Well Test Complete

1 Testing overview

Introduction

Accurate, long-term projections about a reservoir cannot be made based on wireline data alone.

Well tests must be run at the surface in order to gain more information about a reservoir. This

topic provides an overview of well testing. It describes why and when reservoirs are tested, what

is measured during testing, and what information is derived from testing. Well testing activities

can be divided into two major phases: data acquisition and data interpretation.

Why Is a Reservoir Tested?

Reservoirs are tested to answer questions about the reservoir that cannot be answered by wireline

and other techniques such as mud logging, coring, electrical logging, and seismic measurements.

Although extremely valuable, these techniques provide information only about static reservoir

conditions:

Porosity

Lithology

Rock type

Formation dip

Water saturation

Well testing is required to answer critical questions about the reservoir. By measuring relevant

parameters under dynamic conditions, these questions can be answered:

Will the reservoir flow?

What quantity of hydrocarbons are in place?

What quality of hydrocarbons exist?

How long will it be productive?

How long will it be profitable?

When Is a Reservoir Tested?

Tests on oil and gas wells are performed at various stages in the life of a well. Traditionally, a

well is tested after logging is finished and before or after the well is completed. It is also

common for a well to be tested one or more times during its life.

What Is Measured During a Test?

Data is gathered during the data acquisition phase. This topic describes the parameters that are

acquired when a reservoir is tested.

Flowrate values

Fluid flow rate (Q) values are obtained using surface testing equipment. To bring the well

fluids to surface where they can be handled and measured with surface testing equipment,

a flow path is needed between the reservoir (downhole) and surface. The path the fluid

takes is provided either by the well's permanent completion (tubing) or a temporary

completion called drill stem test (DST) string.

Pressure and temperature Initial reservoir pressure and pressure and temperature behavior are acquired from

downhole pressure (P) and temperature (T) values. These values are recorded using

electronic pressure sensors or gauges that are placed at the reservoir either in the DST

string or hung on a cable (slickline or electrical line).

PVT data Fluid from the reservoir is identified using PVT (pressure, volume, and temperature)

values. PVT data is derived from samples that are taken either at the surface or downhole

using sampling techniques and equipment. PVT values are obtained from the lab analysis

of these samples.

Porosity values Porosity values ( ) are obtained from wireline open-hole log data and/or coring.

What Is Derived from a Test?

During the interpretation phase, the data acquired during testing is used to make evaluations.

Using the parameters acquired in the data acquisition phase, the following can be calculated:

Reservoir parameters:

o Permeability (k)

o Heterogeneity parameters (lambda [ ], omega [ ], kappa [ ])

o Hydraulic fracture parameter (Xf)

o Initial reservoir pressure (pi)

Well parameters:

o Near well-bore formation damage: skin factor (S)

o Inflow performance relationship (IPR)

o Wellbore storage coefficient (C)

Geometry of the reservoir and its extent:

Reserve quantities

Hydraulic communication between wells

The accuracy of these evaluations during the interpretation stage is closely related to the

accuracy and the quality of the data collected during the data acquisition phase.

Different Types of Well Tests

The following are the typical well tests:

Exploration tests (oil or gas)

Productivity tests (oil or gas)

Injection tests

Interference tests

Pulse tests

Slug tests

Layered tests

Well Test Setup Diagram

See the "Well Test Setup" figure for a diagram of a well test setup.

Main Services Provided in Well Testing

The following lists the main services performed in well testing:

Surface testing

Downhole testing (e.g., DST)

Sampling

Data acquisition (surface and downhole)

Slickline

2. Surface Testing

Introduction

In order to accurately test a reservoir, tests must be run at the surface and downhole. Because

current technology does not allow all test equipment to function in a downhole environment,

surface testing is required. This training page describes the dynamic conditions under which well

tests must be performed, lists the surface testing equipment used to perform well tests,

summarizes how this equipment is used to collect samples at the surface and lists several

considerations that influence the layout of surface equipment.

Testing a Reservoir under Dynamic Conditions

A reservoir test can only be performed under dynamic conditions. This means the reservoir must

be exposed to a disturbance which will cause the reservoir pressure to change. This pressure

change, when recorded and interpreted along with the measured flowrates, will yield information

about well and reservoir parameters and geometry.

Creating a Pressure Disturbance

How a pressure disturbance is created depends on whether the reservoir is producing or shut

down:

If the well has been shut for a long time, the best way to create a pressure disturbance is

to flow the reservoir; this is called a drawdown.

If the well has been flowing for a long time, a pressure disturbance can be creating by

shutting the well; this is called a buildup. A pressure disturbance can also be created in a

flowing well by either increasing or decreasing the flowrate.

Surface Testing Equipment

In reservoir engineering, a period in which the well experiences changes in pressure is known as

a pressure transient. At the surface, the fluids produced during pressure transients must be

handled using temporary equipment. This is true because, in most cases, permanent production

facilities have not yet been installed. The temporary surface testing equipment must safely and

reliably perform a wide range of functions:

Quickly control pressure and flowrates at the surface and shut the well.

Separate the resulting effluent into three separate fluids (oil, gas and water) and

accurately meter these fluids.

Collect surface samples.

Dispose of the resulting fluids in an environmentally safe manner.

The following is a list of surface testing equipment:

Flowhead

Choke manifold

Emergency shut down (ESD) system

Heat exchanger

Separator

Tanks

Transfer pumps

Oil and gas manifolds

Burners and booms

Piping

Layout of Surface Testing Equipment

The surface equipment and the layout of the surface equipment needed to perform well tests

differs considerably depending on the type of environment, well conditions, and the client

requirements.

The following figure shows a typical offshore layout of surface testing equipment.

These are some of the considerations that dictate how surface equipment should be set up:

Location:

Land operation

Offshore operation

Well conditions:

High flowrate and high pressure

Effluent properties (oil properties and hydrate formation)

Sand production

Corrosive fluids (H2S, CO2, acid)

3. Equipment layout

Introduction

Prior to setting up the equipment for a well test, the equipment layout must be defined. The

layout diagram defines which pieces of surface testing equipment are to be used, identifies where

the equipment is located (zones and recommended distances), illustrates the sequence in which

the equipment is connected, and shows the general piping layout.

The surface testing layout varies according to these factors:

Location (offshore or onshore) Type of well effluent (oil or gas) Well effluent characteristics (high pressure, high flow rates, or high viscosity) Safety regulations (some equipment is restricted to certain zones)

The various combinations of these factors makes it possible to have many different layouts. Four

typical surface testing layouts are described in this training page.

Objectives

Upon completion of this package, you should be able to:

Draw a typical offshore surface testing equipment layout with the recommended safety distances.

Draw a typical onshore surface testing equipment layout with the recommended safety distances.

Give the definitions for safety zones 1 and 2.

Applications

The individual pieces of equipment that make up the surface testing layout are put together for

the purpose of producing the well at the surface, measuring the different components of the well

effluent, taking component samples, and disposing of the well effluent in an environmentally

safe manner.

Four typical surface testing layouts are described in this training page:

Standard onshore setup Standard offshore setup High flow rate setup High viscosity oil or foaming oil setup

Standard Onshore Layout

A typical layout for testing an onshore oil well is shown in "Onshore Surface Testing Layout"

drawing.

Although the order in which the surface testing equipment is connected is similar for all layouts,

equipment selection and placement can vary. The following text describes how safety

considerations and well effluent characteristics affect equipment selection and placement.

The required pressure rating for the flowhead, choke manifold, and separator depends on the

expected wellhead pressure and flow rates.

To reduce the length of the high pressure flow line between the flowhead and the choke

manifold, the choke manifold is located on the rig floor. This limits the length of piping with

high pressure flow. Placing the choke manifold on the rig floor also reduces the pressure drop

between the flowhead and the choke manifold, where the wellhead pressure and temperature are

monitored. The closer the choke manifold is to the wellhead, the more accurate the wellhead

pressure and temperature readings.

The gauge tank is positioned downwind of the drilling rig. Because the gas from the gauge tank

is vented to the atmosphere, it's important to keep the gas as far away from the working area as

possible.

The transfer pump is used to empty the tank to the burning pit. This layout does not use burners

to burn off oil and gas. Instead, oil and gas are driven to a burning pit with tubing joints

connected on the ground. Tubing joints should be at least 300 ft long and secured to the ground,

if high flow rates are expected. Today, burners are more frequently used than burning pits on

land, for both safety and environmental reasons.

The emergency shutdown system (ESD) is designed to shut off the well in case of an emergency.

Standard Offshore Layout

A typical layout for testing an offshore well is shown in the "Offshore Surface Testing Layout"

drawing. All the standard equipment used onshore is also used offshore.

Because space is scarce on offshore rigs, the space that's allotted for well testing equipment

dictates many layout decisions.

This layout uses a gauge tank instead of a surge tank. A surge tank is mandatory only when H2S

gas is present because H2S must be burned, not released to the atmosphere. To burn the gas

coming out of the surge tank, an additional gas line must be connected to the surge tank. Surge

tanks are used more frequently offshore because its vertical tank takes up less deck space than

the horizontal gauge tank.

Some offshore rigs have permanent piping to facilitate the connection between the different

pieces of equipment. The permanent piping is located inside the gray area shown in the

"Offshore Surface Testing Layout" diagram.

Offshore, two burners mounted on booms, one on each side of the rig, are used to dispose of the

oil and the gas. One burner or the other is used, depending on the wind direction. Burners require

compressed air to properly burn the oil and propane is necessary to supply the pilot lights for the

burners.

Identical to onshore layouts where burners are used, oil and gas manifolds are required to divert

the oil and gas coming out of the separator. A water pump is used to inject water into the oil

flame at the burner, which improves combustion, and to create a water screen behind the burner,

which reduces heat radiation.

High Flow Rate Layout

Although most tests worldwide are run with flow rates up to 5000 BOPD or 30 MMscf/D, flow

rates that surpass separator capacity are sometimes encountered. In these cases, the well testing

layout typically includes a parallel arrangement of several separators and choke manifolds to

handle the higher flow rates.

The "Surface Testing Layout for High Flow Rate Test" drawing shows an example of an onshore

high flow rate layout with two separators and two choke manifolds connected in parallel. Each

separator has its own gas and oil flare lines going to the burning pit. These lines should be at

least 1000 ft long and anchored to the ground. The size of the piping that connects the different

elements should be selected based on the expected flow rates. Correct piping size prevents very

high fluid velocities, large pressure losses, and overpressurization of the equipment.

For very high flow rate wells, the intensity of the heat generated at the burners makes it

dangerous and unsafe to use the standard burner and booms attached to the rig. To test these

types of wells, the effluent must either be injected into a pipeline or burned at a permanent flare

system far away from the rig.

High Viscosity Oil or Foaming Oil Layout

The main problems encountered with high viscosity oil are:

Flowing the well to surface Flowing the well through the surface equipment Separating oil from gas and oil from water Measuring each phase Obtaining samples Disposing effectively of oil without creating pollution

Reducing the viscosity of the oil is the key to minimizing these problems. The following text

focuses on the equipment and additives that reduce the viscosity of the oil, making it easier to

flow the well through the surface testing equipment. It also addresses prevention of hydrate

formation and foaming.

The (American Petroleum Institute) API definition of oil gravity is a function of the viscosity,

temperature, and amount of tar in the oil. API oil gravity is used as an indicator of viscosity.

Before a high viscosity well can be tested (with only minor modifications to equipment and

procedures), oil gravity must be above 10o API (viscosity below 300 centipoises).

Viscosity is reduced downhole by either heating the oil or by injecting diesel, gas, or steam into

the well. At the surface, viscosity is reduced by adding a heater or steam exchanger to heat the

well effluent before it enters the separator. The "Surface Testing Layout for a Gas Well or

Viscous Oil Test" drawing shows an onshore surface testing layout that includes a heater.

To prevent the formation of hydrates (common with gas wells), a pump can be used to inject

glycol upstream of the choke manifold.

When foaming oil is expected, silicon additives are injected, if heat is not sufficient to reduce or

eliminate the foam. Additives are injected as close as possible to the point where the foam

occurs.

Safety

The general safety considerations related to the layout of the surface testing equipment are:

Equipment layout and spacing must be done in accordance with classified zones. All of the pieces of surface testing equipment must be grounded. The electrical connection required for certain pieces of surface testing equipment, such as the

transfer pump or the laboratory cabin, must be safe and approved. Piping used for high pressure wells must be anchored. Piping must be color coded to identify the working pressure of the pipe. It is helpful if the piping

is labeled to identify the fluids passing through it. The dominate wind direction must be identified to properly orient equipment that vents or

burns gas.

Classified Zones

The information in this topic describes why classified zones were established, defines the

classified zones, and identifies which pieces of surface testing equipment are associated with

which zones.

A well site is classified into areas, zones, or divisions based upon the probability that flammable

gases or vapors may be present around a specific piece of equipment. For safety purposes, both

the API and French Association of the Oil and Gas Explorers and Producers have defined such

zones.

The following paragraphs rank classified zones from most to least hazardous and define each

zone. Zone restrictions don't dictate the placement of all well test equipment. For example, the

ESD and the oil and gas manifolds, although usually placed in zone 2, are not restricted to a

specific zone. However, other well test equipment is restricted to certain zones as described

below.

Zone 0

Area or enclosed space where any flammable or explosive substance (gas, vapor, or volatile

liquid) is continuously present in a concentration that's within the flammable limits for the

substance. The borehole or the well below the wellhead is zone 0.

Zone 1

Area where any flammable or explosive substance (gas, vapor, or volatile liquid) is processed,

handled, or stored; and where, during normal operations, an explosive or ignitable

concentration of the substance is likely to occur in sufficient quantity to produce a hazard.

The gauge tank is placed in a zone 1 because the presence of flammable gases in the immediate vicinity of the gauge tank vent is normal.

Most of the electric-driven transfer pumps are designed for use in zone 1, however, their use in this zone may be subject to geographical restrictions or client approvals.

At the choke manifold samples of well effluent are taken, typically at the beginning of a test. Because sampling causes some gas to be released to the atmosphere, the choke manifold is usually placed in zone 1.

Because the flowhead is used as a means of introducing tools into the well during a well test, the area around the flowhead is classified as zone 1, otherwise the area around the flowhead is classified as zone 2.

Zone 2

Area where any flammable or explosive substance (gas, vapor, or volatile liquid) is processed

and stored under controlled conditions. The production of an explosive or ignitable

concentration of such a substance in sufficient quantity to constitute a hazard is only likely to

occur under abnormal conditions.

The separator is placed in zone 2 because the separator only releases flammable gases or vapors under abnormal conditions, such as a leak.

Diesel-driven transfer pumps can be located in zone 2 if they are equipped with automatic shut down devices, spark arrestors, inertia starters or special electrical starters.

The indirect heater must be located in zone 2 because it uses a naked flame to heat well effluent. Because its surfaces can reach high temperatures, the steam exchanger is also restricted to zone 2.

Clean Zone

Area where no flammable or explosive substances are processed, handled, or stored. This zone

is also referred to as a non-hazardous or safe area. An example of a clean zone is the living

quarters of an offshore drilling rig.

Note: Schlumberger's safety procedures recommend not overlapping classified zones within a

well testing layout.

Safety Standards

The following drawings identify, for both onshore and offshore surface testing layouts, which

pieces of surface testing equipment are associated with which zones.

This list summarizes the key points illustrated in the "Onshore Safety Standards" and the

"Offshore Safety Standards" drawings.

Onshore, the area around the flowhead is classified as zone 2 within a radius of 15 m (45 ft) and offshore it is classified as zone 2 within a radius of 10 m (30ft).

In the event the separator vessel is overpressurized, the rupture disc will burst releasing effluent to the atmosphere. Because of this risk, the area around the separator rupture disc pipe is classified as zone 1 within a radius of 5 m (15 ft) and as zone 2 within a radius of 10 m (30 ft).

For both offshore and onshore layouts, the area (3 m or 15 ft) above the roof of the gauge tank is classified as zone 1.

Recommended Distances

The following drawings show how the recommended distances between different pieces of

equipment affect the onshore and offshore surface testing layout.

This list summarizes the key points illustrated in the "Onshore Recommended Distances" and the

"Offshore Recommended Distances" drawings.

Onshore, the separator should be located 25 m (75 ft) away from the wellhead. Offshore this distance may be reduced to 13 m (40 ft).

Onshore, the heater / steam exchanger should be located 30 m (90 ft) away from the wellhead. Offshore this distance may be reduced to 10 m (30 ft).

Onshore, the gauge tank should be located 30 m (90 ft) from the wellhead. Offshore, this distance may be reduced to 25 m (75 ft).

Onshore, the distance between the separator and the heater should be 30 m (90 ft). Offshore, this distance can be reduced to 3 m (10 ft).

Onshore, the distance between the gauge tank and the separator should be 25 m (75 ft). Offshore, this distance can be reduced to 15 m (45 ft).

Onshore, the distance between the heater and the gauge tank should be 30 m (90 ft). Offshore, this distance can be reduced to 15 m (45 ft).

For more information about how zones for petroleum sites are classified, see the references listed

for this training page.

Summary

In this training page, we have discussed:

Four typical well testing layouts: o standard onshore layout o standard offshore layout o high flow rate layout o high viscosity and foaming oil layout

The different classified zones and their definitions. The safety standards for an offshore and onshore well testing equipment layout. The recommended distances for an offshore and onshore well testing equipment layout

Self Test

1. What factors influence a surface testing layout? 2. Why would you locate the choke manifold as close as possible to the flowhead? 3. Why is a well site divided into zones? 4. Give the definition of zone 1.

