.ESD schematic.

Air regulator

Pressure gauge Check valve

Valve

Air circuit

Hydraulic circuit

High pilot Low pilot

ESD stations

Flowline

030 psi

0150 psi

06000 psi

Airsupply

0150 psi

0150 psi

030 psi

Hydraulic pump

Manual pump

Hydraulic tank V4 interfacevalve

To hydraulicsafety valves

V7 bypassvalve

V9 velocitycheck valve

Quickexhaust valve

Air vessel

V5 resetvalve

PI

PI

PI

PIPI

PI

PI

Erosion

probe


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Table 7. SSV Specifications

SSV-F SSV-G SSV-HD

Service H2S (fluid class DD) H2S (fluid class DD) H2S (fluid class DD)

Working pressure (psi [bar]) 5000 [345] 10,000 [690] 15,000 [1035]

Temperature (F [C]) 4 to 250, 350 for 12 hr [20 to 120, 175 for 12 hr]

ID (in. [mm]) 3.0 [76] 3.0 [76] 3.0 [76]

Inlet 3-in. Fig. 1002 F 3-in. Fig. 1502 F 3-in. API 6BX flange

Outlet 3-in. Fig. 1002 M 3-in. Fig. 1502 M 3-in. API 6BX flange

Length (ft [m]) 3.7 [1.15] 4.3 [1.30] 4.3 [1.30]

Height (ft [m]) 3.9 [1.18] 3.9 [1.18] 4.1 [1.24]

Width (ft [m]) 2.0 [0.60] 2.0 [0.60] 2.0 [0.60]

Weight (lbm [kg]) 1100 [500] 1188 [540] 1450 [660]


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The flowhead is located directly on top of the well and is the first piece of equipment tha t ffrom the well flows through (Fig. 14). Its five principal functions in controlling fluid flow inout of the well are to

support the weight of the test stringena ble up and d own (re ciprocal) movement of the te st string. If a swivel is atta ched, the tstring can also be rotat ed. Whet her a swivel is required dep ends on t he type of downh ole equipm ent u sed. Some tools can be fully operat ed using up and down movement, some req urotation, and others require both types of movement.cont rol flow out of th e well th rough a flow valve

provide a kill line conne ction so that the well can b e killed off after a t esting operation is dor dur ing an em ergency. The kill line is essen tial for contr olling pressure in th e well. Presscontrol is used to pull the downhole test string out of the well after test ing is complete ancritical for safety. For example, if the d ownhole pressur e is too h igh, th e tool string couldpushe d up t hrough t he r ig floor.introduce tools into t he well thr ough the swab valve.

Well Testing Services Flowhead 29

Flowhead


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30

Figure 14.Flowhead.


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32

Table 8. Lightweight Flowhead Specifications

FHL-F

Service H2S

Working pressure (psi [bar]) 5000 [345]

Temperature (F [C]) 4 to 300 [20 to 150]

ID (in. [mm]) 21 8 [54]

Max tensile load

(lbf at 0 psi [kN at 0 bar]) 400,000 [1780]


Connection 41 2-in. 4 S.A.

Bottom 31 2-in. IF

Flowline 2-in. Fig. 1502 M

Kill line 2-in. Fig. 1502 F

Swab valve ID (kelly cock) (in. [mm]) 21 8 [54]

Master valve ID (kelly cock) (in. [mm]) 21 8 [54]

Height (ft [m]) 9.8 [3.00]

Width (ft [m]) 2.6 [0.80]

Length (ft [m]) 0.5 [0.14]

Weight (lbm [kg]) 1320 [600]


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21 4-in. flowheadThe well test 21 4-in. flowhead (Fig. 16 and Table 9) consists of

29 16-in. swab manual gate valve21 4-in. flow sub a ssem bly with b uilt-in rem otely opera ted fail-safe valve21 4-in. flowhea d swivelindependent 29 16-in. ma ster valve.


Figure 16. 21 4-in. flowhead.

Kill line Flowline

Fail-safesleeve-type valve

Swab valve

Master valve

Swivel

Lifting sub


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34

Table 9. 21 4-in. Flowhead Specifications

FHT-M

Service H 2S (fluid class DD)

Working pressure (psi [bar]) 10,000 [690]


ID (in. [mm]) 21 4 [57]

Max tensile load



Connection 41 2-in. 4 S.A.

Bottom 31 2-in. IF

Flowline 2-in. Fig. 1502 M

Kill line 2-in. Fig. 1502 F

Swab (gate) valve ID (in. [mm]) 29 16 [65]

Master (gate) valve ID (in. [mm]) 29 16 [65]

Height (ft [m]) 14.4 [4.40]

Width (ft [m]) 2.5 [0.76]

Length (ft [m]) 2.0 [0.60]

Weight (lbm [kg]) 2300 [1045]


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31 8- and 31 16-in. flowheadsThe well test 31 8- and 31 16-in. flowheads (Fig. 17 and Table 10) consist of

flowhead a ssembly swab manual gate valve two wing valves, one with a hydraulic actuator ( flowline) independent master va lve flowhead swive l

transportation skid.


Figure 17. 31 8- and 31 16-in. flowheads.

Kill line

Kill line valve

Flowline

Lifting sub

Master valve

Swab valve

Actuator for flowline valve

Swivel


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36

Table 10. 31 8- and 31 16-in. Flowhead Specifications

FHT-F FHT-G FHT-HD

Service H2S (fluid class DD) H2S (fluid class DD) H2S (fluid class DD)

Working pressure (psi [bar]) 5000 [345] 10,000 [690] 15,000 [1,035]

Temperature (F [C]) 4 to 250, 320 for 12 hr [20 to 121, 160 for 12 hr]

ID (in. [mm]) 31 8 [79] 31 16 [78] 31 16 [78]

Max tensile load

(lbf at 0 psi [kN at 0 bar]) 300,000 [1330] 490,000 [2180] 660,000 [2940]

(lbf at 5000 psi [kN at 345 bar]) 200,000 [890] 300,000 [1330] 320,000 [1420]

Connection 61 2-in. 4 S.A. 61 2-in. 4 S.A. 7-in. 5 S.A.