Equipment

A) Flow head

This training page is divided into the following main headings:

Introduction Objectives Principles of Operation Equipment Safety Maintenance Summary Self Test References / Other Useful Links

Introduction


Introduction

Objectives

Principles of Operation

Equipment

The "Surface Test Equipment" figure shows where the flowhead is located

in relationship to the other surface testing equipment. The flowhead is

located directly on top of the well and is the first piece of equipment that

fluid from the well flows through. Its principal function is to control the

fluid flow in and out of the well.

The flowhead can be used to provide temporary shut off at the surface for:

pre-completion testing drill stem testing (DST) post-completion testing (carried out without the use of a christmas tree)

After the well is tested and completed, a permanent assembly of surface equipment (referred to

as the christmas tree) replaces the flowhead and will provide shut off services.

The flowhead has five principal functions:

It supports the weight of the test string. It allows up-and-down (reciprocal) movement of the test string; if a swivel is attached it also

allows rotation of the test string. Whether or not a swivel is needed depends on the type of downhole test equipment used. Some tools can be completely operated using up and down movements, some will need to be rotated, and others will require both types of movement.

It controls flow out of the well through a flow valve. It allows a kill line to be connected so the well can be killed off after a testing operation is done

or during an emergency. The kill line is essential to control the pressure in the well. Pressure control is necessary to pull the downhole test string out of the well after testing is complete and is essential for safety. For example, if the downhole pressure is too great, the tool string could be shot up through the rig floor.

It allows tools to be introduced into the well through the swab valve.

Objectives


Explain the purpose of a flowhead. Explain the operating principles for flowheads and swivels. Explain the function of the different parts of the flowhead. Describe the various types of flowheads and their applications and limitations.

Upon completion of the practical exercises for the Flowhead, you should be able to:

List the specifications for the flowhead that you are working on.

Document the procedures for pressure testing a flowhead and swivel, both at the shop and at the well site.

Using the flowhead provided, study the complete fast inspection tool (FIT) and tool review and inspection monthly (TRIM) as described in the maintenance manual for the flowhead, and study the Field Operating Handbook (FOH) for Surface Well testing.


The flowhead consists of four gate valves: a master valve, two wing valves, and a swab valve.

The outlet wing valve is opened and closed using an hydraulic actuator. Above the swab valve is

a lifting subassembly (sub) with a threaded connection. The threaded connection is often called

a quick union. The quick union is used to connect auxiliary pressure equipment which is needed

if tools are to be run downhole. Some flowheads have a protection frame bolted to the main

block to prevent damage to the valves during handling. Beneath the optional swivel are the

master valve assembly and the bottom sub. In order to raise and lower a drill stem test (DST)

string, elevators (clamps) are attached to the flowhead. Each of the elements that comprise the

flowhead or that can be attached to the flowhead are described later in this topic.

Basic to the operation of the flowhead is the opening and closing of valves in a particular

sequence or order depending on what operation needs to be done. The following list describes

several common operations and provides figures that show the typical status of the valves for

these operations. The valve settings may change depending on whether other operations must be

performed simultaneously.

Build up and set packer

Build up describes the time period when the well is shut

down and pressure is building up in the well. One way to set

the valves when you are shutting down the well is shown in

the "Build Up/Set Packer" figure.

As a part of the drill stem test (DST), a packer is set

downhole to isolate the zone to be tested, typical valve

settings for this operation are also shown in the "Build Up/Set

Packer" figure.

Drawdown

Drawdown describes the time period when the well is open. For

this operation, the valves are set so fluids can flow to the surface

as shown in the "Drawdown" figure.

Killing and acidizing

To stop the well from producing, the well is killed by

injecting a fluid inside the well that has a greater density than

the well effluent. The typical valve settings for this operation

are shown in the "Killing/Acidizing" figure.

Acid is injected into the well to improve well production by

enlarging the passages through which the reservoir flows. The

"Killing/Acidizing" figure shows the typical valve settings for

this operation.

Running tools downhole

To run tools downhole, one way to set the valves for this

operation is shown in the "Running Tools Downhole" figure. The

swab and master valve will always remain open when the tools

are downhole.

The following list describes the elements of a flowhead from the bottom up:

Bottom sub

The bottom sub connects the test string to the flowhead. It also

protects the threads at the bottom of the flowhead. (Replacing a sub

is inexpensive compared to remachining the flowhead threads.)

Master valve

The master valve, connected to the top of the test string, isolates the

surface equipment from the downhole string. It is the first valve at

the surface to control the fluid coming from downhole. The master

valve is manually operated.

Swivel

The flowhead swivel is inserted between the master valve and the

main valve block. It allows the subsurface equipment to be rotated

with respect to the main flowhead block. Using a swivel, it is possible

to rotate the subsurface equipment without disconnecting the flow

line or the kill line. An example of this is using the swivel to set the

drill stem test (DST) packer downhole.

The swivel is designed to allow rotation of the subsurface string (at speeds slower than 25 rpm)

under pressure, while supporting the weight of the whole subsurface string. Roller bearings are

used to support the significant weight of the test string and the downhole tools. Ball bearings are

used to support the lighter weight of the flowhead and the equipment above the flowhead.

Wing valves

The outlet wing valve allows fluids to flow from the well to the

process equipment. It is normally closed. To open it, an hydraulic

actuator is used. This actuator is usually connected to an

emergency shutdown (ESD) system. If the surface pressure

exceeds a preset value or suddenly drops, indicating a surface

equipment failure, the ESD is automatically activated by pressure

pilots or manually activated from a push button station to close

the wing valve.

The inlet wing valve, manually operated, allows fluid to be

pumped into the well. Typical examples are: pumping mud into

the formation to contain reservoir pressure, injecting acid into the

formation to increase production, or high pressure injecting of a

fluid to enlarge the passages through which the reservoir flows.

Hydraulic actuator

The hydraulic actuator is a safety device that operates the flowhead outlet wing valve. The valve

is normally closed. Pressure needs to be applied to the actuator to compress the spring and open

the valve.

The pressure needed to keep the valve open can be provided with a simple hand pump which, in

an emergency, is bled off on the rig floor. However, a more sophisticated system called an

emergency shut down (ESD) is recommended because it allows the actuator to be activated

remotely.

Wing union connection

Both wing valves are equipped with wing unions connections. They allow quick connection or

disconnection of pipe work using a sledge hammer.

Swab valve

The manually operated swab valve allows introduction and

retrieval of wireline tools.

Lifting sub

The lifting sub, located above the swab valve, allows the

flowhead to be handled using the rig elevators.The top part of

the sub is fitted with threads which allow pressure equipment to

be connected onto the flowhead.

Elevator

Elevators are used for many drilling-related operations; for the flowhead, the elevator latches

onto the flowhead to raise and lower the entire test string in and out of the hole.

Pressure equipment

A set of equipment that is temporarily placed above the swab valve on top of the flowhead. It is

used to run tools into a well under pressure without having to close the well.

Equipment

Flowheads are available in working pressure ratings of 3,000; 5,000; 10,000; and 15,000 psi. The

biggest difference between flowheads are the gate valves. Schlumberger uses gate valves from

several manufacturers: Malbranque, McEvoy, and Worldwide Oilfield Machine (WOM) Inc. The

wide range of flowheads available makes it possible to select a flowhead to accommodate all

types of well tests, without having to use equipment that is larger, more complicated, or

expensive than the overall project requires.

These drawings show examples of several types of flowheads and a swivel. For each drawing,

specifications are provided.

Description The FHT-AS flowhead is a lightweight, compact flowhead for low-pressure

operations. The main assembly consists of two wing valves with inte-gral swivel joint. Attached

to the top of the main assembly are a swab valve and lifting sub with quick union for wireline

equipment. Beneath the swivel are the master valve assembly and saver sub.

The master valve allows isolation of the sur-face equipment from the downhole test string.

The swab valve allows introduction and retrieval of wireline tools or a tubing-conveyed

perforating drop bar, for example.

The flowhead has two wing valves, one allowing fluid to flow from the well and the other for

pumping into the well. The wing valves are equipped with WECO hammer unions for quick

connection/disconnection of pipework.

The valves are manually operated gate valves.

Specifications

Certifying authority None

Design codes API 6A

Assembly number M-834246

Project code FHT-AS

Working pressure 3000 psi [207 bar]

Test pressure 6000 psi [415 bar]

Maximum load

At 0 psi

At working

pressure

90,000 lbf

61,000 lbf

Protection Marine anticorrosion coating

Nominal valve ID

Master valve/swab valve 2 9 Ž16 in. [65 mm]

Wing valves 2 1 Ž16 in. [52 mm]

API 6A classifications

Product specification

level PSL 1

Fluid classification AA (general service)

Temperature

classification P+U, 20 to 250°F [28 to 121°C]

Connections

Swab and master valves 3 5 Ž8 -in. -4 Acme box-box

Wireline quick union * 5-in. -4 Acme box

(3 1 Ž2 -in. [88.9-mm] ID box for 5000-

psi lubricators)

Flowline 2-in. Fig. 602 M hammer union

Kill line 2-in. Fig. 602 F hammer union

Maximum 3000 ft-lbf

Minimum 2000 ft-lbf

Dimensions

Length 66 in. [1.67 m]

Width 41 in. [1.03 m]

Depth 24 in. [0.61 m]

Lifting sub diameter 3 1 Ž2 in. [88.9 mm]

Weight 2200 lbm [1000 kg]

* Delivered with plug fitted with 1 Ž2 -in. NPT pressure port

Description The well test flowhead consists of four gate valves. The main block contains a swab

valve and two wing valves, one with a hydraulic actuator. Attached to the top of the main block

is a lifting sub with a quick union for wireline equipment.

A protection frame is bolted to the main block. Beneath the optional swivel are the master valve

assembly and saver sub. The master valve allows isolation of the surface equipment from the

downhole test string. The swab valve allows introduction and retrieval of wireline tools.


pumping into the well. The flowline valve is normally closed and is operated by a hydraulic

actuator, which is usually connected to an emer-gency shutdown system.

(See separate data sheet for information on swivel assembly.)

Specifications

Certifying authority Det Norske Veritas

Design codes DNV Drill "N," DOE

SI 289

API 6A, NACE MR

01 75

Assembly number P-579047 P-579048

Project code FHT-F FHT-G

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

Test pressure 10,000 psi [690 bar] 15,000 psi [1034

bar]

Maximum load

At 0 psi

At working

pressure

300,000 lbm

200,000 lbm

490,000 lbm

300,000 lbm

Makeup torque

Maximum

Minimum

3000 ft-lbf

2000 ft-lbf

7500 ft-lbf

4000 ft-lbf

Protection Marine anticorrosion

coating

Nominal valve ID

Master valve/swab valve 2 9 Ž16 in. [65 mm]

Wing valves 2 1 Ž16 in. [52 mm]



level PSL2 PSL3

Fluid classification DD EE

Temperature

classification

P+U, 20 to 250°F [28

to 121°C]

Connections

Master valve (box) 4 1 Ž2 -in. -4 Stub

Acme 6 1 Ž2 -in. -4 Acme

Wireline quick union * 6 1 Ž2 -in. -4 Acme 6 1 Ž2 -in. -4 Acme

Flowline 3-in. Fig. 1002 M 3-in. Fig. 1502 M

Kill line 3-in. Fig. 1002 F/M 3-in. Fig. 1502 F/M

Dimensions

Length 149 in. [3.78 m] 149 in. [3.78 m]

Width 37 in. [0.94 m] 39 in. [0.99 m]

Depth (including

protective frame) 35 in. [0.89 m] 35.5 in. [0.90 m]

Weight 4410 lbm [2000 kg] 5000 lbm [2265 kg]

* Delivered with plug fitted with 1 Ž2 -in. NPT

pressure port

Description

The well test flowhead consists of four gate valves. The main block contains a swab valve and

two wing valves, one with a hydraulic actua-tor. Attached to the top of the main block is lifting

sub with a quick union for wireline equipment.

A protection frame is bolted to the main block. Beneath the optional swivel are the master valve

assembly and saver sub. The master valve allows isolation of the surface equipment from the

downhole test string. The swab valve allows introduction and retrieval of wireline tools.


pumping into the well. The flowline valve is normally closed and is operated by a hydraulic

actuator, which is usually connected to an emer-gency shutdown system.

(See separate data sheet for information on swivel assembly.)

Specifications


Design codes DNV Drill ³N,² DOE

SI 289

API 6A, NACE MR

01 75


Project code FHT-DM FHT-HM

Working pressure 15,000 psi [1034 bar] 15,000 psi [1034 bar]

Test pressure 22,500 psi [1380 bar] 22,500 psi [1380 bar]

Maximum load

At 0 psi

At working

pressure

661,400 lbf

322,900 lbf

661,400 lbf

322,900 lbf

Makeup torque

Maximum

Minimum

7500 ft-lbf

4000 ft-lbf

7500 ft-lbf

4000 ft-lbf


coating



level PSL3 PSL3

Fluid classification EE (H2S, CO2) EE (H2S, CO2)

Temperature

classification P+U, 20 to 250°F P+X, 20 to 320°F

Connections

Master valve (box) 6 1 Ž2 -in. -4 Acme * 6 1 Ž2 -in. -4 Acme

Hostile

Wireline quick union 7-in. -5 Acme, 3-in.

ID

7-in. -5 Acme, 3-in.

ID

Flowline 3-in. Fig. 2202 M 3-in. Fig. 2202 M

Kill line 3-in. Fig. 2202 F/M 3-in. Fig. 2202 F/M

Dimensions

Length 157 in. [3.99 m] 157 in. [3.99 m]

Width 59.5 in. [1.51 m] 59.5 in. [1.51 m]

Depth (including

protective frame) 65 in. [1.65 m] 65 in. [1.65 m]


Option

Graylock HUB connectors can replace Fig. 2202 WECO Unions.

* The 6 1 Ž2 -in. -4 Acme ³Hostile² connections are not

interchangeable with the 6 1 Ž2 -in. -4 Acme connections of FHT-

DM.

Description

The flowhead swivel is inserted between the flow-head master valve

and the main valve block. With the flowhead swivel, the test string

suspended from the flowhead can be rotated independently of the main

flowhead block (for example, when setting a packer or for emer-gency

disconnection of a subsea test tree). The swivel should not be rotated

when pressurized.

Specifications


Design codes DNV Drill ³N,² DOE SI

289

API 6A, NACE MR 01

75

Assembly number M-838710 M-832758 M-832683

Project code FHS-B FHS-C FHS-D

Working pressure 5000 psi

[345 bar]

10,000 psi

[690 bar]

15,000 psi

[1034 bar]

Test pressure 10,000 psi

[690 bar]

15,000 psi

[1034 bar]

22,500 psi

[1550 bar]

Nominal ID (drift) 3 1 Ž8 in. [79 mm] 3 1 Ž16 in. [78 mm] 3 1 Ž16 in. [78 mm]

Maximum load without

rotation

At 0 psi

At working pressure

300,000 lbf

200,000 lbf

490,000 lbf

300,000 lbf

661,400 lbf

322,900 lbf

Connections 4 1 Ž2 -in. -4 Acme 6 1 Ž2 -in. -4 Acme 6 1 Ž2 -in. -4 Acme


coating


Product specification level PSL 2 PSL 3 PSL 3

Fluid classification DD (H2S) EE (H2S, CO2) EE (H2S, CO2)

Temperature classification P+U P+U P+U

20 to 250°F [28 to 121°C]

Makeup torque

Maximum

Minimum

3000 ft-lbf

2000 ft-lbf

7500 ft-lbf

4000 ft-lbf

7500 ft-lbf

4000 ft-lbf

Dimensions

Total length 42.5 in. [1.08 m] 48.5 in. [1.23 m] 48.5 in. [1.23 m]

Makeup length 32.7 in. [0.83 m] 38.0 in. [0.96 m] 38.0 in. [0.96 m]

Diameter 12.6 in. [0.32 m] 15.3 in. [0.39 m] 15.3 in. [0.39 m]

Weight 880 lbm [400 kg] 1210 lbm [550 kg] 1210 lbm [550 kg]

The 15,000-psi FHC-DC "hostile" swivel has a temperature rating to 320°F (API 6A, P+X).

Flowheads from these manufacturers currently satisfy the Schlumberger pressure operation

guidelines for surface pressure control:

A minimum of two primary pressure barriers must be used in the flow path: the master valve and the flow line valve.

The valves must be rated at least 1.2 times the maximum expected shut-in wellhead pressure.

The maximum pressure that can be used to test the flowhead at the well site is the working pressure.

When the surface equipment includes a swivel, it must always be located downstream of the master valve.

Flowhead Selection Guidelines

The principal criteria for selecting a flowhead are:

Project requirements (some jobs will require christmas tree equipment). Pressure rating greater than 1.2 times the expected shut-in well-head pressure. Required service type (operating environment): H2S resistant or not H2S resistant. Fluid temperature: high or low.

Additional selection considerations are:

Swivel requirement (mandatory with some downhole tools requiring rotation). Connection (cross-over) requirements for test string, flow line, and the kill line. Pressure equipment may require quick-union compatibility. Emergency shut-down (ESD) system needed for hydraulic actuator. Internal diameter of the flowhead.