Bottom On request On request On request

Flowline 3-in. Fig. 1002 M 3-in. Fig. 1502 M API 6BX flange

Kill line 3-in. Fig. 1002 F 3-in. Fig. 1502 F API 6BX flange

Swab (gate) valve ID (in. [mm]) 31 8 [79] 31 16 [78] 31 16 [78]

Master (gate) valve ID (in. [mm]) 31 8 [79] 31 16 [78] 31 16 [78]

Height (ft [m]) 12.0 [3.65] 12.5 [3.80] 13.3 [4.06]

Width (ft [m]) 3.6 [1.10] 3.6 [1.10] 4.1 [1.25]

Length (ft [m]) 3.8 [1.15] 3.6 [1.10] 4.1 [1.25]

Weight (lbm [kg]) 4400 [2000] 4994 [2270] 8530 [3870]

Skid dimensions (ft [m]) 12.1 4.6 1.0 15.0 3.9 6.6 15.0 6.6 3.6[3.7 1.4 0.3] [4.6 1.2 2.0] [4.6 2.0 1.1]

Skid weight (lbm [kg]) 1000 [455] 7040 [3200] 7040 [3200]


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61 8-in. flowheadThe 61 8-in. flowhead (Fig. 18 and Table 11) is designed for high flow rates. It consists of

flowhead a ssembly swab manual gate valve two wing valves, one with a hydraulic actuator ( flowline) independent master va lve flowhead swive l

transportation basket.


Figure 18. 61 8-in. flowhead.


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The data hea der is used to connect instrumen ts and sensors for the acquisition of data upstreof the choke m anifold ( Fig. 19 and Table 12). The stan dard data head er includes four to six pfor pressure and temperature manometers and transducers. Depending on the pressure, tconnections are either National Pipe Thread (NPT) or Autoclave Engineers, Division of Sntite, Inc.

The specialized FHH-E data header flowline (Fig. 20) incorporates connections for sadetection:

5 NPT ports (1 2-in. [12.7-mm] diamet er)the rmo well (1 2-in. diameter )BX151 flange for moun ting Sande c* sand-detection flow equipmen t.

Well Testing Services Data Header 39

Data Header

Figure 19. Data header.


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40

Figure 20. Data header with Sandec probe mounted in side view (top) and schematic (bottom).

Thermo well

Sandec probe

Flow


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Well Testing Services Data Header 41

Table 12. Data Header Specifications

FHH-CC FHH-CD FHH-E FHH-D

Service H2S H2S H2S H2S

Working pressure (psi [bar]) 5000 [345] 10,000 [690] 10,000 [690] 15,000 [1035]


ID (in. [mm]) 25 16 [58] 233 64 [64] 25 16 [58] 233 64 [64]

Inlet 3-in. Fig. 1002 F 3-in. Fig. 1502 F 3-in. Fig. 1502 F 3-in. Fig. 2202 F

Outlet 3-in. Fig. 1002 M 3-in. Fig. 1502 M 3-in. Fig. 1502 M 3-in. Fig. 2202 M

Length (ft [m]) 6.56 [2.00] 6.56 [2.00] 7.11 [2.80] 7.00 [2.10]

Height (ft [m]) 1.54 [0.50] 1.54 [0.50] 2.00 [0.60] 1.54 [0.50]

Diameter (in. [mm]) 3.0 [76] 3.0 [76] 3.0 [76] 3.0 [76]

Weight (lbm [kg]) 200 [90] 220 [100] 352 [160] 390 [175]


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Whenever solids are produced during a well test or cleanup operations, sand-handling equment is required. The main objective is to avoid erosion caused by high-flow velocity and presen ce of solids to downstream equipme nt. For gas wells, part icular atten tion should be pto the set-up. The type of Schlumberger purpose-built equipment used for sand handldepen ds on th e type of solids produced , such as forma tion sand or fractu ring flowback.

Dual-pot sand filterThe dual-pot sand filter (Figs. 21 and 22 and Table 13) removes sand and other solid particfrom well effluen t. It is usua lly located upstre am of the ch oke ma nifold. The dual-pot sand f

consists of two 46-L filter potsinterconnecting piping with bypass and drain.

The frame-mounted pots have a telescopic lifting support for convenient filter replacemeTypical applications are bare foot completion cleanup s and m aximum san d-free r ate t ests.

Well Testing Services Sand-Handling Equipment 43

Sand-HandlingEquipment

Figure 21. Dual-pot sand filter.


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44

OperationThe maximum sand concentration for continuous operation is about 10-lbm/min solids. Tvalue is base d on a 50% solids slurr y with a solids spe cific gravity of 2.7.

Figure 22. Three views of the dual-pot sand filter.