Flowhead Identification

The flowhead can be identified by its working pressure (WP) rating and service type. The

information can be on: a metal plate, a permanently attached metal ring, or a dot that is stamped

on a noncritical area of the flowhead. It is also typical to use colored bands (painted or taped) on

the flowhead for quick visual identification of flowhead pressure and service type.

Safety

The following is a list of key safety considerations for flowheads:

A flowhead is a safety device. As such, they must be maintained in perfect condition and operated by competent people.

Only Schlumberger employees are allowed to operate flowhead controls. Do not lift the flowhead by the eye bolts that are fitted to some flowheads. The eye bolts are

not designed to support the weight of the flowhead. During testing, numerous hydraulic hoses overcrowd the rig floor. Make sure the flowhead

control hoses are neatly laid down, located, and well marked. Do not use steel hammers to tighten wing union connections. Brass or copper hammers must be

used to prevent sparks. The brass or copper hammer must be in good condition to avoid injuries from metal chips that can break off of these hammers.

Always open a well slowly using the master valve to avoid the shock from a large pressure kick which can occur due to the difference in pressure between the atmosphere and the well.

For all types of gate valves, count the number of turns to open and close each valve, then back up the valves one-quarter turn to make it easier to open and close valves and to prevent sticking.

For wireline jobs, make sure that the wireline string is totally inside the lubricator before closing the swab or the master valve. If these valves are closed on the wireline string, they could be damaged or cause damage to other equipment.

Make sure there are always enough piping lengths on the wing valves to manipulate the tool string and to compensate for up and down movement (heave) of the offshore rig so the flowhead is never submitted to lateral forces. On offshore rigs, the string is fixed but the rig will heave. Sufficient piping must be used between the flowhead and the choke manifold (flowline) and between the flowhead and the pump (kill line) to compensate for this movement.

After every job, the flowhead must be cleaned thoroughly to prevent corrosion from well fluids. To determine if a connection is backing off, all connections on the flowhead are marked with

chalk or paint to easily recognize if a connection has loosened. Always remove all valve handles from the flowhead after opening or closing them to prevent

handles from falling onto the rig floor as the flowhead is manipulated.

Maintenance

For information about flowhead preparation and functional checks, see the recommended steps

in the "Field Operating Handbook (FOH) for Surface Well Testing."

For infomation about equipment maintenance, see the maintenance manuals for the flowhead and

the "FOH for Surface Well Testing."

Summary


The five principle functions of the flowhead. Each of the components that make up a typical flowhead. The swivel's main application is its ability to rotate the subsurface equipment without

disconnecting the flowline and the kill line. How the hydraulic actuator, connected to the outlet wing valve, operates to safely and quickly

shut down the flowline. Valve settings (open-closed) for four common flowhead operations. The criteria for selecting a flowhead.

Self Test

1. List the five principal functions of the flowhead. 2. What is the purpose of the swab valve? 3. When is a swivel needed? 4. If you are monitoring the well head pressure at the choke manifold during a build up, which

flowhead valves should be open? 5. Why is the outlet wing valve equipped with an hydraulic actuator?

6. When rigging up the flowhead, how can you verify that the connections do not back off?

b) Choke manifold

Introduction

The choke manifold is used to control the fluid from

the well by reducing the flowing pressure and by

achieving a constant flow rate before the fluid enters

the processing equipment on the surface.

When testing a well, the aim is to impose critical

flow across the choke. When critical flow is

achieved, changes in pressure and flow rate made

downstream from the choke do not affect downhole

pressure and flow rate.

Features and Benefits

The choke manifold has the following features and benefits:

four gate valves used to isolate the choke boxes on either side of the choke manifold. an adjustable choke to gain quick control of the well and to change fixed choke beans without

interrupting the flow. a fixed choke box to insert calibrated choke beans of different diameters, depending on the

pressure and flow rate required. tapping points for measurement of the upstream and downstream pressures. thermometer well inserted in the flow path allowing the fluid temperature to be monitored.

The choke manifold, with a design featuring a fixed and adjustable choke, is a versatile piece of

equipment. At both chokes, the size of the orifice that fluid flows through can be varied,

allowing maximum control over fluid flow rate and pressure. In addition, the adjustable choke

makes it possible to control flow pressure without stopping the well, further enhancing the

flexibility of the system.

The combination of a fixed and adjustable choke allows the choke manifold to achieve various

flow rates (low and high) as needed to support well testing requirements and client

specifications.

Applications

The choke manifold is part of the minimum set of surface testing equipment needed when a well

is being tested. It is used whenever the fluid flow rate and pressure need to be controlled or

altered for the purpose of testing the well.

This package is divided into the following main headings:


Introduction

The "Surface Test Equipment" figure shows where the choke manifold is located in relation to

the other surface testing equipment. The choke manifold is downstream of the flowhead. Its

principal function is to control flowrate and pressure. Fluid flows from the flowhead to the choke

manifold, where flowrate and pressure are reduced by the restrictive orifices in the choke

manifold.

A choke device is used for a number of purposes at the surface or downhole. For example,

chokes can be used downhole as safety devices to control the formation of hydrate (solid

chemical compounds of hydrocarbons and water). Its principal use is to control flow rate and

pressure at the well head. This topic focuses on the surface choke, commonly used during testing

and production.

During production, a choke is located in the flow line where the well fluids leave the christmas

tree.

During testing, a special piece of equipment, the choke manifold, is used. The choke manifold

has a fixed and an adjustable choke. The fixed choke has a fixed diameter. The size of the orifice

on the adjustable choke can be varied. In addition the adjustable choke allows fixed chokes to be

switched out as needed without stopping the well, increasing the flexibility of the overall system.

The surface choke has these principle functions:

It allows wellhead pressure to be controlled, improving safety. It maintains a certain flow rate, as required for testing. A test can require different flow rates

over several time periods, requiring the use of different choke sizes. It prevents formation sand from entering the well by limiting the flow rate. Limiting the flow

rate reduces the speed of the fluid, which in turn, minimizes the amount of sand entering the well.

It also prevents water and gas coning by limiting the flow rate. It is also used to ensure that the flow is critical, meaning that the pressure fluctuations

downstream of the choke manifold do not affect downhole pressure and flow rate of the well.

(As a rule of thumb, critical flow is obtained when the downstream choke pressure is approximately 0.6 times the upstream pressure.)

Objectives

Upon completion of this package, a person should be able to:

Explain the purpose of a choke manifold. Explain the operating principles for choke manifolds. Describe the various types of choke manifolds, their applications and limitations. Describe the function of each component of the choke manifold. Describe how to change the choke when the well is flowing.

Upon completion of the practical exercises for this package, a person should be able to:

Write a procedure that tells how to pressure-test and operate a choke manifold. Using the choke manifold provided, review fast inspection tool (FIT) and tool review and

inspection monthly (TRIM) procedures for the choke manifold as per the maintenance manual. Dismantle and reassemble the adjustable choke assembly.


The choke manifold controls the fluid produced from the well by imposing a constant flow rate.

A choke is simply a device used to restrict fluid flow and the choke manifold usually has two

choke boxes that house two chokes: one is usually adjustable, while the other is fixed.

The choke manifold has an upstream (high pressure) side and a downstream (low pressure) side.

It is vitally important to know, at a glance, which side is which because the valves and spacers

can be rated for different working pressures. However, today most valves have the same pressure

rating on both sides, making the valves interchangeable.

Flow can be directed through one choke or the other, or through both in parallel. It is important

to know the exact diameter of the choke when making pressure and flow rate measurements

because the choke size is part of the flow rate calculation and the flow rate description. It's

standard to include the choke size when describing flow rate: "2,000 barrels a day on a 1/2-inch

choke."

A typical choke operation involves switching the flow from the adjustable choke side to the fixed

choke side to change the pressure or flow rate. First the well is opened to flow fluid through the

adjustable choke that has been preset to a specific diameter. (This is done before the upstream

valve on the choke manifold is opened.) The adjustable choke size is changed until the required

wellhead pressure or flow rate is attained. The proper choke size to choose for a specified flow

rate can be estimated from choke performance charts that show the relationships between choke

size, pressure, and flow rates. When the required pressure is reached and is stable, the graduated

barrel on the adjustable choke is read and the corresponding size of fixed choke bean is put in the

fixed choke box. If the adjustable choke reading is 1/2-inch, then the 1/2-inch choke bean is put

in the fixed choke box. The flow can then be diverted through the fixed choke.

Gate valves

The four manual valves on the choke manifold are gate valves. These valves are arranged so the

flow can be directed through one of two choke boxes that contain either a fixed or an adjustable

choke. The downstream gate valves can have a different working pressure rating than the

upstream gate valves. This is especially true for older choke manifolds; for choke manifolds

manufactured today, the four valves have identical pressure ratings and are interchangeable.

Tapping points

Both inlet and outlet (Y-shaped) of the choke manifold have four 1/2-inch National Pipe Threads

(NPT) tapping points or holes. These holes connect temperature and pressure gauges, either

mechanical or electrical, to monitor the pressure and temperature of effluent during a test. All

the pressure tapping points are fitted with a needle valve so the gauges can easily be isolated.

Tapping points are also used to collect samples for quick on-site analysis.

On the upstream side, three holes are used to connect independent pressure recorders that

monitor the well head pressure. The fourth hole usually has a thermometric well installed

so that a simple mercury thermometer or an electric thermometer can be inserted to

measure temperature.

The downstream side is identical to the upstream side: one hole is usually fitted with a

thermometric well and the other holes are used to monitor the downstream choke

pressure.

Independent pressure/temperature recorders

The following types of independent pressure recorders are used to to monitor the wellhead

pressure. Its important to note that, more and more, mechanical measuring devices are used as

backups due to the widespread use of electrical sensors that are connected to a computer.

a Bourdon tube pressure gauge quickly provides an indication of the upstream pressure. a dead weight tester (DWT) accurately measures the well head pressure. a chart pressure recorder keeps track of the behavior of the well-head pressure during

the test. thermometer, either electrical or mercury.

Fixed choke

On one side of the choke manifold, calibrated choke beans are used to control flow rate through

the fixed choke box. Each bean is a specific diameter, usually in graduations of 1/64-inch, and is

screwed into the choke box. These are the most common sizes (in inches) of choke beans used:

1/8, 3/16, 1/4, 5/16, 3/8, 7/16, 1/2, 9/16, 5/8, 3/4, 7/8, 1, 1-1/4, and 1-1/2. Depending on the

type of equipment used, the size of the choke bean can be as large as 3 inches. (In the field the

term fixed choke is used to refer to the fixed choke bean.)

The fixed choke box is equipped with a 1/2 inch-NPT hole connection that is used to

bleed off the pressure before changing the bean.

Adjustable choke

An adjustable or variable choke manifold is a variable geometry orifice that is fitted on one side

of the choke manifold. It allows the size of the orifice that fluids flow through to be changed,

and it permits the fixed choke to be changed out without interrupting the fluid flow from the

well. The adjustable choke is a conical plug against a tapered seat. Flow control is obtained by

turning the external handwheel which opens or closes the choke. A graduated barrel on the axle

indicates the orifice size. The seat for the adjustable choke looks similar to the choke beans for

the fixed choke; however they are different, both in the length and in the shape of the inlet.

Don't put the seat from an adjustable choke inside the fixed choke.

Because the size of the opening varies, flow rate calculations for adjustable chokes may not be as accurate as flow rate calculations for fixed chokes.

Adjustable chokes are particularly vulnerable to erosion from suspended sand particles. The adjustable choke is not designed to work as a valve. Seats are available in the following sizes: 1-inch , 1-1/4 inch, and 1-1/2 inch. Depending

on the type of equipment used, the size of the choke seat can be as large as 3 inches. The fixed choke box is equipped with a 1/2 inch-NPT hole connection that is used to

bleed off the pressure before changing the seat.

Bleed off port

On both choke boxes, the bleed off port is also used to connect a hose, one end of which is

immersed in a bucket of water. At the very beginning of a test, if effluent does not reach the

surface the hose and bucket can be used to check whether air/gas flow exists. During the clean-

up period, this hose can also be used to collect fluid samples at surface to measure the amount

of basic sediments and water (BSW).

Centrifuge

BSW is measured with a manual or electric centrifuge which separates the sample into its

components according to their densities. The percentage of oil, water and sediments is read

directly from the graduated glass tubes in which the sample was taken. This check will ensure

that the flow will not be diverted to the separator before less than 1% of BSW is obtained so the

separator will not be filled with sediments.

Sniffer

At the same time a fluid sample is taken, you can measure the gas concentration, typically CO2

and or H2S, using a sniffer. The reactive tube connected to the sniffer is made of glass and

contains a reactive material for the gas that it measures. The concentration of gas is measured

by the graduated lines in the reactive tube.

Weco connections

Both the inlet and outlet of the choke manifold are equipped with Weco hammer wing union

connectors to allow quick connection and/or disconnection to other equipment.

Equipment

Pressure Ratings for Choke Manifolds

Choke manifolds are available in 3,000; 5,000; 10,000; and 15,000 psi. The choke manifolds in

the following figures satisfy the Schlumberger pressure operations guidelines for surface testing

equipment. The wide range of choke manifolds available makes it possible to select a choke

manifold that accommodates the well tests required, while not being larger, more complicated, or

expensive than the overall project requires.

The choke manifolds used by Schlumberger can be assembled with gate valves from several

different manufacturers: Malbranque, McEvoy, and WOM.

These figures show examples of several types of choke manifolds and list their specifications.

Description

The choke manifold is used for controlling flow rate and for reducing the effluent pressure to

acceptable levels before it enters the process equipment.

The choke manifold is composed of four gate valves, a variable choke box, a fixed choke box

and tapping points for measurement of upstream and downstream pressures. A thermometer

well is usually provided. Each choke box has a pressure bleedoff port that is fitted with a needle

valve.

The manifold is skid mounted and comes with an integral storage box for a fixed choke set,

valve handles and other accessories.

Specifications


Design codes API 6A


Project code FMF-AA

Integral bypass valve NO


Test pressure 6,000 psi [415 bar]

Nominal ID (drift) 2 1 Ž16 in. [52 mm]

Adjustable choke size 1 1 Ž4 in. [32 mm]

Choke bean series D-52



Product specification level PSL 1

Fluid classi ication AA

Temperature classification P+U, 20 to 250°F [28 to 121°C]

Connections Inlet 2-in. Fig. 602 F/M WECO Union

Outlet 2-in. Fig. 602 M WECO Union

Dimensions

Length 27.5 in. [0.7 m]

Width 40.5 in. [1.03 m]

Height 23 in. [0.58 m]

Height to centerline of inlet / outlet 8.5 in. [0.22 m]


Description

The choke manifold is used for controlling flow rate and for reducing the effluent pressure to


The choke manifold is composed of four gate valves (five if a bypass valve is included), a

variable choke box, a fixed choke box and tapping points for measurement of upstream and

downstream pressures. A thermometer well is usually provided. Each choke box has a pressure

bleedoff port that is fitted with a needle valve.

The manifold is skid mounted and comes with an integral storage box for a fixed choke set, valve

handles and other accessories.

Specifications


Design codes DNV Drill ³N,² DOE SI 289

API 6A, NACE MR 01 75

Assembly number M-873331 M-873330

Project code FMF-BBS FMF-D *

Integral bypass valve Yes No

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


Nominal ID (drift) 3 1 Ž8 in. [79 mm] 3 1 Ž8 in. [79 mm]

Adjustable choke size 1 1 Ž2 in. [38 mm] 1 1 Ž2 in. [38 mm]

Choke bean series D-58 D-58

Protection Marine anticorrosion coating Marine anticorrosion

coating



Fluid classification DD (H2S)


Connections

Outlet 3-in. Fig. 1002 M WECO

Union

Inlet 3-in. Fig. 1002 F WECO Union

Dimensions

Length 63 in. [1.59 m] 70 in. [1.78 m]

Width 81 in. [2.05 m] 72 in. [1.84 m]

Height 38 in. [0.96 m] 38 in. [0.96 m]

Height to centerline of inlet /

outlet 13 in. [0.33 m] 13 in. [0.33 m]


* The FMF-D is not shaped as overleaf but has ³Y² inlet and outlet pieces.

Description

The choke manifold is used for controlling flow rate and reducing the effluent pressure to



variable choke box, a fixed choke box and tapping points for measuring upstream and





Specifications





Project code FMF-F FMF-G

Integral bypass valve No No

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



Adjustable choke size 1 1 Ž2 in. [38 mm] 2 in. [51 mm]




Product specification level PSL 2 PSL 3

Fluid classification DD (H2S) EE (H2S, CO2)


Connections Inlet (WECO Union) 3-in. Fig. 1002 F 3-in. Fig. 1502 F

Outlet (WECO Union) 3-in. Fig. 1002 M 3-in. Fig. 1502 M

Dimensions

Length 70.1 in. [1782 mm] 77.3 in. [1965 mm]

Width 72.4 in. [1839 mm] 77.5 in. [1970 mm]

Height 37.6 in. [955 mm] 38.8 in. [986 mm]

Height to centerline of inlet / outlet 13.0 in. [330 mm] 13.0 in. [330 mm]


Description




variable choke box, a fixed choke box and tapping points for measuring upstream and





Specifications





Project code FMF-ABJ FMF-CCM

Integral bypass valve Yes No

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



Adjustable choke size 2 in. [51 mm] 2 in. [51 mm]


Protection Marine anticorrosion coating Marine anticorrosion coating





Connections


Inlet 3-in. Fig. 1502 F/M WECO Union

Dimensions

Length 80.3 in. [2040 mm] 63.6 in. [1620 mm]

Width 94.5 in. [2400 mm] 94.5 in. [2400 mm]

Height 35.4 in. [900 mm] 35.4 in. [900 mm]

Height to centerline of inlet / outlet 21.7 in. [550 mm] 21.7 in. [550 mm]


Description



The choke manifold is composed of four gate valves, a variable choke box, a fixed choke box

and tapping points for measuring upstream and downstream pressures. A thermometer well is

usually provided. Each choke box has a pressure bleedoff port fitted with a needle valve.