Front View Side View

Top View

Fluid inlet

Fluid outlet

Drain

Drain valve

Bypass valve

Fluid inlet

Filter pot


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Table 13. Dual-Pot Sand Filter Specifications

SFDP-A SFDP-B

Service H2S H2S

Working pressure (psi [bar]) 10,000 [690] 5000 [345]

Temperature (F [C]) 4 to 250 [20 to 121] 4 to 250 [20 to 121]

Flow rate

Liquid (B/D [m3 /d]) 5000 [795] 5000 [795]

Gas (MMscf/D [Mm3 /d]) 35 [991] 35 [991]

Standard screen size ( m) 200 200

Equivalent flow area (in. [mm]) 11.5 [300] 11.5 [300]

Max P (psi [bar]) 1500 [103] 1500 [103]

Fluid inlet 3-in. Fig. 1502 3-in. Fig. 1502

Fluid outlet 3-in. Fig. 1502 3-in. Fig. 1502

Drain outlet 2-in. Fig. 1502 2-in. Fig. 1502

Footprint (ft [m]) 9.2 7.2 [2.8 2.2] 9.2 7.2 [2.8 2.2]

Height (ft [m])

Transport 13.1 [4] 13.1 [4]

In use 24.2 [7.4] 24.2 [7.4]

Weight (lbm [kg]) 16,535 [7500] 16,535 [7500]

Other sizes available


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46

Sand separatorThe sand separator (Figs. 23 and 24 and Table 14) removes solids in the production streOil/gas/water separation is completed in an associated three-phase separator. The sand septor is ideally suited for well cleanup after a sand fracturing treatment, when a large volumsand can be lifted u p durin g the initial flowback ph ase.

The sand separator consists of 42-in. 10-ft [ 106-cm 3.05-m] vessel with 18-in. [53-cm] ent rysand compartmen t with weirdouble cyclone clustersand drain linetwo 3-in. pilot-operated, modulating action pressure relief safety valvesmanifoldsafety dischar ge line.

OperationSand removal through the sand line enables continuous operation.

Figure 23.Sand separator.


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Figure 24.Three views of a sand separator.

Front View

Side View

Top View

Fluid outlet

Fluid inlet

Solid outlet

Gas outlet

Fluid outlet

Fluid inlet Solid outlet

Gas outlet

Fluid inlet

Fluid outletGas outlet Solid outlet


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48

Table 14. Sand Separator Specifications

SFU-A

Service H2S

Working pressure

(psi to 100F [bar to 38C]) 1440 [100]

(psi to 212F [bar to 100C]) 1345 [93]


Fluid inlet 3-in. Fig. 602

Fluid outlet 3-in. Fig. 602

Drain outlet 3-in. Fig. 602

Pressure safety valve (PSV) outlet 3-in. Fig. 602

Footprint (ft [m]) 18.6 7.3 [5.68 2.24]

Height (ft [m]) 8.1 [2.50]

Weight (lbm [kg]) 30,860 [14,000]


53/117


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50

Figure 25.Cyclonic desander.


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Table 15. Cyclonic Desander Specifications

SFCU-A

Service H2S

Working pressure (psi [bar]) 5000 [345]


Flow rate

Liquid (B/D [m3 /d]) 4500 [715]

Gas [MMscf/D [m3 /d]) 35 [991,200]

Fluid viscosity (cp) 2 to 20

Solid contents (lbm/1000 bbl) [kg/m3])

Inlet 10 to 100 [0.03 to 0.3]

Peak 4000 [11.3]

Max particle size ( m)

In 600

Out 10 to 20


Fluid outlet 4-in. Fig. 1002

Flushing water inlet 2-in. Fig. 1502

Vent outlet 2-in. Fig. 1502

Solids and water discharge 3-in. Fig. 1502

Footprint (ft [m]) 9.5 7.3 [2.9 2.2]

Height (ft [m]) 22 [6.7]

Weight (lbm [kg])

Dry 26,400 [12,000]

Wet 29,700 [13,500]


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52

Figure 26.Three views of a cyclonic desander.

Front View Side View

Top View

Desander

Accumulator

Fluid outlet

Fluid inlet

Solid outlet

Flush line

Fluid outlet

Fluid inlet

Solid outlet


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The choke man ifold (Fig. 27 and Table 16) contr ols the fluid from th e well by reducing th e fing pressure an d achieving a constant flow rate b efore the fluid ent ers th e processing equipmon th e surface. When a well is being tested, critical flow (a t which th e downstre am pr essurappr oximat ely one-half of the u pstrea m pre ssure) must be a chieved across the choke. At critflow, changes in pressure an d flow rate mad e downstrea m from the ch oke do not affect th e dohole pressure and flow rate.

Well Testing Services Choke Manifold 53

Choke Manifold

Figure 27.Choke manifold.

Table 16. Choke Manifold Specifications

FMF-F FMF-BF FMF-G FMF-BG FMF-HD(bypass) (bypass)

Service H2S H2S H2S H2S H2S

Working pressure 5000 [345] 5000 [345] 10,000 [690] 10,000 [690] 15,000 [1035](psi [bar])

Temperature [F [C]) 4 to 250 [20 to 121] 4 to 320 [20 to 160]

ID (in. [mm]) 3.0 [51] 3.0 [51] 3.0 [51] 3.0 [51] 3.0 [51]

Inlet 3-in. 1002 F 3-in. 1002 F 3-in. 1502 F 3-in. 1502 F API 6BX

Outlet 3-in. 1002 M 3-in. 1002 M 3-in. 1502 M 3-in. 1502 M API 6BX

Footprint (ft [m]) 6.2 5.9 7.2 6.2 8.2 6.9 8.5 7.2 8.2 6.9[1.9 1.8] [2.2 1.9] [2.5 2.1] [2.6 2.2] [2.5 2.1]

Height (ft [m]) 3.2 [0.97] 3.2 [0.97] 3.3 [1.02] 3.3 [1.02] 3.3 [1.02]

Weight (lbm [kg]) 3785 [1720] 5070 [2300] 4180 [1900] 5510 [2500] 6060 [2750]


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54

The choke m anifold consists of valves and fittings arr anged t o direct th e flow through ontwo choke boxes. One box is configured as a variable choke, and the other as a fixed cho(Fig. 28). The fixed choke box is set by screwing in a calibrate d choke b ean. The bea n sizesusually in graduations of1 64 in. [0.4 mm] to produce a flow rate th at can be specified at the endof a test. The fixed choke can be ch anged dur ing operation when th e flow is directed th roughvariable ch oke box. The variable ch oke is a variable geometry orifice tha t is easily changed wout isolating the choke box. If the choke size and upstream pressure under critical fl

conditions are known, the flow rates during cleanup can be estimated.

OperationThe well is opene d to flow on a variable ch oke. The choke size is increased u ntil th e specifflowing wellhead pressure is attained. The choke bean size that corresponds to the barrel reing on the variable choke at the flowing wellhead pressure is then installed in the fixed chobox, and flow is diverte d th rough th e fixed ch oke at t he specified rat e.

Figure 28.Three views of the choke manifold.

Variable choke Fixed chokeFluid inlet

Fluid outlet

Fluid outlet

Side View

Top View

Front View

Fluid inlet


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Heat exchangers, commonly called heaters, raise the temperature of well effluents, which pvents hydrate formation, reduces viscosity and breaks down emulsions to facilitate tsepara tion of oil and wat er.

Heater types and applicationsHeaters a re used in almost all aspects of petroleum pr oduction and processing. They vary in and complexity from a simple hot-water bath to a sophisticated cracking furnace in a refinHeaters are gen erally classified as d irect or ind irect fired.

In a direct-fired heater, the fluid being heated flows through tubes that are surrounded b

firebox and are in direct contact with the heat source. A domestic boiler is an example odirect-fired he ater. Ther e are limitations to th e use of direct-fired he ater s in the oil industr y

In an indirect fired heater, the well fluid being heated flows through tubes that are srounde d by water in a vessel. The h eat source heat s the wat er via a firebox.

Hydrate preventionNatural gas contains water vapor. Under certain choked flow conditions, sufficient expansoccurs to lower the temperature of the flow and cause hydrate formation, which is when pacles of water an d some light h ydrocarbon s in the n atur al gas become solid. Hydrat e formatioa serious problem; if particles freeze in the surface equipment, the valves and flowmetbecome inoperative and chokes are blocked.

Natural gas hydrates resemble granular snow. These chemical compounds of hydrocarboand water form at temperatures above the normal freezing point of water when certain hydcarbons are dissolved in water under low-temperature and high-pressure conditions. Hivelocity, pressure pulsation an d agitation accelerate t he ph enome non, as do certain gases, pticularly H2S and CO2. A heater is used to help maintain the temperature above the point atwhich hydrates can form.

Viscosity reductionHigh viscosity impairs the flow of an effluent thr ough a pipe. It is usua lly not a problem in testing. However, the combined effects of chan ges in composition as th e re servoir fluid is broto th e surface am bient tem perat ure m ay raise the viscosity and affect t esting efficiency. Becaviscosity is temper atur e depen dent , a heater ca n be used t o lower the viscosity and pr event h

viscosity problems.

Emulsion breakdownWith the inevitable production of water from a reservoir, it is necessary to separate oil frwater. Under cert ain conditions, the oil and water em ulsify and d o not separa te un less chemiare injected or the effluent tempe rature is raised with a heater.

Well Testing Services Heat Exchanger 55

Heat Exchanger


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56

Steam-heat exchangersSteam-heat exchangers h ave almost completely replaced indirect-fired he ater s for offshore wand are also used where regulations do not permit the use of indirect-fired heaters. Figuresand 30 show typical steam -heat excha ngers. A steam-heat exchanger is virtually free of fire rIt requires an adequate supply of steam to operate. Some rigs have a sufficient steam suppbut usually a steam generator must also be used. Third-party companies provide steagenerat or service.

Figure 29.Steam-heat exchanger.


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Figure 30.Three views of a steam-heat exchanger.

Adjustablechoke

Inlet

Outlet

Steam inlet

Steam inlet Condensate outlet

Inlet

Outlet

Bypass

Side View

Top View

Front View

Bypass


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58

The steam-heat exchanger design most commonly used for testing has a capacity 4.3 MMBtu/hr (Table 17). As shown in Fig. 31, it h as a shell and also a tub e, which is a hipressure vessel. Steam provided to the shell is passed around the tube bundle. Heat is traferred from the steam to th e tube bundle and, in turn, to the effluent. A choke between the iand outlet of the steam-heat exchanger allows preheating the effluent before the pressuredropped at the ch oke. The t emper ature control of a steam -heat exchanger is shown in Fig. 32

Table 17. Steam-Heat Exchanger SpecificationsSTX-BBS STX-CCN STX-D STX-CCQ

Service H2S H2S H2S H2S

Vessel size 42 in. 15 ft [106 cm 4.57 m]

Working pressure (psi [bar]) 4900 [338] 10,000 [690] 10,000 [690] 15,000 [1035]

Temperature (F [C]) 32 to 250 4 to 250 32 to 250 4 to 320[0 to 121] [20 to 121] [0 to 121] [20 to 160]

Capacity (MMBtu/hr) 4.3 4.3 4.3 4.3

Fluid inlet 3-in. Fig. 1002 3-in. Fig. 1502 3-in. Fig. 1502 3-in. Fig. 2202

Fluid inlet 3-in. Fig. 1002 3-in. Fig. 1502 3-in. Fig. 1502 3-in. Fig. 2202

Steam inlet 3-in. Fig. 206 3-in. Fig. 206 3-in. Fig. 206 3-in. Fig. 206

Steam outlet 3-in. Fig. 206 3-in. Fig. 206 3-in. Fig. 206 3-in. Fig. 206

Footprint (ft [m]) 20 6.4 21.3 7.7 21.3 7.7 21.3 7.7[6.1 2] [6.5 2.3] [6.5 2.3] [6.5 2.3]

Height (ft [m]) 8.1 [2.5] 8.5 [2.6] 8.5 [2.6] 8.5 [2.6]

Weight (lbm [kg]) 19,800 [8980] 26,400 [11,980] 26,400 [ 11,980] 26,840 [12,170]


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Figure 31.Steam-heat exchanger schematic.