The manifold is skid mounted and comes with integral storage boxes for a fixed choke set, valve

handles and other accessories. Inlet and outlet connections are 3-in. Fig. 2202 WECO unions, or

CIW/Graylock hubs when metal-to-metal seals are required.

Specifications


equivalent

Design codes DNV Drill ³N,² DOE SI

289


Working pressure 15,000 psi [1035 bar]

Test pressure 22,500 psi [1380 bar]

Nominal valve ID 2 9 Ž16 in. [65 mm]

Adjustable choke size 2 in. [51 mm]

Choke bean series Cameron Unitaper


coating



Fluid classification EE (H2S, CO2)

Temperature classification P+U, 20 to 250°F [28 to

121°C]

Connections

Inlet

3-in. Fig. 2202 F WECO

Union

(optional 3 1 Ž16 -in.

CIW hubs)

Outlet 3-in. Fig. 2202 M WECO

Union

(optional Graylock C-25

hubs)

Dimensions


Width 105 in. [2.67 m]


Height to centerline of inlet / outlet 27 in. [0.69 m]

Weight

2800 lbm [1270 kg]

Choke Manifold Identification

The choke manifold can be identified by its working pressure (WP) rating and service type. This

information can be on a metal plate, on a permanently attached metal ring, or on a dot that is

stamped on a noncritical area of the choke manifold. It is also typical to use colored bands

(painted or taped) on the flowhead for quick visual identification of flowhead pressure and

service type.

Safety

The following is a list of key safety considerations for choke manifolds:

When diverting flow, always open one valve before closing another. This practice prevents flow interruption and pressure buildup upstream of the valves.

Never flow through the manifold if the chokes are not in place. Corrosive fluids and/or sand particles can erode the threads in the choke boxes.

Do not use the adjustable choke to stop the flow, you can break the stem tip. Always count the number of turns to open and close each valve, then back up the valves one-

quarter turn to make it easier to open and close valves and to prevent sticking. Do not use steel hammers to tighten Weco connections. Brass or copper hammers must be used

to prevent sparks. These hammers must be in good condition to avoid injuries from brass or copper chips that can break off during use.

Beware of trapped pressure--pressure can kill. Always bleed off pressure using the bleed off port before changing a choke.

Stay upwind when taking fluid samples and wear safety goggles to prevent injury. Fluid can contain dangerous effluents, such as H2S acid.

Maintenance

For information about choke manifold preparation and functional checks, see the recommended

steps in the "Field Operating Handbook (FOH) for Surface Well Testing."

For information about equipment maintenance, see the maintenance manuals for the choke

manifold and the "FOH for Surface Well Testing."

Summary


The principle functions of the choke manifold. How to perform a typical choke manifold operation: switching the flow from the adjustable to

the fixed choke. An important benefit of the adjustable choke is that it allows the fixed choke to be changed

without interrupting the fluid flow from the well. Calibrated choke beans are used to control flow rate through the fixed choke box.

Self Test

1. What is the role of a choke manifold? 2. Why is the choke manifold equipped with an adjustable choke and a fixed choke? 3. Why is it important to establish critical flow across the choke manifold? 4. What measurements are usually monitored at the choke manifold? 5. When a well is open and the effluent does not reach the surface, how can you determine

whether the well will produce? 6. During the cleanup phase, a well is flowing through the adjustable choke and the upstream

pressure is building up rapidly. What is the probable cause of the upstream build up? What action should you take?

c) EMERGENCY SHUTDOWN

Introduction

The emergency shut down (ESD) is used when quick closure is necessary due to a pipe leak or

burst, equipment malfunction, fire, or similar emergency. The ESD system allows a flow line

valve to be safely closed

from a remote station or

from the ESD console.

The ESD system can be connected to the hydraulic flowhead valve or any other single-action,

fail-safe hydraulically activated valve, provided that the pressure required to open the valve does

not exceed the ESD limit of 6,000 psi hydraulic pressure.

In well testing operations, the ESD controls the hydraulically-operated flow line valve on the

flowhead; if required by the surface testing setup, it can also control an additional safety valve

(not shown) which is sometimes located upstream of the choke. Pressure is applied from the ESD

to open valves and released to close valves.

The ESD is push-button activated from ESD stations located at the separator, the heater/steam

exchanger, and the tank. An additional station is commonly positioned at an escape route. To

back up these stations, hi/lo-pressure pilots are located on the flowline upstream of the choke

manifold, upstream of heater/steam exchanger, and upstream of the separator. The hi-pressure

pilot initiates well closure when the pressure in the flow line rises above a high-level threshold

(line plugged), and the lo-pressure pilot initiates well closure when the pressure falls below a

low-level threshold (flow line rupture or leak).

The ESD is powered from air supplied from the rig. If this air supply fails, the ESD has an air

storage tank that can supply air to ESD stations and pressure pilot lines. This tank supplies air to

the air circuit lines, but not to the hydraulic pump that opens the flowhead valve. The quantity of

air required to operate the hydraulic pump is too great to be stored in the air tank. A check valve

is installed between the tank and the hydraulic pump to prevent any tank air from going to the

hydraulic pump. If you want to open the flowhead valve in this situation, you need to use the

manual pump at the ESD.

Objectives


Explain the purpose of the emergency shut down (ESD) system. Explain the operating principles for the ESD.

Describe the setup of the ESD system used in your location. Explain how the different parts of the ESD work.

Upon completion of the practical exercises for this package, you should be able to:

Rig up the ESD system with hi/lo-pilots and manually-operated buttons. Function test the hydraulic actuator on the flowhead with the ESD. Dismantle and reassemble the V4 interface valve and the hi/lo-pilots.


ESD Push-Button Stations

This sequence of drawings shows how the ESD is activated from its idle state (no pressure

applied) to its triggered state when the system is activated from an ESD station.

ESD idle

The ESD contains two circuits: hydraulic (oil) and pneumatic (air). These circuits are linked

together via the hydraulic-pneumatic V4 interface valve.

The hydraulic fluid flows from an air-driven hydraulic pump to the actuator on the surface

safety valve through the V4 valve. (A manual pump can replace the air-driven pump.) Because

the V4 valve is normally closed, the hydraulic fluid is bled off to the tank and there is no

pressure build up in the hose that goes to the actuator. The fail-safe flow line valve, mounted on

the flowhead (not shown), is closed when the ESD is idle.

ESD arming

Opening the air supply causes air to simultaneously flow to the hydraulic pump and to the V5

reset valve. This causes the hydraulic pump to supply oil to the V4 valve. When V5 is pulled, air

pressure activates the V4 valve and hydraulic oil is sent to the actuator. At the same time V5 is

pulled, the V7 by-pass valve is pushed to pressurize the pneumatic circuit. Pushing on V7

causes air pressure to flow to V5, allowing V5 to remain open when its handle is released.

ESD armed

When the V7 by-pass valve is released (V5 remains open) air flows through the V9 velocity

check valve that supplies air to the ESD stations and pilots. In order to prevent a small leak in

any of the ESD station or pilot lines from causing the valve on the flow line to close, potentially

causing a well shut down, air flows continuously through a small orifice in V9. The small orifice

in V9 is always open to compensate for small leaks; but if an emergency is triggered, air can be

vented through the check valve in V9.

ESD triggered

In an emergency, a push button located on the ESD console (not shown) or on one of the remote

ESD stations (ESD1, ESD2, etc.) is manually activated, releasing air from the lines. This causes

V5 and V4 to close. The air pressure drop activates the quick exhaust valve which cuts off air

pressure to V5. (The purpose of the quick exhaust valve is to close V5 without bleeding off the

entire system.) The drop in air pressure also closes V4, stopping the flow of hydraulic oil to the

actuator and venting oil from the actuator to the outside. The de-pressurizing of this system

closes the valve on the flow line.

Hi/Lo-Pilot System

The pressure pilot system operates on the same pressure principles as the ESD stations. The hi-

and lo-pilots are connected to the ESD by an air line and are mounted on the flow line. The pilot

system can be comprised of a hi-pilot, a low-pilot, or a combination of a hi- and a lo-pilot. Each

pilot is basically made up of two components: a spring and a piston. The piston is used to detect

pressure changes in the flow line. The spring is used to set the expected flow line pressure.

The following paragraphs describe how the hi- and lo-pilots behave in a normal state and how

they function when a pilot responds to an emergency shut down.

Hi-Pilot Normal Operation

In normal operating mode, the hi-pilot expects the pressure in the flow line to remain at or below

a preset pressure value which is set by adjusting the spring force. In this mode, the air pressure

between the hi-pilot and the V4 interface valve is retained, allowing hydraulic pressure from the

pump to keep the flow line valve open.

Hi-Pilot Shut Down Operation

When the flow line pressure rises above the preset spring value, air is bled off at the pilot, the V4

interface valve is triggered, venting the hydraulic pressure from the actuator and closing the

valve on the flow line.

Lo-Pilot Normal Operation

In normal operating mode, the lo-pilot expects the pressure in the flow line to remain at or above

a preset pressure value that is set by adjusting the spring force. In this mode, the air pressure

between the lo-pilot and the V4 interface valve is retained, allowing hydraulic pressure from the

pump to keep the flow line valve open.

Lo-Pilot Shut Down Operation

When the flow line pressure falls below the preset spring value, air is bled off at the pilot, the V4

interface valve is triggered, venting the hydraulic pressure from the actuator and closing the

valve on the flow line.

Hi- and Lo-Pilot Combination

When both a hi- and a lo-pilot are mounted on the flow line, the pressure can be restricted within

a preset range. Air pressure flows from the lo- to the hi-pilot and is retained between the pilots

and the V4 interface valve, allowing hydraulic pressure from the pump to keep the flow line

valve open. If the pressure rises above the preset value, air is bled off at the hi-pilot and if the

pressure falls below the preset value, air is bled off at the lo-pilot. In either case, the V4 interface

valve is triggered, venting the hydraulic pressure from the actuator and closing the valve on the

flow line.

The following animation illustrates the different elements of the ESD system and demonstrates

automatic and manual operations. It includes an interactive simulator to reinforce your

understanding of this system.

Emergency Shut down System Multimedia

Objective: To progressively illustrate the elements and interactively demonstrate the automatic

and manual operation of the emergency shut down (ESD) system

Comment: The ESD is designed to control the hydraulically activated flow line valve on the

flowhead. It allows manual remote closure of this valve in case the well needs to be shut off in an

emergency. The closure of the flow line valve can also be initiated automatically with pressure

pilots installed on the flow line. This system also allows the reopening of the flow line valve

after closure. The animation will show how each special valve works by using generic valves to

concentrate on the function of each part. Manual and automatic sequences are covered. The

operation of the oil pump, spare air tank, etc. are not covered in this animation. Please note that

there is a mistake in the velocity check section of the animation. The needle shown is actually

static and adjusted only during a shop check.

Mac

Read me!

PC

Read me!

Compressed size: 4.9 MB, Expanded (noncompressed) size:9.0 MB

Equipment

The ESD consists of a pneumatic control console which consists of the various switches and

controls used to pressurize the pneumatic (air) and hydraulic (oil) circuits, a pump, an hydraulic

tank, and an air reservoir. The control console is mounted on a skid that has storage space for

the remote ESD stations and three hose reels. One hose is a high-pressure hose for a shut down

valve actuator, and the other two are low-pressure hoses for connecting to the ESD stations or

the hi/lo-pilots. The console has 4 air outlets that can either be connected to the remote stations

or the hi/lo-pilots.

Description

The Emergency Shutdown System (ESD) controls the flowline valve actuator and an additional

surface safety valve located upstream of the choke. Additional push-button shutdown stations

can be located, for example, at the steam exchanger or heater, separator, gauge tank and burner

pedestals.

The ESD system can be complemented by high- or low-pressure pilots or by high- or low-level

alarms. The pilots initiate well closure when the pressure rises above a high-level threshold

(choke plugged) or falls below a low-level threshold (flowline leakage).

The ESD-BB system consists of an ESD control console skid that includes a pump, hydraulic

tank, air reservoir and three hose reels. The first hose reel contains 20 m of high-pressure hose

for a shutdown valve actuator. The other two reels each contain 90 m of low-pressure hose for

connecting the push-button stations.

The ESD-BB actuator system is designed for use with any single-action fail-safe actuator,

provided required hydraulic pressure does not exceed 6000 psi.

Specifications


Assembly number P-579063

Project code ESD-BB

Working pressure 6000-psi

maximum actuator pressure


Standard accessories

High-pressure hose 1 reel containing 20 m of 10,000-psi WP hose

Low-pressure hose 2 reels, each containing 6 ¥ 15-m lengths of 240-psi WP hose

Push-pulls 12 x 3 Ž8 in. 300-psi WP

1 x 3 Ž8 in., 10,000-psi WP

ESD stations 4 each

Dimensions

Length 43.3 in. [1.10 m]

Width 39.3 in. [1.00 m]

Height 41.7 in. [1.06 m]


Options

High-low pilots See booklet M-075121

Extra high-pressure

hose

P-582666, 20-m high-pressure hose with push-pull for second

actuator

Safety

Because it improves safety, using an ESD system is recommended for all well test operations. When the well head pressure exceeds 3,000 psi or whenever H2S is present, an ESD must be used.

A minimum of two remote control stations shall be set up: one at the separator and one in an area away from all pressurized equipment. These control stations are necessary to ensure the well can be controlled from more than one place.

Be sure to open the air vessel inlet valve to ensure that the ESD is operational, even in the event of air supply failure. Energy stored in the vessel supplies enough air for about 10 closures.

Maintenance

For information about equipment maintenance, see the maintenance manuals for the ESD and the

pilots.

Summary


The principle function of the ESD. How the ESD is push-button activated from ESD stations at various locations, either inside or

outside of the surface testing setup. The function of the hi/lo-pressure pilots in automating the ESD system and improving its overall

reliability. How the parts that make up the ESD system respond when triggered by either a push-button or

a hi/lo-pressure pilot.

Self Test

1. Which valve(s) does the ESD activate? 2. What are the fluids used in the ESD system? 3. Is it possible to use an ESD when H2S is present in the well effluent? 4. How is the ESD activated? 5. Where are the push-button stations usually located? 6. How does a low-pressure pilot work? 7. What is the role of the air vessel?

D) STEAM EXCHANGER



Introduction

The steam exchanger is an optional piece of surface testing equipment that may be required,

depending on the characteristics of the well effluent, when a well is being tested. This training

page describes the purpose of the steam exchanger, shows where it's located in relationship to

other surface testing equipment, examines how the steam exchanger works, and describes its

main components.

A steam exchanger is used to raise the temperature of the well effluent for the following reasons:

Hydrate Prevention

Water is often present in the well effluent along with oil and gas. Under certain flow conditions,

the temperature of the well effluent can drop significantly. This temperature drop can cause the

particles of water and some of the light hydrocarbons in the gas to solidify. The accumulation of

solid particles can make the valves along the flow path inoperative. If these solid particles are

not eliminated or prevented from forming, they can eventually block the flow line.

Natural gas hydrates have the appearance of hard snow and are formed at temperatures above

the normal freezing point of water when certain hydrocarbons are dissolved in water under low

temperature and high pressure conditions. High velocities, pressure pulsations, and agitation

accelerate this phenomena. H2S and CO2 promote the formation of hydrates.

Viscosity Reduction

If the effluent has a high viscosity, then its ability to flow through the pipe is impaired. Because

viscosity is temperature-dependent, using a steam exchanger to raise the effluent temperature

decreases its viscosity.

Emulsion Breaking

Under certain conditions, the oil and water in the effluent are miscible, creating an emulsion

that will not separate unless the temperature of the effluent is raised.

Foam Reduction

For certain types of crude oil, reducing the flow rate pressure causes some gas bubbles to

become encased in a thin film of oil, instead of being liberated from the oil. This results in the

dispersion of foam or froth throughout the oil, creating what is known as foaming oil.

Foaming greatly reduces the flow rate capacity of oil and gas separators and makes it difficult to

accurately measure the oil flow rate. These problems, combined with the potential loss of oil

and gas because of improper separation, emphasize the need for special equipment and

procedures to handle foaming oil. Heat is one of the main methods used to eliminate or reduce

foaming.

Increased Burner Efficiency

Reducing the oil viscosity improves the atomization of oil at the burner head.

Objectives


Explain the operating principles of the steam exchanger. Draw a diagram of the steam exchanger circuits that the well effluent and the steam flow

through. Write down a list of the safety rules to be observed when operating the steam exchanger.

Upon completion of the practical exercises for the steam exchanger, you should be able to:

Identify all the components of the steam exchanger by visual inspection. Complete the steps required to prepare the steam exchanger to flow fluids through both coils. Write down the steps required to pressure test the coils, then pressure test both coils. Follow recommended safety procedures when operating a steam exchanger. Divert the flow to bypass the steam exchanger.


The steam exchanger is a steam vessel with two coils through which the well fluid passes. A

choke assembly between the coils allows the well to be controlled at the steam exchanger instead

of at the choke manifold. An inlet manifold with three gate valves controls fluid flow and

provides a way to bypass the coils and choke. To maintain a preset temperature, the steam

flowing into the vessel is regulated by an automatic control valve (ACV) on the steam inlet. A

steam trap is mounted on the stream outlet line.

The steam vessel is protected by a safety relief valve. A flange on the steam vessel is available to

connect either an additional safety relief valve or a bursting disc. The steam exchanger is

insulated on the outside with glass wool and is covered with an aluminium jacket. Steam is

supplied to the vessel by a steam generator (usually rented from a third-party company). The

steam allows fluids to be heated to higher temperatures than could be obtained with water.

The parts of the steam exchanger are illustrated in the "Steam Exchanger" diagram and are

described below:

Temperature controller system

A controller continuously monitors the difference in temperature between the well effluent

leaving the steam exchanger and the temperature set on the controller. To maintain a stable

fluid temperature, the temperature controller produces an output air signal that is function of

this difference. This air signal is transmitted to an ACV that regulates steam intake.

Steam trap

The steam trap is mounted on the steam condensate outlet line of the steam vessel. Its main

functions are:

Maintain a constant pressure inside the vessel in order to maintain the set temperature. The temperature of the steam is about 90o C during normal operation and rises to 170o C when the steam exchanger is working at full capacity.

Eliminate steam condensate without letting the steam escape. Condensate should be evacuated rapidly so the exchange surfaces inside the vessel remain completely surrounded by steam and water does not accumulate on the exchange surfaces. This reduces the heat exchange loss between the steam and the well effluent.

The "Steam Trap Operation" series of diagrams shows how the steam trap works:

Safety relief valve

The safety relief valve is located on top of the steam exchanger. When the steam pressure inside

the vessel rises above the working pressure (WP) of the vessel, the relief valve opens and bleeds

off the steam pressure, preventing the vessel from accidently bursting.

The outlet for the safety relief valve is connected to a vent line that's sized to handle the

steam flow plus the maximum flow rate of the effluent. This is a safety precaution that's

taken to ensure, in case the coil inside the vessel breaks, that the well effluent can be

liberated with the steam. Offshore the vent line goes overboard.

The safety relief valve incorporates a bellows seal that prevents steam from entering the

upper part of the valve that is exposed to the atmospheric pressure. The bellows covers an

area equal to the area of the valve seat, so the effect of any back pressure from the valve

outlet on the set pressure is eliminated. The set pressure is the pressure at which you want

the safety relief valve to open. The set pressure is adjusted by the force of a spring on a

sealing disc that is exposed to steam pressure.

Choke box

The choke box is designed to receive either a fixed or an adjustable choke. It is located between

the two coils in order to heat the fluid before it passes through the choke. When the fluid

arrives at the choke, it is preheated. This helps to prevent the formation of hydrates in the fluid;

or in the case of gas, it prevents freezing.

Equipment

The steam exchanger is available in 5000, 10,000, and 15,000 psi pressure ratings. The heating

capacity is expressed in Btu/hr (British thermal unit per hour). The wide range of steam

exchangers makes it possible to select a steam exchanger that can accommodate the required

well test without having to use equipment that is larger, more complicated, or more expensive

than the overall project requires.

STEAM HEAT

EXCHANGER

Description

The steam heat exchanger is used to raise the temperature of well effluent for hydrate prevention,

viscosity reduction and breakdown of emulsions.

The unit is skid mounted with a protective frame and consists of a steam vessel containing two

coils through which the well fluid passes. A choke assembly enables the well to be controlled at

the steam exchanger, rather than at the choke manifold, after the well fluid has passed through

the first coil section.

The working pressure of the coils is the same upstream and downstream of the choke.

An inlet manifold of three gate valves controls fluid flow and provides a bypass of coils and

choke.

The steam flow into the vessel is regulated by an automatic control valve on the steam inlet to

maintain a preset temperature. There is a steam trap on the steam outlet line.

The steam vessel is protected by a safety valve with a flange available for either an additional

safety valve or 6-in. bursting head.

The steam vessel is insulated with glass wool and is covered with an aluminum jacket.

Specifications


Project code STX-BBS STX-CCN STX-CCQ


Design codes DNV Drill "N," DOE SI 289, API 6A, TEMA R

NACE MR 01-75, ASME VIII Div 1, ANSI

B31-3

Coil temperature rating -20 to 350°F [-28 to 175°C]

Working pressure 4900 psi

[338 bar]

10,000 psi

[690 bar]

15,000 psi

[1036 bar]

Test pressure

Valves

Coils

10,000 psi

[690 bar]

7350 psi

[500 bar]

15,000 psi

[1035 bar]

15,000 psi

[1035 bar]

22,500 psi

[1380 bar]

22,500 psi

[1380 bar]

Nominal value ID 3 1/8 in. 3 1/16 in. 3 1/16 in.

Choke size 1 1/2 in. 2 in. 2 in.

Choke bean series D-58 D-72 ACME

Steam vessel

(230-psi working

pressure) 42 in. x 15 ft 42 in. x 15 ft 51 in. x 15 ft

Heating capacity 4.3 MMBtu/hr (4970 lbf/hr steam at 120 psi and

340°F)

Relief valve size 6 in. 6 in. 6 in.

API 6A CLASSIFICATIONS


level PSL2 PSL3 PSL3

Fluid classification DD (H2S) EE (H2S, CO2) EE (H2S, CO2)

Manifold temperature

classification P+U, -20 to 250°F [-28 to 121°C]

Connections

Inlet (WECO Union)

Outlet (WECO Union)

3-in. Fig. 1002

F

3-in. Fig. 1002

M

3-in. Fig. 1502

F

3-in. Fig. 1502

M

3-in. Fig. 2202

F

3-in. Fig. 2202

M

Steam supply 3-in. Fig 206 inlet, 2-in. Fig. 206 outlet

DIMENSIONS

Height

Without relief valve

With relief valve

101 in. [2.62 m]

137 in. [3.49 m]

101 in. [2.62 m]

137 in. [3.49 m]

101 in. [2.62 m]

136 in. [3.47 m]

Width 92 in. [2.34 m] 92 in. [2.34 m] 92 in. [2.34 m]

Length 258 in. [6.55 m] 258 in. [6.55 m] 258 in. [6.55 m]

Weight

Empty

Full of water

22,075 lbm

35,320 lbm

22,625 lbm

35,870 lbm

23,180 lbm

36,420 lbm


Options

6-in. bursting head M-839101

6-in. rupture disc, 250

psi M-839102

6-in. safety valve M-817489

This drawing shows an example of a steam heat exchanger. Specifications are provided for three

different models: STX-BBS, CCN, and CCQ.

Steam Exchanger Selection Guidelines

The principal criteria for selecting a steam exchanger are:

Pressure rating requirements Heating capacity Safety regulations (an indirect heater is not accepted in some locations)

Note: In some countries, a steam exchanger must be used because safety regulations

prohibit the use of indirect heaters. The steam exchanger is intrinsically safe in terms of

fire risk because it does not use a flame to heat the well effluent.

Additional considerations are:

A steam generator is needed for the steam exchanger. Air supply for the temperature controller of the steam exchanger.

Safety

The following is a list of key safety considerations for steam exchangers:

Do not touch the steam vessel with bare hands when the steam exchanger is working. After the job, flush the coils thoroughly with soft water and fill them with corrosion inhibitor

before storing the steam exchanger. Never flow the well through the coils if a choke is not installed. Sand particles or corrosive fluids

can erode the threads in the choke box. Do not use the adjustable choke to stop the flow, you can break the stem tip. Do not use the gate valves on the steam exchanger as chokes. Do not transport the steam exchanger when it is full of condensate water. The frame cannot

support this extra weight.

Before starting the steam exchanger, verify that the inlet and outlet valves for the coils are open. If the coils are filled with liquid and the valves are closed, the thermal expansion that results can generate enough pressure to burst the coils.

Maintenance

For information about the preparation and functional checks for the steam exchanger, see the

recommended steps in the "Field Operating Handbook (FOH) for Surface Well Testing."

For information about equipment maintenance, see the maintenance manuals for the steam

exchanger.

Summary


The purpose of a steam exchanger and five reasons to use it. The general description of the steam exchanger. The function of the parts of the steam exchanger. Explained why the steam exchanger is intrinsically safer than the indirect heater.

Self Test

1. Why is it sometimes necessary to heat up the well effluent? 2. What is the purpose of the choke assembly? 3. Why is the steam exchanger safer than the indirect heater? 4. How is the steam kept inside the vessel? 5. What precaution should be taken before starting the steam exchanger? 6. How is the ACV controlled that is mounted on the steam inlet line?

E) INDIRECT HEATER

Introduction

The indirect heater is an optional piece of surface testing equipment that may be required,

depending on the characteristics of the well effluent, when a well is being tested. This training

page describes the purpose of the indirect heater, shows where it's located in relationship to other

surface testing equipment, examines how the indirect heater works, and describes its main

components.

An indirect heater is used to raise the temperature of the well effluent for the following reasons:

Hydrate Prevention

Water is often present in the well effluent along with oil and gas. Under certain flow conditions,

the temperature of the well effluent can drop significantly. This temperature drop can cause the

particles of water and some of the light hydrocarbons in the gas to solidify. The accumulation of

solid particles can make the valves along the flow path inoperative. If these solid particles are

not eliminated or prevented from forming, they can eventually block the flow line.

Natural gas hydrates have the appearance of hard snow and are formed at temperatures above

the normal freezing point of water when certain hydrocarbons are dissolved in water under low

temperature and high pressure conditions. High velocities, pressure pulsations, and agitation

accelerate this phenomena. H2S and CO2 promote the formation of hydrates.

Viscosity Reduction

If the effluent has a high viscosity, then its ability to flow through the pipe is impaired. Because

viscosity is temperature-dependent, using an indirect heater to raise the effluent temperature

decreases its viscosity.

Emulsion Breaking

Under certain conditions the oil and water in the effluent are miscible, creating an emulsion that

will not separate unless the temperature of the effluent is raised.

Foam Reduction

For certain types of crude oil, reducing the flow rate pressure causes some gas bubbles to

become encased in a thin film of oil, instead of being liberated from the oil. This results in the

dispersion of foam or froth throughout the oil, creating what is known as foaming oil.

Foaming greatly reduces the flow rate capacity of oil and gas separators and makes it difficult to

accurately measure the oil flow rate. These problems, combined with the potential loss of oil

and gas because of improper separation, emphasize the need for special equipment and

procedures to handle foaming oil. Heat is one of the main methods used to eliminate or reduce

foaming.

Increased Burner Efficiency

Reducing the oil viscosity improves the atomization of oil at the burner head.

Objectives


Explain the operating principles of the indirect heater. Explain how the temperature regulator for the indirect heater works. Explain how the CMA flameout shutdown system for the indirect heater works. Draw a diagram of the indirect heater circuits that the well effluent, propane, compressed air,

water, mercury, and diesel fluids flow through. Write down a list of the safety rules to be observed when operating the indirect heater.

Upon completion of the practical exercises for the indirect heater, you should be able to:

Identify all the components of the indirect heater by visual inspection.

Complete the steps required to prepare the indirect heater to flow fluids through both coils. Write down the steps required to pressure test the coils, then pressure test both coils. Follow recommended safety procedures when operating an indirect heater. Divert the flow to bypass the indirect heater.


The indirect heater shown in the "Indirect Heater" diagram consists of a nonpressurized water

vessel that contains two coils through which well fluid passes. The well fluid in the coils is

indirectly heated by the water, which is heated by a flame from a diesel burner. The diesel burner

is contained inside a firetube. This system causes the water to conduct heat to the coiled tubes,

warming up the effluent. There is no direct contact between the tubes carrying the fluid to be

heated and the flame that's used as a heat source. This system is intrinsically safer than a direct

heater in which the tubes containing the well effluent are in direct contact with the flame. A

common example of a direct heater is a domestic boiler.

After the well fluid passes through the first coil section, a choke assembly between the coils

allows the well to be controlled at the indirect heater instead of at the choke manifold. An inlet

manifold with three gate valves controls fluid flow and provides a way to bypass the coils and

choke. To maintain a preset temperature, the diesel flame is regulated by an automatic control

valve (ACV). A shut down valve cuts the diesel supply if the pilot light is extinguished. The

internal design of the vessel is such that convection currents prevent any localized heating of the

water because boiling would impair the performance and life of the indirect heater.

The parts of the indirect heater are shown in the "Indirect Heater" diagram and are described

below. Click on the graphic or scroll down for detailed information on each component.

Firetube

The firetube is shaped like a "U" tube. Combustion occurs on one side of the "U" and the

chimney is located on the other side. The firetube is mounted on a flange and inserted inside

the vessel. This configuration allows the firetube to be easily removed for repair or replacement.

It has brackets on the bottom or on the side (or both) to prevent it from touching the vessel.

Because the tube is immersed in the water, its temperature is approximately the same as the

water, even though the combustion temperature inside the tube may be greater than 165o C

(300o F).

If the tube touches the vessel, a hot spot will develop that can distort or melt the tube and the

vessel. To prevent this from occurring, a liner is located inside the firetube in the combustion

area. This protective device, made of a heat resistant metal, prevents the flame from striking the

tube wall, which could cause the tube to overheat and fail. In the event the fire does strike the

liner, it will eventually melt and have to be replaced. If the damaged liner is promptly replaced,

the fire tube will not be damaged.

Diesel burner

The burner of an indirect heater, located at the inlet of the firetube, is designed to produce a

long, narrow flame pattern so the flame will not touch the walls. It is centered in the firetube. It

is made up of a mixing chamber where air under pressure sprays the diesel into tiny droplets

before it burns. The amount of air passing through the flame arrestor (necessary for the diesel

combustion) can be adjusted with a flap. When the proper volume of diesel and volume of air

are mixed in the firetube, a blue flame results. The diesel is sent to the burner with an air driven

pump that typically sits on top of a diesel drum. The flow rate of the diesel supplied to the

burner is controlled by adjusting an air pressure regulator on the pumping unit.

Pilot burner

The pilot burner is similar to the main burner, but it is much smaller. It does not require

compressed air because it burns propane gas. To maintain a constant flame pattern, a pressure

regulator is fitted on the propane line to the pilot burner. A view glass allows the status (on/off)

of the pilot light to be checked.

Air ring

Located inside the firetube, the air ring sweeps out the firetube with fresh compressed air

before the pilot light is ignited. If any gas vapors are present inside the firetube when the pilot

light is ignited an accidental explosion could occur.

Stack

The stack or chimney is a piece of pipe that fits over the outlet end of the firetube. The chimney

dissipates the unused heat to the atmosphere. Its height varies from 2 to 6 meters, depending

on the length of pipe required to properly vent the smoke in the area where the heat exchanger

is located. It is equipped with a spark arrestor to prevent sparks from being released to the

atmosphere through the chimney.

Flame ignition system

This system consists of a high voltage coil and a spark plug to light the pilot. A push button is

used to create the spark that lights the pilot.

Temperature control system

A temperature controller senses the temperature of the water bath and signals the diesel valve

to open or close as required to hold the water temperature at the set point on the controller.

The temperature control system consists of a thermostatic valve and a temperature bulb. The

thermostatic valve is designed to maintain the temperature of the water bath at the desired

value. A temperature bulb immersed in the water activates the valve. When the burner is off,

the temperature bulb is cold and the valve is open. When the burner is lit, the water bath

temperature heats the bulb. The fluid inside the bulb and the valve chamber expands, exerting a

force on the valve stem and the spring that's proportional to the temperature. At a certain

temperature, the force of the expanded fluid is higher than the force of the return spring so the

valve closes, cutting off the diesel supply. This extinguishes the flame in the diesel burner. When

the burner flame goes out, the water bath and the bulb cool down. This heat loss causes the

fluid in the expansion chamber to contract and the valve opens by means of the return spring,

restoring the diesel supply to burner.

The temperature controller is set for a delayed response of the diesel valve. The delayed

response setup allows the diesel burner to burn continuously, and the intensity of the flame

varies in response to temperature changes. In contrast, when the temperature controller is set

for a quick response, the diesel burner burns at full rate when the diesel valve is fully open and

is completely extinguished when the diesel valve is fully closed. This on/off action increases the

likelihood of firetube burnout at full-rate. Consequently, the delayed response setup is desirable

because it stabilizes the firing rate and avoids full firing even for short periods.

The following paragraphs describe how the diesel valve's delayed response works.

If the temperature of the water begins to fall, the temperature controller reacts by opening the

diesel valve more, increasing the intensity of the flame in the diesel burner. It takes a few

minutes to heat the volume of water in the vessel to the set temperature. When the set

temperature is reached, the diesel valve does not return to its original position immediately.

This delay allows the water temperature to rise slightly above the set point.