Effluentoutlet

Effluentinlet

Thermometric well

Temperature controller

Automatic control valve

Steam inlet

Steam trap

Manual valves

Choke

Steam condensate outlet

Safety relief valve


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60

Figure 32.Steam-heat exchanger temperature control.

Choke box

ControllerAutomaticcontrol valve

Temperature bulb

Pressure regulator

Steam trap

Air

Steam

Effluent

Effluent

Steam

Steam exchanger

Steam generator


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Indirect-fired heaterThe Schlumber ger indirect-fired diesel he ater (Figs. 3335 and Table 18) consists of

vessel for water bath at atmospheric pressure, including 4-in. split coil with intermedichoke, adjustable choke with 11 2-in. [3.81-cm] seat a nd solid stem tipmanifold equipped with three 31 8-in. gate valves r ated 5000-psi [ 345-bar] working pressurediesel shutdown valve actu ated b y pilot light stopp age and t empe ratu re contr oller ( Fig. 3flame arrestor on burn er air inletspark arrestor on chimney exhaust.


Table 18. Indirect-fired Heater Specifications

IHT-BAF

Service H2S (fluid class DD)

Working temperature (F [C]) 32 to 200 [0 to 93]

Working pressure (coil) (psi [bar]) 5000 [345] upstream and downstream choke

Heating capacity (MMBtu/hr) 2

Inlet 3-in. Fig. 1002 F

Outlet 3-in. Fig. 1002 M

Diesel inlet 1 4-in. NPT

Footprint (ft [m]) 19.27.4 [5.852.25]

Height (ft [m]) 13.1 [4.0]

Weight (lbm [kg]) 27,450 [12,450]


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62

Figure 33.Indirect-fired heater.

Figure 34.Indirect-fired heater schematic.

Flange

Fire tube

Vessel

Liner

Stack


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64

Figure 36.Indirect-fired heater temperature controls.

Temperature bulb Coils Choke boxSpark arrestor

Air ring

Flame arrestor

Gas pilot lightMercury bulb

Bypass

Diesel burner

Thermostatic valve

Automatic control valve

CMA control box

Chimney

Manual valve

Pressure regulator

Mercury

PropaneDiesel

Compressed air

Well fluidWater

Air

Propane

Effluent

Effluent

Diesel

Vent


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Plate-steam exchangerThe plate-steam exchanger is especially designed for h igh-efficiency heating downstr eam ofma nifold (Figs. 37 an d 38 and Table 19). It is ideally suite d for use in he avy-oil operat ions to rthe t empe ratu re of the effluent for bett er disposal to oil burner s. It can also be used for oil ditioning prior to export. The unit is skid mounted with a prote ctive frame a nd consists of

plate exchanger

crude man ifold equipped with bypass and pr essure r elief valvesteam manifold equipped with a Fisher 2-in. control relief valve for regulating the tempature of the crude th rough t he steam flow.

OperationThe plate-steam exchanger requires clean liquid.


Figure 37.Plate-steam exchanger.


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66

Figure 38.Three views of a plate-steam exchanger.

Inlet

Outlet

Steam inlet

Steam inletCondensate outlet

Inlet

Outlet

Side View

Top View

Front View

Steam outlet

Safety valve

Safety valve


71/117


Table 19. Plate-Steam Exchanger Specifications

STX-P STX-PSteam Crude

Service H2S (fluid class DD)

Working pressure (psi [bar]) 174 [12] 464 [32]

Working temperature (F [C]) 376 [191] 131 to 194 [55 to 90]Flow rate 1854 kg/hr 8000 BOPD

Inlet 4-in. 150 RF 6-in. 300 RF

Outlet 2-in. 150 RF 6-in. 300 RF

Footprint (ft [m]) 11.85.6 [3.601.72]

Height (ft [m]) 7.8 [2.40]

Weight (lbm [kg]) 8820 [4000]


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73/117

Test separ ators are versatile pieces of equipme nt used t o separate, mete r and sam ple all phaof the e ffluent. Because test separa tors are u sed on exploration wells where effluent phases not known, they must be able to treat a wide variety of effluents, such as gas, gas condenslight oil, heavy oil and foaming oil as well as oil conta ining water and impurities such as mor solid particles. Schlumberger also provides a wide range of separators for high-content 2Sservice.

Figure 39 shows the main e lement s of a test sepa rator, which are th e vessel (including innal components, pressure and level regulators, and safety devices), the piping necessary different phases and metering (fitted with corresponding metering devices), and the skid its protective frame. Separators are also equipped with a built-in shrinkage tester, Bartorecorder and sampling points.

Well Testing Services Test Separator 69

Test Separator

Figure 39.Test separator.


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70

Separator vesselThe principal intern al component s of a separ ator ar e shown in Fig. 40. The coalescing plates vent droplets larger than 15 mm from being carried into the outlet gas stream, and the mextractor, which is th e last obstacle th e gas must pass before leaving the separa tor vessel, blofine liquid droplets still in th e gas stream . The b locked droplets coalesce and fall back into oil phase .

The vessel capacity for each p hase de pen ds on the in-situ conditions of pressur e and t empature and in-situ effluent properties such as

viscosities and den sities of the liquids, which are a function of th e am ount of dissolved gavessel operating liquid levelvessel intern als

requ ired liquid gas separat or efficiency in t erm s of size of liquid droplet t o be sep arat ed frthe gas phase.

Calculations for the oil and gas capacities and int ern al pressure are m ade as follows:The se ttlin g velocityV s , drag coefficientC d and Reynolds numberRe are calculated as

( 1)

( 2)

( 3)

Figure 40.Cross-section schematic of test separator vessel.

Foam breaker

Mist extractor

Gas outlet

Oil-level controller

Access door

Vortex breaker

Weir

Water outlet

Water-level controller

Deflector plate

Safety valve Second safety valve

Coalescingplates

Effluent inlet

Oil outlet

V dm

C

C

dm V

s d

l g

g

d

s g

g

=

= + +

= ( )

0 0019

24 30 34

0 0049

1 2

.

Re Re .

Re . ,

/


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and the critical velocityV c is

( 4)

where

dm = liquid droplet diameter (m)

= in-situ density (ai r = 1) = viscosity (cp)L = effective vessel length ( ft)h = pad heigh t ( ft )

and th e subscriptsg and l denote gas and liquid, respectively.

The gas rate in ft3 /s is

( 5)

an d in MMscf/D is

( 6)

where

Ag = gas cross-sect ional area (ft )P = opera ting pressure (ps i)T = opera ting t empera ture ( R)Z = gas compressibili ty factor.

Oil capacity is calculated as

( 7)where

Q o = oil capacity (BOPD)V = oil volume (bbl)t = r e ten tion tim e ( s) .


V V L

h c s

g

= 12 ,

q A V P TZ g

g c = ( ) ( )( )520 0 086414 73 .. ,

q A V g g c =

Q

V

t o =128 ,


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72

Separat ors are h ighly versatile in th eir operat ion because t he level of the oil can be adjusacross a ran ge of 6 in. [ 15.24 cm] from th e cent er line of the vessel (Fig. 41). The pn eumliquid-level controller has a long vertical float t o accomm odate the range of oil levels. The ctroller actuates either the small- or large-diameter regulation valve fitted in parallel on theoutlet to regulate the oil rate from very low flow to the maximum capacity of the separa(Fig. 42). The valves close when air sup ply is not available, and the oil/gas interface is obserwith a sight-glass level.

Figure 41.Separator flow sheet.

P2PGV2Air

supply

PCV2

ReliefvalvePCV7

T2PGV3P3

GOV7GOV6

PCV1T1 PCV3 PCV4

1

2

2

3

3

1

4

4

5

57

6

T5

8

Liquid

levelsvalves(LLV)

Shrinkage testervalves (SLV)

31 2

Gas metering

4

5 6

T3

PGV1

P1

Gas outlet valves(GOV)4 3

12

Safety valves

Nonreturnswing valve

V35

V1

Water outlet

WOV2WOV1

V2

V4

PCV6

3

1

4

2

5T4

Oil outlet valves (OOV)Oil metering

3

1

2

Inlet lineGas lineOil lineWater line

6

7


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The water level is also regulated pn euma tically. By using an interface con troller to re guthe oil-water interface, the separator can continuously eliminate the separated water; howewate r levels exceedin g 10% of the cap acity of th e vessel cann ot be con tr olled efficient ly. The lcontroller actua tes a regulation valve on t he wat er out let. Like th e oil regulation valve, the w

valve is also closed b y a lack of air su pply.


Figure 42.Separator capacity.

0 10 20 30 40 50 60 70 805 1510 200 90

Liquid Capacity (BOPD)for 1-min Retention Time

Gas Capacity (MMscf/D)Type ofSeparator

LevelPosition

SEP-G test separator

42 in. 15 ft, 720 psi Center line

+6 in.

6 in.

SEP-N test separator

48 in. 12.5 ft, 1440 psiCenter line

+6 in.

6 in.

SEP-T test separator

42 in. 10 ft, 1440 psiCenter line

+6 in.

6 in. 2 0 0

4 0 0

6 0 0

8 0 0

1 0 0 0

1 2 0 0

1 4 4 0

2 0 0

4 0 0

6 0 0

8 0 0

1 0 0 0

1 2 0 0

1 4 4 0

2 0 0

4 0 0

6 0 0

7 2 0


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74

Type N test separator (48 in. 12.5 ft, 1440 psi)Type N separ ators ar e designed for high flow rates a nd h igh pr essure ( Fig. 43 and Table 20). Tconsist of th e following:

48-in.12.5-ft vessel with acce ss doorrem ovable cyclone inlet clusterinlet 4-in. fullbore ch eck valveintern al coating of vesselisolation valves on flow meters ( upstre am an d downstrea m)pne umat ic control valves on oil and water outlet stwo lateral sta ndpipes with oil- and water-level contr ollerstwo pilot-operated safety valves on t he vessel and one on th e oil inlet m anifold togethe r inindependent discharge lineskid mount with full drip pan, protect ive frame an d prote ctive roof panel.

Figure 43.Type N test separator.


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OperationOperational ben efits include

foam-free separa tion ( no carr yover)increased achievable flow ratesno em ulsion formationbetter coalescence from better liquid separationweight a nd volume r eductionsimple scaling up by adding cycloneswater kn ockout down to few percen t oilwater polishing down t o 20-ppm oil.


Table 20. Test Separator Specifications

SEP-NC SEP-ND

Service H2S H2S

Vessel size 48 in. 12.5 ft [122 cm3.8 m] 48 in.12.5 ft [122 cm3.8 m]

Maximum working pressure 1440 [100] 1440 [100](psi at 100F [bar at 38C])


Working pressure at max temperature 1345 [93] 1315 [90](psi [bar])

Liquid capacity (B/D [m3 /d])

LLL 8200 [1300] 8200 [1300]

HLL 16,500 [2600] 16,500 [2600]

Gas capacity (MMscf/D [m 3 /d])

LLL 90 [2,500,000] 90 [2,500,000]

HLL 75 [2,100,000] 75 [2,100,000]

Fluid inlet 3-in. Fig. 602 3-in. Fig. 602

Gas outlet 4-in. Fig. 602 4-in. Fig. 602

Oil outlet 3-in. Fig. 602 3-in. Fig. 602

Water outlet 2-in. Fig. 602 2-in. Fig. 602

Relief outlet 4-in. Fig. 602 4-in. Fig. 602

Drain outlet 2-in. Fig. 602 2-in. Fig. 602

Footprint (ft [m]) 18.67.4 [5.682.24] 18.67.4 [5.682.24]

Height (ft [m]) 7.9 [2.42] 7.9 [2.42]

Weight (lbm [kg]) 43,210 [19,600] 43,210 [19,600]

Low liquid level (LLL) and high liquid level (HLL) at 720 psi [50 bar]


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76

Horizontal test separator (42 in. 10 ft, 1440 psi)The standard three-phase horizontal test separator separates and measures the gas, oil awater p roduced by a well. This separator is compa tible with all Schlumbe rger well testing eqment and is used primarily in well testing operations and in cleaning up new completionsstimulated wells.