If the temperature of the water begins to rise, the temperature controller reacts by closing the

diesel valve more, decreasing the intensity of the flame in the diesel burner. It takes a few

minutes to cool down the volume of water in the vessel to the set temperature. When the set

temperature is reached, the diesel valve does not return to its original position immediately.

This delay allows the water temperature to fall slightly below the set point.

The drawback to the delayed response system is that the temperature is not perfectly

constant. As described in the previous paragraphs, it cycles around the set temperature.

This variation around the set temperature can affect pressure readings at the separator.

Flameout shutdown

This safety system, known as the CMA control box, consists basically of a three-way switch that's

operated by the expansion of mercury when it is exposed to heat. The purpose of this system is

to shut off the diesel flow to the burner when the propane gas pilot goes out.

When the heater is started, a manual knob opens the propane inlet orifice, causing propane gas

to flow to the ACV and to the pilot simultaneously. This opens the ACV and allows the pilot to be

lit. Once the pilot is lit, the mercury in the sensor and capillary tube expands, pushing down the

stem inside the control box. In this position, the stem causes the propane inlet orifice to remain

open even when the manual reset knob is released. If the pilot flame goes out, the mercury will

cool down and contract, releasing the pressure on the stem and causing the stem to retract.

Under the action of the return spring, the propane inlet will close. Because the ACV is no longer

supplied with propane, it will close by means of the return spring. Consequently, there is no

danger of diesel being supplied to the main burner when the pilot is not lit.

Flame arrestor

The flame arrestor is mounted on the inside of the door that permits access to the burner. If a

flame tries to move to the outside of the tube, the flame arrestor will stop the flame. The flame

arrestor is made of a thin aluminium sheet wound in a spiral coil. The flame arrestor is also

designed to let air from the outside into the firetube, because the air is necessary for diesel

combustion. If the indirect heater was not equipped with a flame arrestor, a gas leak or the

presence of a flammable liquid outside the heater could be ignited by the flame and cause a

major fire or explosion.

Spark arrestor

Located on top of the chimney, the spark arrestor is made of a wire mesh. Sparks from the

diesel burner flame that travel up the chimney are stopped by the spark arrestor before they

can escape to the atmosphere.

Choke box

The choke box is designed to receive either a fixed or an adjustable choke. It is located between

the two coils in order to heat the fluid before it passes through the choke. When the fluid

arrives at the choke, it is preheated. This helps to prevent the formation of hydrates in the fluid;

or in the case of gas, it prevents freezing.

Equipment

INDIRECT HEATER

(IHT-BAF)

Description

The indirect heater is used to raise the temperature of well effluent for hydrate prevention,

viscosity reduction and breakdown of emulsions.

The unit is skid mounted with a protective frame and consists of a water vessel containing two

coils through which the well fluid passes. The water vessel is heated by a diesel burner and

remains at atmospheric pressure.

A choke assembly enables the well to be controlled at the heater, rather than at the choke

manifold, after the well fluid has passed through the first coil section.

The working pressure of the coils is the same upstream and downstream of the choke.

An inlet manifold of three gate valves controls fluid flow and provides a bypass of coils and

choke.

The diesel flame is regulated by an automatic control valve to maintain a preset temperature. A

shutdown valve cuts the diesel supply if the pilot light is extinguished.

Specifications


Project code IHT-BAF

Design codes API 6A, API 12K, NACE MR 01-75,

ANSI B3 1-3

Coil temperature rating -20 to 350°F [-28 to 175°C]


Test pressure

Valves

Coils

10,000 psi [690 bar]

7350 psi [507 bar]

Coil description 4-in. XXH by 4-in. XXH

Nominal valve ID 3 1/8 in.

Choke size 1 1/2 in.

Choke bean series D-68

Heating vessel 81 in. x 12 ft (2.3-psi working pressure)

Heating capacity 2 MMBtu/hr

Diesel supply required 120 liter/hr at 70 psi [5 bar]

Air supply required 25 scf/min at 70 psi [5 bar]

Safety devices

Diesel shutdown valve, activated by pilot

light stoppage;

flame arrestor on burner air inlet


Product specification level PSL2


Manifold temperature

classification P+U, -20 to 250°F [-28 to 121°C]

CONNECTIONS



Diesel inlet 1/4-in. NPT

DIMENSIONS

Height

Without chimney

With chimney

104 in. [2.64 m]

156 in. [3.98 m]

Width 88 in. [2.25 m]

Length 230 in. [5.85 m]

Weight

Empty

With pipe work set

25,250 lbm [11,450 kg]

27,440 lbm [12,450 kg]


Options

Air-driven diesel fuel pump

(PMP-C) M-801364

Positive choke bonnet

assembly M-805110

Protective panels for frame M-804203

The indirect heaters are available in 3000 and 5000 psi pressure ratings. The 3000 psi version is

heli-portable. The heating capacity expressed in Btu/hr (British thermal unit per hour) is also a

main characteristic of the indirect heaters. The wide range of indirect heaters makes it possible to

select an indirect heater that can accommodate the required well test without having to use

equipment that is larger, more complicated, or more expensive than the overall project requires.

This drawing shows an example of an indirect heater. Specifications are provided for this

drawing.

Indirect Heater Selection Guidelines

The principal criteria for selecting an indirect heater are:

Pressure rating requirements Heating capacity Safety regulations (an indirect heater is not accepted in some locations) Available space (an indirect heater must be located in a safe area)

Additional considerations are:

Air supply for the diesel burner and sweep system of the indirect heater. The indirect heater needs electricity for the ignition of the pilot light. The indirect heater needs diesel supply and a diesel pump for the burner. The indirect heater needs propane to supply the pilot light. Water and corrosion inhibitors are needed to fill up the vessel of the indirect heater.

Safety

The following is a list of key safety considerations for indirect heaters:

A perfect understanding of the diesel, propane, and air circuits is a prerequisite to a successful and safe job.

Before starting or restarting the indirect heater, sweep out the firetube with fresh compressed air. In the event that gas or diesel vapors are present, this practice can avoid an accidental explosion.

Do not touch the water vessel with bare hands when the indirect heater is working Verify that the spark arrestor is installed on the chimney. After the job, flush the coils thoroughly with soft water and fill them with corrosion inhibitor

before storage.

Never flow the well through the coils if a choke is not installed. Sand particles or corrosive fluids can erode the threads in the choke box.

Do not use the adjustable choke to stop the flow, you can break the stem tip. Do not use the gate valves on the indirect heater as chokes. Do not transport the indirect heater when it is full of water. The frame cannot support this extra

weight. Before starting the indirect heater, verify that the inlet and outlet valves of the coils are open. If

the coils are filled with liquid and the valves closed, the thermal expansion that results can generate enough pressure to burst the coils.

Maintenance

For information about the preparation and functional checks for the indirect heater, see the

recommended steps in the "Field Operating Handbook (FOH) for Surface Well Testing."

For information about equipment maintenance, see the maintenance manuals for the indirect

heater.

Summary


The purpose of the indirect heater and five reasons to use it. The general description of the indirect heater. The function of the parts of the indirect heater. How the temperature regulation and flameout systems work.

Self Test

1. List five reasons to raise the temperature of the well effluent. 2. Why is this heater called an indirect heater? 3. How is the temperature of the indirect heater regulated? 4. Briefly explain how the flameout shutdown system works. 5. What is the important thing to do prior starting or restarting the indirect heater?

E) SEPARATOR

Introduction

The "Surface Test Equipment" figure shows where the separator is located in relation to other

surface testing equipment. The separator is comprised of a pressurized vessel where fluids are

separated and a piping system that carries separated fluids out of the vessel. Its principle function

is to separate the well effluent leaving the choke manifold (or heat exchanger) into oil, gas, and

water components before sending the gas to the gas flare and the oil to either the tank or the oil

burner. Other important separator functions include the capability to meter effluent components

and take pressurized oil and gas samples.

Separators are classified by their shape and by the fluids they separate. They are either

horizontal, vertical, or spherical in shape. Shapes are further classified into two-phase

(gas/liquid) and three-phase (oil/water/gas) separators. The "Types of Separators" diagram shows

the basic types available. When testing a well, Schlumberger typically uses only three-phase

horizontal separators.

The following list summarizes a few of the advantages and disadvantages of the different

separator shapes:

Horizontal separators are normally more efficient at handling large amounts of gas. Horizontal separators are the most economical for normal oil-gas separation, particularly where

there may be problems with emulsions, foam, or high gas-oil ratios.

A vertical separator takes up less space than a horizontal separator with the same capacity. On a vertical separator, some of the controls may be difficult to access without ladders or access

platforms. Spherical separators are the most efficient for containing pressure; however, they are not

widely used because of their limited liquid surge capability and because they are difficult to fabricate.

Objectives


Explain the purpose of the separator. List the components of the separator and describe their functions. Explain how to adjust the retention time for the separator. Explain why the separator should be run at a constant pressure and how to control this

pressure. Describe the various types of separators and list their specifications.

Upon completion of the practical exercises for the Separator, you should be able to:

Perform a FIT and TRIM on a separator. Read the gas flow recorder. Read the oil flow recorders. Direct the flow into the separator. Bypass the flow from the separator. Adjust the pressure in the separator. Adjust the oil level in the separator. Perform shrinkage measurements using the shrinkage tester.


The operating principles for the separator are covered in the following topics:

Separation Processes Pressure and Level Controllers Safety Devices Metering Devices Piping Systems

Separation Processes

Separators rely on these processes to separate liquid (oil and water) from gas:

gravity and the difference in densities between oil, gas, and water. mechanical devices in the separator that are used to improve the separation process. altering the pressure and gas-liquid interface to further optimize separation.

Gravity and Density

In the separator, oil, gas, and water will naturally separate due to the effects of gravity and the

difference in density between effluent components. The denser effluent particles fall to the

bottom and the lighter particles rise to the top. Gas rises and liquid falls in the separator. The

separator improves this natural separation process by retaining the fluid long enough to slow

down its motion, allowing separation to occur.

About 95% of the liquid-gas separation inside the separator happens instantly. The relative

densities of gas and liquid (oil and water) are typically in the ratio of 1 to 20 so their separation is

quick, usually taking only a few seconds. However, some liquid will remain in the gas in the

form of a fine mist. This liquid must be separated from the gas with the aid of mechanical

devices for separation to be complete. The relative density of oil to water is typically in the ratio

of .75 to 1, so separation is a bit longer: one or two minutes.

Mechanical Separation Devices

To obtain good separation, speed up the separation process, and minimize retention time, the

separator is equipped with mechanical devices. The function of these mechanical devices is

explained here so you can understand the role they play in the separation process.

Deflector Plate

This plate is located in front of the inlet. It causes a rapid change in the

direction and velocity of the fluids, forcing the liquids to fall to the bottom

of the vessel. The deflector plate is responsible for the initial gross separation of liquid and gas.

Coalescing Plates

These plates are arranged longitudinally in an inverted V-shape in the

upper part of the separator. The liquid droplets in the gas hit the plates

and stick to them. As more gas passes through the plates, more droplets

coalesce to form bigger drops that fall to the bottom of the vessel.

Foam Breaker

This piece of equipment is made of wire mesh, like the mist extractor. It prevents oil particles in

the foam (comprised of oil and gas) from passing through the separator and being carried away

with the gas.

Mist Extractor

This piece of equipment is composed of a mass of

wire netting. Before leaving the separator, the gas

stream passes through the mist extractor, causing the

tiny oil droplets remaining in the gas to fall down.

Weir Plate

This plate, located at the bottom of the vessel, divides the separator into two compartments: oil

and water. Provided that the water level is controlled, it only permits oil to overflow into the oil

compartment.

Vortex Breakers

These breakers are located on the oil and water outlets.

Their function is to break the swirling (vortex) effect

that can occur when oil and water exit the separator

from their respective outlets. The vortex breakers

prevent any gas from being sucked away with the

liquids.

Pressure and Gas-Liquid Interface

To optimize separation, there are three main parameters that can be controlled:

the pressure inside the separator the level of the gas-liquid interface the temperature inside the separator

The goal is to achieve the best separation possible for a given effluent. Because variations in

these parameters can affect separation conditions, it's important to keep these parameters as

constant and stable as possible. Although the temperature inside the separator is almost equal to

the well effluent temperature and cannot be controlled (unless a heat exchanger is connected

upstream of the separator), the pressure and gas-liquid interface can be controlled to optimize oil

and gas recovery.

The "Separation Problems" table shows two examples of how the pressure, gas-liquid interface,

and temperature can be used to control separation problems.

Separation Problems

Problem Causes Action

Liquid carryover

High flow rate

High liquid level

Low operating pressure

Decrease flow rate

Lower oil/gas interface

Raise operating pressure or decrease flow rate

Wave action in separator

Foaming

Reduce sensitivity of oil level controller

Increase pressure

Poor oil-gas separation

High viscosity

High separator pressure

Heat well effluent

Increase retention time

Reduce pressure

Separation Processes

Pressure and Level Controllers

This topic covers the controller systems and their associated equipment. The gas pressure

controller and the oil and water level controllers maintain constant separation conditions inside

the tank. To adjust the separator pressure and the water and oil flow rates, all the controllers use

automatic control valves (ACVs). The compressed air used to operate the controllers is filtered

through an air scrubber. The air pressure is reduced by using pressure regulators mounted

upstream of the controllers. Visual level indicators, called sight glasses, are used to monitor the

oil-gas and oil-water interfaces inside the separator.

Gas Pressure Controller

The internal separator pressure is provided by the gas that flows into the separator. The fluid

inflow varies depending on the flowing conditions of the well. To maintain a constant pressure in

the separator, the fluid outflow must be adjusted so it's as close as possible to the fluid inflow.

Simple Gas Pressure Controller

The most common method of controlling pressure is with a pressure controller that uses a control

valve to automatically react to any variation in separator pressure. When the pressure drops, the

controller closes the valve and when the pressure rises, the controller opens the valve. Once the

separator operating pressure is manually set at the pressure controller, the pressure in the vessel

is maintained close to the selected value.

For safety purposes, this control valve is normally open. If for any reason the air pressure supply

to the valve is cut, the vessel will not be over pressurized.

The separator pressure is applied directly to the Bourdon tube inside the pressure controller as

shown in the "Gas Pressure Controller" figure. A change in the separator pressure deforms the

Bourdon tube. This deformation moves the flapper covering the nozzle away from or closer to

the nozzle, causing it to leak air. The air leak is used by the pressure controller to open or close

the control valve that regulates the pressure in the separator.

Complex Gas Pressure Controller

The "Gas Pressure Controller" figure above shows a simple model of a gas pressure controller. In

this simple system, the valve is either wide open or closed, causing the separator pressure to

oscillate between a minimum and maximum pressure value.

The actual gas pressure controller mounted on the separator is more complex. In contrast to the

simple model, the actual gas pressure controller allows the desired working pressure to be set and

utilizes proportional band control to adjust the valve stroke, ensuring smooth regulation of the

separator pressure.

For the complex system shown in the "Gas Pressure Controller - Proportional Action" diagram,

the desired pressure is set by adjusting the set point lever. Adjusting this lever moves the nozzle

either closer or farther away from the flapper to establish the set point pressure. Pressure from

the separator is applied directly to the Bourdon tube. The "Gas Pressure Controller - Proportional

Action" diagram shows the gas pressure control system in a state of equilibrium with the

separator pressure stable.

The following lists describe what happens to the system shown in the "Gas Pressure Controller -

Proportional Action" diagram when the separator pressure rises and falls.

When the separator pressure decreases, the set pressure is maintained by

The Bourdon tube moves the flapper toward the nozzle, closing the gap between the nozzle and the flapper.

Because chamber A is continuously supplied with air through orifice B, the reduction in the size of the air passage between the nozzle and the flapper causes the air pressure in chamber A of the relay to build up.

The pressure build up in chamber A pushes diaphragms C and D upward, causing supply valve E to open.

Air supply pressure enters chamber F and flows to the automatic control valve (ACV), causing it to throttle closer to its seat and reducing the flow of gas from separator thereby increasing its pressure.

Pressure in chamber F increases until diaphragms C and D are pushed back to their original positions, causing valve E to close and returning the system to a state of equilibrium.

At the same time that air flows to the ACV, it also flows through the proportional band valve to the bellows G. This air pressure causes the flapper to move away from the nozzle which stops the build up of pressure in chamber A and restores the system to a state of equilibrium.

As a result, the pressure on the ACV valve is increased (causing it to throttle closer to its

seat) and the separator pressure is restored to its set pressure.

When the separator pressure increases, the set pressure is maintained by

The Bourdon tube moves the flapper away from the nozzle, widening the gap between the nozzle and the flapper.

This causes the air pressure in chamber A of the relay to decrease. The pressure drop in chamber A and the action of the spring H causes diaphragms C and D to

move down. Air from the ACV starts to bleed off to the atmosphere through chamber I. This reduction in

pressure causes the ACV valve to open under the action of its spring.

At the same time that air flows from the ACV to the atmosphere, the air pressure in bellows G decreases, causing the flapper to move closer to the nozzle. This action will cause the pressure in chamber A to increase enough to close the passage between chambers F and I.

As a result, the pressure on the ACV is decreased (causing it to throttle away from its

seat) and the separator pressure is restored to its set pressure.

Proportional Band Valve

As shown in the "Gas Pressure Controller - Proportional Action" diagram, the pressure going

from relay chamber F to the ACV also goes to the proportional band three-way valve. The orifice

inlet for this valve is adjustable. This allows the amount of air pressure sent to bellows G (the

proportional band bellows) to vary. This variation changes the clearance between the flapper and

nozzle.