The horizontal test sep arat or is a self-containe d unit with a ll valves and pneu mat ic contrrequired to regulate the pressure and fluid levels (Fig. 44 and Table 21). The redundant safdesign incorporat es two p reset relief valves. The un it consists of the following:

42-in. 10-ft vessel with 18-in. access dooroil compart men t with weirisolation valves on flow meters ( upstre am an d downstrea m)flow measuring system for oil with dual flowmeterflow measur ing system for gas with 6-in. orifice m eter, orifice set a nd thr ee-pen r ecorderflow measur ing system for wat erpne umat ic control valves on oil and gas outletsman ual control valve on water outlettwo pilot-operated safety valves

safety discharge line connecte d to gas outlet or an ind epen den t gas flarelateral standpipe with oil-level controller.


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Figure 44.Three views of a standard horizontal separator.

Inlet

Water outlet

Oil outlet

Gas outlet

Oil outlet Gas outlet

Water outletFluid inlet

Side View

Front View

Top View


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78

Table 21. Horizontal Test Separator Specifications

SEP-T SEP-U SEP-W

Service H2S H2S H2S

Vessel size 42 in. 10 ft 42 in. 10 ft 42 in. 10 ft[106 cm 3.28 m] [106 cm 3.28 m] [106 cm 3.28 m]

Working pressure at max 1440 at 100F [100 at 38C] 1440 at 100F[100 at 38C] 1440 at 100F [100 at 38C] temperature (psi [bar]) 1345 at 212F [93 at 100C] 1345 at 212F [93 at 100C] 1345 at 212F [93 at 100C]

Temperature (F [C]) 32 to 212 [0 to 100] 4 to 212 [20 to 100] 32 to 300 [0 to 150]


LLL 6650 [41] 6650 [41] 6650 [41]

HLL 14,400 [90] 14,400 [90] 14,400 [90]

Gas capacity (MMscf/D [Mm 3 /d])

LLL 60 [1690] 60 [1690] 60 [1690]

HLL 25 [707] 25 [707] 25 [707]

Fluid inlet 3-in. Fig. 602 3-in. Fig. 602 3-in. Fig. 602

Gas outlet 3-in. Fig. 602 3-in. Fig. 602 3-in. Fig. 602

Oil outlet 2-in. Fig. 602 2-in. Fig. 602 2-in. Fig. 602

Water outlet 2-in. Fig. 602 2-in. Fig. 602 2-in. Fig. 602

Relief outlet 3-in. Fig. 602 3-in. Fig. 602 3-in. Fig. 602

Drain outlet 2-in. Fig. 602 2-in. Fig. 602 2-in. Fig. 602

Footprint (ft [m]) 18.6 7.4 [5.68 2.24] 18.6 7.4 [5.68 2.24] 18.6 7.4 [5.68 2.24]

Height (ft [m]) 7.9 [2.50] 7.9 [2.50] 7.9 [2.50]

Weight (lbm [kg]) 30,800 [14,000] 30,800 [14,000] 30,800 [14,000]

LLL and HLL at 720 psi [50 bar]


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Type G test separator (42 in. 15 ft, 720 psi)With its extended length vessel, the type G separator (Table 22) has a high liquid capacitymedium pressure.


Table 22. Type G Test Separator Specifications

SEP-G

Service H2S

Vessel size 42 in. 15 ft [107 cm 4.57 m]

Maximum working pressure 720 [50](psi at 100F [bar at 38C])


LLL 10,500 [1670]

HLL 23,800 [3800]

Gas capacity (MMscf/D [Mm 3 /d])

LLL 41 [1160]

HLL 18 [510]


Gas outlet 3-in. Fig. 602

Oil outlet 3-in. Fig. 602

Water outlet 2-in. Fig. 602

Relief outlet 2 relief valves

Drain outlet 2-in. Fig. 602

Length (ft [m]) 23.25 [7.09]

Width (ft [m]) 7.4 [2.24]

Height (ft [m]) 8.0 [2.42]

Weight (lbm [kg]) 35,200 [16,000]

LLL and HLL at 720 psi [50 bar]


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80

Vertical gas separator (2200 psi)The vertical gas separator (Figs. 45 and 46 and Table 23) is designed for high gas flow raIt consists of the following:

cyclone cluster separ ating unit8-in. orifice met er, orifice set an d th ree-pen r ecorderoptional flow measuring system for oiloptional flow mea suring system for water4-in. gas cont rol valve2-in. oil/water cont rol valvestwo 3-in. pilot-oper ate d sa fety valves.

Figure 45.Vertical gas separator.


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Figure 46.Three views of a vertical gas separator.

Gas outlet

Water outlet

Fluid inlet

Side ViewFront View

Top View

Safety outlet

Gas outlet

Water outlet

Fluid inlet

Safety outlet

Oil outlet

Oil outlet

Drain

Drain


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82

Table 23. Vertical Gas Separator Specifications

SEPV-A

Service H2S

Working pressure (psi at 100F [bar at 38C]) 2220 [153]

Working pressure at max temperature (psi [bar]) 1970 at 300F [136 at 150C]


Liquid capacity (B/D [m3 /d]) 1500 [240]

Gas capacity (MMscf/D [Mm 3 /d]) 100 [2800]

Inlet 6-in. 900 RF 4-in. Fig. 1002

Gas outlet 6-in. 900 RF 4-in. Fig. 1002

Oil outlet 2-in. 900 RF 2-in. Fig. 1002

Water outlet 2-in. 900 RF 2-in. Fig. 1002

Drain outlet 2-in. 900 RF 2-in. Fig. 1002

Safety outlet 6-in. 300 RF 6-in. Fig. 206

Footprint (ft [m]) 10.6 8.0 [3.23 2.44]

Height (ft [m]) 27.3 [8.32]

Weight (lbm [kg]) 30,800 [14,000]


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84

Figure 47.Oil manifold.

Figure 48.Flow directions through the oil manifold.From separator

To gauge tank

From gauge tank

To burners


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Gas manifoldThe gas manifold (Fig. 49 and Table 25) directs t he gas produced from the sepa rator t o the or starboar d flareport a funct ion of wind direction ( Fig. 50). It consists of a skid-mount ed assewith t wo ball valves.

Well Testing Services Oil and Gas Manifolds 85

Figure 49.Gas manifold.

Figure 50.Flow directions through the gas manifold.

From separator

To burner To burner


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86

Table 25. Gas Manifold Specifications

MFD-ADB MFD-BDA

Service H2S H2S

Working pressure

(psi at 100F [bar at 38C]) 1440 [100] 1440 [100]

(psi at 212F [bar at 100C]) 1345 [93] 1345 [93]


Inlet 3-in. Fig. 602 4-in. Fig. 602

Outlet 3-in. Fig. 602 4-in. Fig. 602

Footprint (ft [m]) 5.0 1.0 [1.5 0.38] 5.9 1.5 [1.80 0.45]

Height (ft [m]) 1.3 [0.40] 1.5 [0.46]

Weight (lbm [kg]) 550 [218] 710 [322]


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Gauge and surge tanks are one of the met hods used to measu re the liquid flow rate from th e arator. A surge tank can also be used as a second-stage separator. The use of surge tankscompulsory for offshore operations and whenever H2S is present. An atmospheric gauge tankaccurately determines the shrinkage factor by measuring the oil volume change at atmosphepressure on a large volume; the same is applicable for a surge tank operating at atmosphepressure.

Surge tankThe surge tank is a pressur ized vessel used to me asure liquid flow rates and obt ain an a ccur

measurem ent of shrinkage and th e met er factor (Figs. 51 and 52). The two types of surge tankssingle-compa rtm ent vessel ( Table 26)dual-compartment vessel, which enables one compartment to be emptied with a transpum p while the oth er is being filled ( Table 27).

Both types of surge tan ks have an au tomat ic pressure con trol valve on th e gas outlet linemaintain backpressure up to the maximum working pressure of 50 psi for the single compment and 150 psi for the dual compartments. The change in volume is inferred from the leindicator on the basis of the ph ysical dimensions of the sur ge tank. High- and low-level alawarn when gauging will stop.

Safety features include a safety relief valve in case t he vessel is accident ally overpr essubeyond the maximum working pressure. A grounding strap is attached to the surge tank static discharge. A separa te gas vent line with flame arre stor to the bu rne r must b e used wisurge tank. The tank cannot be connected directly to the separator gas outlet because tpressure could exert backpressure on the surge tank.

Well Testing Services Tanks 87

Tanks


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Well Testing Services Tanks 89

Figure 52.Three views of a vertical surge tank.

Oil inlet Gas outlet

Oil outlet

Oil inlet

Side View

Front View Top View

Safety outletOil outlet

Gas outlet

Safety outlet


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90

Table 26. Single-Compartment Surge Tank Specifications

VST-BA VST-BB VST-BC

Service H2S H2S H2S

Working pressure (psi [bar]) 50 [3.5] 50 [3.5] 50 [3.5]


Capacity (bbl [m3]) 80 [12.2] 80 [12.2] 80 [12.2]

Oil inlet 3-in. Fig. 602 3-in. Fig. 602 3-in. Fig. 602



Safety outlet 4-in. Fig. 602 4-in. Fig. 602 4-in. Fig. 602

Drain 3-in. Fig. 602 3-in. Fig. 602 3-in. Fig. 602

Footprint (ft [m]) 8.0 7.9 [2.45 2.40] 8.0 7.9 [2.45 2.40] 8.0 7.9 [2.45 2.40]

Height (ft [m]) 19.7 [6.0] 19.7 [6.0] 19.7 [6.0]

Weight (lbm [kg]) 13,420 [6000] 13,420 [6000] 13,420 [6000]VST-BC has an ANSI class 600 oil manifold.

Table 27. Dual-Compartment Surge Tank Specifications

VST-FA VST-FB VST-N

Service H2S H2S H2S

Working pressure (psi [bar]) 50 [3.5] 50 [3.5] 50 [3.5]


Capacity (bbl [m3

]) 2

50 [2

8] 2

50 [2

8] 2

50 [2

8]Oil inlet 3-in. Fig. 602 3-in. Fig. 602 3-in. Fig. 602



Safety outlet 4-in. Fig. 602 4-in. Fig. 602 4-in. Fig. 602

Drain 3-in. Fig. 602 3-in. Fig. 602 3-in. Fig. 602

Footprint (ft [m]) 8.0 6.2 [2.45 1.89] 8.0 6.2 [2.45 1.89] 8.0 6.2 [2.45 1.89]

Height (ft [m]) 25.0 [7.60] 25.0 [7.60] 25.0 [7.60]

Weight (lbm [kg]) 26,500 [12,000] 26,500 [12,000] 26,500 [12,000]

VST-N has an ANSI class

book3 surface testing

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