The proportional band is independent of the set point pressure, but dependent on the Bourdon

tube pressure rating. The proportional band setting is expressed as a percentage, based on the

Bourdon tube pressure rating, as described in the following examples. This percentage can vary

between 0 and 100%. For example, when the proportional band for the Fisher 4150 pressure

controller (shown in the "Gas Pressure Controller - Proportional Action" diagram) is fully closed,

it corresponds to a proportional band setting of approximately 3%.

The following examples show how a narrow (5%) and a wide setting (50%) of the proportional

band changes how the system reacts to a variation in pressure.

The pressure controller is equipped with a Bourdon tube with a pressure rating of 1000 psi. The set point for the separator pressure is 400 psi.

If the proportional band is set at 50% of the Bourdon tube rating of 1000 psi, this means that the

ACV will be fully closed when the separator pressure reaches 150 psi and fully open when the

separator pressure reaches 650 psi. At this wide setting, the system is not very sensitive to small

pressure variations. It will take a large pressure variation of 250 psi on either side of the

separator set point of 400 psi to either close or open the valve.

50% of 1000 psi = 500 psi

500 psi / 2 = 250 psi

400 + 250 = 650 psi

400 - 250 = 150 psi

In contrast, if the proportional band is set at 5% of the Bourdon tube rating of 1000 psi, the ACV

will be fully closed when the separator pressure reaches 375 psi and fully open when the

separator pressure reaches 425 psi. At this narrow setting, the system is sensitive to small

pressure variations. The system will either close or open the valve for a relatively small pressure

variation of 25 psi on either side of the separator set point of 400 psi.

5% of 1000 psi = 50 psi

50 psi / 2 = 25 psi

400 + 25 = 425 psi

400 - 25 = 375 psi

The following animation of a gas pressure controller demonstrates the operation of the gas ACV

and its controller. The effect of the proportional band valve on the ACV will also be shown.

Gas Automatic Control Valve Multimedia

Objective: To describe the operation of the valve and controller

To demonstrate the effects of the proportional band valve

Comment: The gas pressure controller and the oil and water level controllers maintain constant

separation conditions inside the tank. To adjust the separator pressure and the water and oil flow

rates, all the controllers use automatic control valves (ACV), the gas automatic control valve

(GACV) maintains the constant gas pressure.

The animation demonstrates how GACV components react to pressure setting changes and how

the proportional band valve adjusts the hysteresis.

Steady state GACV interaction will be covered in the next version of this animation.

For related topics, see the Liquid Control Valve and the Gas Flow Recorder animations.

Mac

Read me!

PC

Read me!

Compressed size: 5.5 MB, Expanded (noncompressed) size: 8.9 MB

Hints for Setting the Separator Pressure

When setting the separator pressure at the gas pressure controller, consider the following points:

The pressure rating of the safety relief valve in relation to the separator's maximum working pressure.

The critical flow conditions at the choke manifold. The minimum pressure needed to run the oil out of the separator to either a tank or a burner or

to run the oil and water meters.

Oil Level Controller

The level of the liquid-gas interface inside the separator should be kept constant to maintain

steady separation conditions. A variation in this level changes the volume of gas and liquid in the

separator, which in turn affects the speed and the retention time of the two fluids. The initial set

point for the liquid-gas level depends on the gas-oil ratio (GOR) of the well effluent.

If the GOR is high, more volume in the separator needs to be reserved for gas so a low oil level is required.

If the GOR is low, more volume in the separator needs to be reserved for the oil, so a high oil level is required.

To cover different GORs, from the oil level controller, the oil level can be adjusted between two

values: plus or minus 6 in. of the center line of the separator. As a guideline, the level is initially

fixed at the center line and further level adjustments are made based on the GOR.

Simple Oil Level Controller

Oil level controllers commonly employ a plunger attached to a controller to

open or close a control valve that regulates the oil level. This controller

actuates one of the two regulation valves on the oil outlet: a large and a

small diameter valve fitted in parallel. This system permits regulation of very

low to very high oil flow rates, limited only by the maximum capacity of the

separator.

When liquid in the separator rises, the plunger moves up causing the

torque tube to twist slightly to the right. a rod welded inside the torque

tube transmits the rotation of the torque tube to the flapper, causing it to

move closer to the nozzle that opens the automatic control valve

(ACV). Similarly, when the liquid in the separator falls, the plunger

moves down. The weight of the plunger causes the torque tube to twist

slightly to the left. The rod transmits the torque tube rotation to the

flapper, causing it to move away from the nozzle, closing the ACV.

Another way to understand how the torque tube system works is to

compare it to a spring. The force on the spring is replaced by the torque

on the tube and the linear displacement of the spring is replaced by the

angular displacement of the tube.

When the oil level changes, according to the principle of Archimedes, the plunger is buoyed up by a force equal to the weight of the displaced fluid as shown in the "Oil Level Controller" and "Torque Tube" figures. The movement of the plunger is converted, through a torque tube assembly, causing the flapper to move away from or closer to the nozzle. In turn, the air leak from the nozzle opens or closes the control valve on the separator oil outlet. For safety purposes, the control valves on the oil outlet are normally closed. If for any reason the air pressure supply to these valves is cut, this problem should be detected fast enough to prevent oil from backing up into the separator. Oil buildup in the separator can cause oil to outflow into the gas

line where it eventually reaches the flare and pollutes the environment. Conversely, if the control valves on the oil outlet were open, oil could build up in the tank, causing similar problems.

Complex Oil Level Controller

The "Oil Level Controller" figure above shows a simple model of an oil

level controller. In this simple system, the valve is either wide open or

closed, causing the separator oil level to constantly fluctuate between a

minimum and a maximum level.

The actual oil level controller mounted on the separator is more

complex. In contrast to the simple model, the actual oil level controller

allows the desired oil level to be set and utilizes a proportional band

control to adjust the valve stroke, ensuring smooth regulation of the

separator oil level.

For the complex system shown in the "Oil Level Controller - Proportional Action" diagram, the

desired liquid level is set by adjusting the set point lever. Adjusting this lever moves the nozzle,

mounted on the Bourdon tube, closer or farther away from the flapper. This set point lever allows

the desired level of liquid to be set (providing that the oil level is between the top and the bottom

of the plunger). The diagram shows the oil level controller in a state of equilibrium: the oil level

is set in the middle of the plunger and the inlet flow is equal to the outlet flow.

The following lists describe what happens to the system shown in the "Oil Level Controller -

Proportional Action" diagram when the inlet flow is greater than and less than the outlet flow.

When the inlet flow is greater than the outlet flow, the level of oil in the separator increases:

The buoyant force of the liquid increases, lifting the plunger up. The flapper, connected to the plunger by the torque tube, moves toward the nozzle.

This displacement of the plunger moves the flapper up, closing the gap between the flapper and the nozzle and reducing the air passage. Because chamber A is constantly supplied with air through orifice B, the reduction in this air passage increases the pressure in chamber A.

The pressure build up in chamber A pushes diaphragms C and D down, opening the supply valve E.

Air supply pressure enters chamber F and flows to the automatic control valve (ACV) causing it to throttle away from its seat (opening the ACV). This action increases the oil outflow and causes the oil level to fall.

At the same time that the air flows to the ACV, it also flows through the proportional band valve to the Bourdon tube. This air pressure causes the nozzle on the Bourdon tube to move away from the flapper. This action stops the pressure buildup in chamber A and restores the system to a state of equilibrium.

As a result, the pressure on the ACV is increased (causing it to throttle away from its

seat) and the separator oil level is restored to its set level.

When the inlet flow is less than the outlet flow, the level of oil in the separator decreases:

The flapper moves away from the nozzle, widening the gap between the nozzle and the flapper. This causes the air pressure in chamber A of the relay to decrease. The pressure drop in chamber A and the action of the spring G move diaphragms C and D up. Air from the automatic control valve starts to bleed off to the atmosphere through chamber I.

This reduction in pressure causes the ACV to close under the action of its spring. At the same time that air flows from the ACV to the atmosphere, the air pressure passing

through proportional band valve to the Bourdon tube decreases, causing the nozzle on the Bourdon tube to move closer to the flapper. This action causes the pressure in chamber A to increase enough to close the passage between chambers F and I.

As a result, the pressure on the ACV is decreased (causing it to throttle closer to its seat)

and the oil level is restored to its set level.

Proportional Band Valve

As shown in the "Displacement-Type Controller" figure, the pressure from relay chamber F

flows to the automatic control valve and also flows to the proportional band three-way valve.

The orifice of this valve is adjustable so the amount of air pressure or "feedback" to the Bourdon

tube can be set as desired.

This figure represents a displacement type controller, one that does

not float on top of the liquid, but floats in the liquid and is displaced

(moves up and down) as the liquid level changes. As shown in the

diagram, to control the liquid level the liquid must be between

points A and B. If the liquid level is below A or above B, the

controller will not be able to control the liquid level.

The proportional band setting is expressed as a percentage, based on

the length of the plunger, as described in the following examples.

This percentage can vary from 0 to 100%. For example, if the

proportional band is set at 100%, the liquid level would have to

move from A to B or B to A to fully stroke the valve. In contrast, if the proportional band is set

at 25%, the level of liquid would have to move 25% of the distance between A and B to fully

stroke the valve.

Another way this relationship is expressed is based on the length of the level change that will

cause the valve to fully stroke. For example, if the level change that causes a full stroke of the

ACV is 8 in. and the float is 16 in. long, the proportional band is set at 50% (50% proportional

band).

The following animation of an oil level controller demonstrates the operation of the oil ACV and

its controller. The effect of the proportional band valve on the ACV will also be shown.

Liquid Control Valve Multimedia

Objective: To demonstrate the operation of the valve and controller

To demonstrate the effect of the proportional band valve

Comment: The level of the liquid-gas interface inside the separator should be kept constant to

maintain steady separation conditions. A variation in this level changes the volume of gas and

liquid in the separator, which in turn affects the speed and the retention time of the two fluids.

The liquid control valve (LCV) is the equipment responsible for keeping this steady separation

condition.

This animation will demonstrate how the LCV components (LCV, Bourdon tube, plunger, level

setting, proportional band controller, and the liquid valve) interact with each other.

The steady state condition will be covered in the next version of this animation.

For related topics, see the Gas Automatic Control Valve and the Gas Flow Recorder animations.

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Water Level Controller

The interface level between water and oil in

the separator should be kept constant to

prevent the water from passing over the weir

plate and flowing into the oil compartment.

This is accomplished with a float connected to

a water level controller that acts on a valve

fitted to the water outlet.

The level of water is controlled with a float that floats in water but sinks in oil. The movement of

the float is transmitted through a tube to a flapper that moves away from or closer to the nozzle,

causing it to leak air. The air leak from the nozzle is used to open or close a control valve on the

separator water outlet.

Automatic Control Valves

The automatic control valves (ACV) for the oil, gas, and water controllers are designed to

regulate the rate of flow in a pipe by varying its cross-sectional area in response to an air leak

signal received from a controller.

The "Automatic Flow Control Valves" figure shows the two different types (normally open and

normally closed) of control valves used in a separator.

Sight Glass

The sight glass is a visual level indicator. On the separator there's an oil sight glass to monitor

the oil-gas interface and a water sight glass to monitor the oil-water interface. The levels inside

the separator can be seen through the glass.

This device is made of transparent glass housed in a steel chamber to withstand the pressure

inside the separator. In the event the glass breaks, the safety glass is equipped with safety valves

that prevent fluids inside the separator from escaping. The safety valve works using a ball that

automatically seals off the tank from the sight glass using the pressure differential between the

tank and the atmosphere. After a broken glass is changed, the ball needs to be pushed back in its

groove so it can seal off the separator from the sight glass, in case another failure occurs. Use the

stem tip to push the ball back by moving the handle about one quarter turn. Once the ball is in

position, turn the handle back to return the stem to its original position.

Air Scrubber

The air used to operate the oil, gas, and water controllers is provided by an air compressor. This

air from the compressor is first filtered using an air scrubber. The air scrubber is simply a vertical

pot where the impurities and water settle. After the air is filtered, it is sent to pressure regulators

where the air pressure is reduced to a level that's acceptable for the instruments.

Pressure and Level Controllers


Safety Devices

In case a malfunction causes the separator pressure to rise to a dangerous level, these devices

provide an emergency vent to the atmosphere. To prevent this type of failure, the separator is

designed with two weak points--a safety relief valve and a rupture disc--that are activated in case

of overpressure. For the safety valve to operate properly, it needs a needle valve and a check

valve.

Safety Relief Valve

The safety relief valve is located on top of the separator. Its outlet is connected to the gas outlet

line, downstream of the automatic control valve (ACV). When the safety relief valve is opened,

gas is bled off to the flare. Depending on client requirements and local regulations, the outlet for

the safety relief valve is sometimes connected to a separate vent line.

The safety valve incorporates a bellows seal that prevents separator fluid discharge from entering

the upper part of the valve that's exposed to the atmospheric pressure. The bellows has an

effective area equal to the area of the valve seat so the effect of any back pressure from the valve

outlet on set pressure is eliminated.

The set pressure is the pressure at which you want the safety relief valve to open. The set

pressure is adjusted by the force of a spring on a sealing disc that is exposed to separator

pressure.

The set pressure is normally set at 90% of the nominal (600 psi, 720 psi, or 1440 psi) separator

working pressure (WP). Due to temperature influence and calibration tolerances, it cannot be

guaranteed that the safety relief valve will open at exactly 90% of WP. When setting the

operating pressure, it's safe to assume that the valve could open within a range of 85% to 95% of

the WP. Consequently, the operating pressure in the separator should be kept at or below 80% of

WP to prevent accidental opening of the safety valve.

For example, for a 1440 psi WP separator, the set point is 90% of WP (1296 psi), and the

operating range for the valve is between 85% of WP (1224 psi) and 95% of WP (1368 psi). For

this separator, the operating pressure should be set at or below 80% of WP (1152 psi).

Check Valve

The check valve is located downstream of the safety relief valve. It is a free-swinging flapper

valve that prevents back pressure in the gas outlet line from reaching the safety relief valve

outlet, where it could possibly affect the opening of the safety relief valve.

Needle Valve

The needle valve, connected between the safety relief valve and the check valve, ensures that any

back pressure on the safety relief valve outlet is discharged to the atmosphere. It should be small

in size and must be checked often to make sure it's clear. The needle valve is kept open during

operations to detect leaks in the check valve and prevent leaks from exerting back pressure on

the safety relief valve. In the event the safety relief valve opens, the needle valve limits the size

of the leak, making it easy to control. If H2S is present, a line must be connected to the needle

valve to vent the gas away from personnel.

Rupture Disc

The main disadvantage of the configuration shown in the "Safety Devices" diagram is if for any

reason the gas line to the flare is blocked, the safety relief valve will not be able to discharge the

overpressure. For this reason, and to prevent any other malfunction of the safety relief valve, the

separator is equipped with an additional safety device called the rupture disc. The rupture disc

operates on a different principle than the safety relief valve. It's made of a fine, convex metal

diaphragm designed to rupture at a very specific pressure. The diaphragm is completely torn

apart when ruptured, leaving a large hole through which gas and liquid can escape. The disc must

be replaced when ruptured, but the safety relief valve can be opened and closed repeatedly.

The disc is normally set to break at 110% of the nominal (600 psi, 720 psi or 1440 psi) separator

working pressure (WP). Due to temperature influence and calibration tolerances, it cannot be

guaranteed that the rupture disc will burst at exactly 110% of WP. It is safe to assume that the

disc could burst within a range of 105% to 115% of the WP. Using this range of values helps

ensure, in case of an emergency, that the safety valve will always operate before the disc

ruptures.

Safety Devices


Metering Devices

This topic looks at the meters used to measure flow rates for oil, gas, and water as they leave the

separator. To measure low to high oil flow rates, a positive displacement meter and a vortex

meter attached to the oil outlet line are used. The gas flow rate is measured using an orifice

meter, a type of differential pressure meter, attached to the gas outlet. Water flow rates are

measured using a positive displacement meter, identical to the positive displacement meter used

to measure oil, that's attached to the water outlet. The shrinkage factor, measured using a

shrinkage tester, represents a correction factor used in oil volume computations. Gas scrubbers

filter the gas that's used to operate the differential pressure recorder.

Oil Meters

The oil outlet is fitted with two parallel meters, making it possible to cover a broad range of flow

rates. A single meter cannot accurately cover the entire range (low to high) of flow rates. Oil

meters are used one at a time and the choice depends on the flow rate. Low and medium flow

rates are measured with a positive displacement meter, and high flow rates are measured with a

vortex meter.

The positive displacement meter measures the liquid passing through it by separating the liquid

into segments and counting the segments. Liquid entering the meter strikes the bridge and is

deflected downward, hitting the blades and turning the rotor in the right direction. The seals on

the bridge prevent the liquid from returning to the inlet side. The rotor movement is transferred

to a register (readout device) with magnetic coupling.

Separators used for testing are usually equipped with a 2-in. diameter positive displacement

meter that can measure a flow rate from 100 to 2200 barrels per day.

The ball vortex meter consists of a body with an offset chamber and a rotor that are mounted

transversely to the flow stream. When liquid flows through the meter, a vortex is created in the

offset chamber. The rotational velocity of the liquid vortex is proportional to the rate of flow.

The rotor movement is transferred to a register (readout device) with magnetic coupling.

Separators used for testing can be equipped with a 2- or 3-in. diameter vortex meter. For this

type of meter, the flow rate depends not only on the size but also on the type of bearings used as

shown in the "Vortex Meters and Flow Rates" table.

Vortex Meters and Flow Rates

Meter Type Rating with ball bearings in barrels

per/day

Rating with sleeve bearings in

barrels/day

2-in. vortex

meter 850 to 6800 barrels/day 1700 to 8500 barrels/day

3-in. vortex

meter 2000 to 17,000 barrels/day 3400 to 22,000 barrels/day

The oil meters located upstream from the automatic control valves operate under pressure, so the

volume of oil measured is greater than if compared to standard conditions (atmospheric pressure

and 60o F). Oil passing the counter may be hot, which also increases the volume measured. After

cooling, the real volume of oil will be less. This is because the oil leaving the separator still

contains dissolved gas that will escape when the pressure drops. A first correction for this loss of

volume must be applied and a second correction is applied for temperature changes.

Water Meter

The water outlet is fitted with a 2-in. diameter positive displacement meter that is identical to the

positive displacement meter used to measure the oil flow rate.

Gas Meter

Before leaving the separator, the gas flow rate is measured using a type of differential pressure

meter called an orifice meter. A calibrated orifice inserted in the gas stream creates a small

pressure drop across the orifice plate. The pressure upstream and downstream of the orifice plate

is used along with the gas temperature and density to calculate the gas flow rate.

At the beginning of a test, the gas flow rate is unknown. During the test, the gas flow rate may

change; therefore, different sizes of orifice plates are used. The correct diameter of orifice plate

is selected by trial and error, so it's important to have an apparatus that allows the orifice plate to

be changed without interrupting the gas flow. The orifice gas meter is designed for this purpose.

Replacing the Orifice in a Gas Differential Meter - Step 1

The following animation describes the safe change of the orifice plate in the Daniel orifice meter.

Gas Orifice Plate Meter Multimedia

Objective: To learn how to safely change the orifice plate in the gas orifice plate meter while it

is under pressure

Comment: The Daniel orifice meter measures the gas flow at the separator using the differential

pressure across an orifice. This animation describes the step-by-step process of how to remove,

change and install the orifice plate.

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To obtain accurate measurements, the flow of gas must be streamlined before it reaches the

meter. An adequate length of straight pipe and straightening vanes (bundle of straight tubes fitted

inside the pipe) are positioned before the meter to reduce the disturbances created by the elbows

in the gas line.

To record the differential pressure, a measuring instrument called a differential pressure recorder

is used. The high pressure side of the recorder is connected on the upstream side of the orifice

and the low pressure side is connected on the downstream side. In this way, the differential

pressure can be measured. The movement of the recorder is transferred to a pen that records the

differential pressure on a chart. The same chart is used to record the static pressure, measured

downstream of the orifice plate. In addition, another pen is used to record the gas temperature.

The "Differential Pressure Recorder Process" diagram includes steps that show how the

differential pressure recorder works.

The following animation of a gas pressure recorder depicts how separator pressure changes and

selection of orifices affect the pressure readings.

Gas Flow Recorder Multimedia

Objective: To understand the response of the recorder with separator pressure changes and the

selection of orifices

Comment: The gas flow recorder (GFR) is one of the instruments attached to the separator. It

will record the temperature and pressure in the output line and differential gas pressure across the

Daniel meter.

With the help of this recorder, we can select the correct orifice for the Daniel meter to cope with

the current flow.

For related topics, see the Liquid Control Valve and the Gas Automatic Control Valve

animations.

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Compressed size: 4.5 MB Mac or 7.0 MB PC,

Expanded (noncompressed) size: 7.1 MB Mac or 11.8 MB PC

Gas Scrubbers

The gas used to operate the differential pressure recorder is provided by the separator gas line.

This gas is first filtered, on both the high and low pressure lines, using bottom gas scrubbers.

These gas scrubbers are vertical pots where impurities, oil, and emulsion settle. Before the gas

reaches the recorder, it is filtered again by the top gas scrubber. The top scrubbers act as a buffer

between the gas and the recorder. In case the gas contains H2S or CO2 (sour gas), the top

scrubbers can be filled with hydraulic oil or diesel to prevent direct contact between the gas and

the recorder.

Shrinkage Tester

The shrinkage tester, usually attached to the oil sight glass of the separator, is used to estimate

the shrinkage factor in the field. The shrinkage factor is a correction factor used in the oil volume

computations. It represents the amount of dissolved gas in the oil that will be freed when the

pressure drops from the separator pressure to the atmospheric pressure.

The shrinkage tester consists of a bottle equipped with a graduated sight glass. Oil and gas will

flow to the tester until the oil level reaches "0" on the vernier, corresponding to a set volume

(Vo). The tester is then isolated from the separator and the bottle pressure is bled off to the

atmosphere slowly to prevent oil from being released with the gas. This allows gas to be freed

from the oil, so usually after 20 minutes, a new level can be read on the vernier. This new level

corresponds to a new volume (V) of oil. The shrinkage factor read on the vernier is simply the

V:Vo ratio, expressed as a percentage.

The following animation of a shrinkage tester illustrates the function of the valves and proper

operating sequence and measurement procedures. It includes an interactive simulator to reinforce

your understanding of this system.

Shrinkage Tester Multimedia

Objective: To understand the function of the valves of a shrinkage tester and learn the correct

operating sequence and measurement procedures

Comment: Well fluid in the separator is normally under pressure and its volume will change as

soon as the dissolved gas disappears under atmospheric conditions. This multimedia will

demonstrate how to operate the shrinkage tester that is normally attached to the separator. Valves

need to be operated in a certain sequence to obtain the correct reading. The animation will be

followed by a shrinkage tester simulator in which the students will be asked to click the valve

open/close in the correct sequence.

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Metering Devices


Piping Systems

This topic describes the functions of the other equipment that's attached to the separator piping

system: valves, a bypass manifold, and tapping points.

Valves

The "Separator Layout with Bypass" drawing shows a typical separator piping layout plus the

manual ball valves used to isolate the parts of the piping not in use.

Bypass Manifold

The bypass manifold between the separator inlet and the oil and gas outlets permits effluent to be

diverted to the burners or gas flare without passing through the separator. The bypass manifold is

used when the effluent doesn't need to be separated; for example, at the beginning of a test when

the well is first opened.

There's also a bypass line for the separator oil meter that's used when the oil flow rate does not

need to be measured.

Tapping Points

The oil and gas lines are equipped with tapping points and isolating valves, allowing fluid

samples to be taken. Tapping points on oil, water, and gas lines can be used to connect pressure

and temperature recorders. The separator is equipped with hammer wing unions for quick

connection and disconnection of pipe work.

Piping Systems


Equipment

Schlumberger has developed a wide range of separators that differ in size, modularity,

portability, and temperature rating which are available in working pressure ratings of 600, 720

and 1440 psi. All are H2S resistant and each has special features:

The 600 psi is designed to be light, easily lifted, even by a small crane or an helicopter. Because

of its lower working pressure, the metal is thinner so the overall vessel remains light.

The 720 psi is designed to handle high flow rates of oil, because its extended length provides a

long retention time.

The 1440 psi version is by far the most commonly used separator. Due to its high working

pressure, it can handle higher flow rates of gas. The drawback is the higher overall weight for

this separator.

These drawings show examples of several types of separators and their characteristics. For each

drawing, specifications are provided

Description

The three-phase test separator allows separation, metering and sampling of all phases of well

effluent. The horizontal test separator is capable of handling most types of fluid found in today¹s

exploration wells, such as gas, gas condensate, light oil, heavy oil, foaming oil and H2S-bearing

fluid.

The separator unit is skid mounted with an integral inlet and bypass manifold. The skid contains

an orifice meter for measuring gas flow rate, a positive displacement meter and a vortex meter

for measuring oil flow rate, and a positive displacement meter for measuring water flow rate.

The separator pressure is maintained at a preset level by an automatic control valve on the gas

outlet. The liquid level is maintained by an automatic control valve on the oil outlet. The liquid

level within the separator can be monitored through sight glasses.

The vessel is protected from overpressure by both a relief valve and a rupture disc system. The

outlet from the relief valve can be vented to the gas outlet or to an independent line. A second

relief valve can replace the rupture disc, if required.

A separator-mounted shrinkage tester is available to measure the oil volume change from

separator conditions to atmospheric pressure and temperature.

Sampling points for taking pressurized oil and gas samples are standard on each separator.

Specifications


Project code SEP-SKO SEP-SKP

Certifying authority Det Norske Veritas None

Design codes NACE MR 01-75 NACE MR 01-75

ASME VIII Div 1 ASME VIII Div 1

DNV Drill 'N,' DOE SI 289 DNV Drill 'N,' DOE SI 289

Working pressure 1480 psi [102 bar] at

100°F

1480 psi [102 bar] at

100°F

1350 psi [93 bar] at 200°F 1350 psi [93 bar] at 200°F

Working temperature -20 to 200°F [-28 to 93°C] 32 to 200°F [0 to 93°C]

Service H2S H2S

Separator vessel 42 in. x 10 ft 42 in. x 10 ft

Relief valve setting 1440 psi [100 bar] 1440 psi [100 bar]

2-in. rupture disc setting 1600 psi [112 bar] 1600 psi [112 bar]


coating

Marine anticorrosion

coating

Load factor 6.6 psi 6.6 psi

Nominal capacity

Gas Low liquid level 60 MMscf/D [1.7 MMm3 /D] at 1440 psi

High liquid level 25 MMscf/D [0.71 MMm3 /D] at 1440 psi

Liquid High level 14,400 BLPD [2289 m3 /D] at 1-min retention

Low level 6650 BLPD [1057 m3 /D] at 1-min retention

CONNECTIONS

Inlet (WECO Union) 3-in. Fig. 602 F 3-in. Fig. 602 F

Outlets (WECO Union)

Gas 3-in. Fig. 602 M 3-in. Fig. 602 M

Oil/water 2-in. Fig. 602 M 2-in. Fig. 602 M

Sampling points 1/2-in. NPT F 1/2-in. NPT F

DIMENSIONS

Height

Without relief valve 95 in. [2.42 m] 95 in. [2.42 m]

With relief valve 103 in. [2.62 m] 103 in. [2.62 m]

Width 87 in. [2.21 m] 87 in. [2.21 m]

Length 224 in. [5.68 m] 224 in. [5.68 m]

Weight

Empty 28,260 lbm [12,800 kg] 28,260 lbm [12,800 kg]

With piping set 30,900 lbm [14,000 kg] 30,900 lbm [14,000 kg]

Options

Shrinkage tester (SKT-

AB/AC) P-579040 M-808721


D/C) P-579041 M-806275

Low gas flow skid P-579082 P-579083

Water circuit control set P-579064 M-872886

Protective side panels M-801718 M-801718

Description

The heliportable separator package allows well testing to take place in areas where access is too

difficult for conventional test equipment. The three-phase test separator allows separation,

metering and sampling of all phases of well effluent.

The separator assembly is mounted on two skids that are connected together on site. The first

skid contains the separator vessel. The second consists of an inlet manifold and metering

instruments, including an orifice meter for measuring gas flow rate, a positive displacement

meter and a vortex meter for measuring oil flow rate, and a positive displacement meter for

measuring water flow rate.




The vessel is protected from overpressure by both a relief valve and a rupture disc system.

A separator-mounted shrinkage tester is available to measure the oil volume change from

separator conditions to atmospheric pressure and temperature.

Sampling points for taking pressurized oil and gas samples are standard on each separator.

Specifications

Assembly number K-874015

Project code SSEP-HFE

Certifying authority ABS

Design codes NACE MR 01-75, ASME VIII Div 1

Working pressure 600 psi [41.4 bar]

Working temperature 32 to 200°F [0 to

93°C]

Service H2S

Separator vessel 36 in. x 10 ft

Relief valve setting 600 psi [41.4 bar]

2-in. rupture disc

setting 660 psi 45.5 bar]

Nominal capacity at 600 psi

Gas Low liquid level 28 MMscf/D [0.79 MMm3 /D]

High liquid level 10.8 MMscf/D [0.25 MMm3 /D]

Liquid High level 10,500 BLPD [1670 m3 /D] at 1-min retention

Low level 2600 BLPD [415 m3 /D] at 1-min retention

Load factor 5 psi

CONNECTIONS


Gas Outlet 3-in. Fig. 602 M WECO Union

Oil/water outlets 2-in. Fig. 602 M WECO Union

Sampling points 1/2-in. NPT F

DIMENSIONS VESSEL SKID

CONTROL/MEASUREMENT

SKID

Height 67 in. [1.70 m] 67 in. [1.70 m]

Width 44 in. [1.10 m] 52 in. [1.30 m]

Length 158 in. [4.00 m] 154 in. [3.90 m]

Weight 4,000 lbm [1800 kg] 3,800 lbm [1700 kg]


Option

Shrinkage tester (SKT-A) M-874520

Description

The three-phase test separator allows separation, metering and sampling of all phases of well

effluent. The horizontal test separator is capable of handling most types of fluid found in today¹s

exploration wells, such as gas, gas condensate, light oil, heavy oil, foaming oil and H2S-bearing

fluid.

The separator unit is skid mounted with an integral inlet and bypass manifold. The skid contains

an orifice meter for measuring gas flow rate, a positive displacement meter and a vortex meter

for measuring oil flow rate, and a positive displacement meter for measuring water flow rate.




The vessel is protected from overpressure by both a relief valve and a rupture disc system. The

outlet from the relief valve can be vented to the gas outlet or to an independent line. A separator-

mounted shrinkage tester is available to measure the oil volume change from separator

conditions to atmospheric pressure and temperature.

Sampling points for the taking of pressurized oil and gas samples are standard on each separator.

Specifications

Assembly number K837655 K-579042

Project code SEP-SGF SEP-SGM

Certifying authority None None

Design codes NACE MR 01-75 NACE MR 01-75

ASME VIII Div 1 ASME VIII Div 1

Working pressure 720 psi [50 bar] at 100°F 720 psi [50 bar] at 100°F

675 psi [46 bar] at 200°F 675 psi [46 bar] at 200°F

Working temperature 32 to 200°F [0 to 93°C] 32 to 200°F [0 to 93°C]

Service H2S H2S

Separator vessel 36 in. x 10 ft 42 in. x 15 ft

Relief valve setting 720 psi [50 bar] 720 psi [50 bar]

3-in. rupture disc setting 790 psi [54.5 bar] 790 psi [54.5 bar]

Nominal capacity

Gas Low liquid level 25 MMscf/D [0.71 MMm3

/D]

41 MMscf/D [1/16 MMm3

/D]

High liquid level 13 MMscf/D [0.37 MMm3

/D]

18 MMscf/D [0.51 MMm3

/D]

Liquid High level 10,000 BLPD [1600 m3 /D] 23,800 BLPD [3783 m3 /D]

Low level 5000 BLPD [800 m3 /D]

at 1-min retention time

10,500 BLPD [1669 m3 /D]

at 1-min retention time

Load factor 1 0 psi 6.6 psi

CONNECTIONS

Inlet (WECO Union) 3-in. Fig. 602 F 3-in. Fig. 602 F

Outlets (WECO Union)

Gas 3-in. Fig. 602 M 3-in. Fig. 602 M

Oil/water 2-in. Fig. 602 M 2-in. Fig. 602 M

Sampling points 1/2-in. NPT F 1/2-in. NPT F

DIMENSIONS

Height

Without relief valve 93 in. [2.35 m] 95 in. [2.42 m]

With relief valve 100 in. [2.55 m] 103 in. [2.62 m]

Width 72 in. [1.82 m] 87 in. [2.24 m]

Length 205 in. [5.21m] 2260 in. [6.60 m]

Weight

Empty 16,500 lbm [7500 kg] 32,680 lbm [14,800 kg]

With piping set 19,150 lbm [8700 kg] 35,320 lbm [16,000 kg]


coating


coating

Options


AB/AC) M-808721 M-808721


D/C) M-806275 M-806275

Low gas flow skid P-579083 P-579083

Water circuit control set M-874445 M-839169

Protective side panels M-839170 M-839175

Separator Selection

Guidelines

The principal criteria for selecting a separator are:

Project requirements related to working pressure, emulsion, foam, and cost considerations.

The recommended retention time for fluid inside the vessel is greater than one minute. If the flow rate is high, a larger separator is needed to achieve the recommended retention time. Some jobs may require more than one separator to meet the recommended retention time.

Weight restrictions can be dictated by crane lift capacity at the well site or access to the well site; for example, only heli-portable separators can be used on some offshore rigs.


A differential pressure cell is needed for gas rate calculation. A shrinkage tester is needed if one is not already fitted on the separator. Check connection (cross-over) requirements. Connections need to be compatible with manifolds

and piping on rig lines. A compressed air supply is needed for the level controllers.

Separator Identification

The separator can be identified by its working pressure (WP) rating, temperature rating, and its

size. This information is stamped on a metal plate. It is also common to use colored bands

(painted or taped) on the separator for quick visual identification.

Safety

The following is a list of key safety considerations for separators:

After every job, the separator must be thoroughly cleaned to prevent corrosion from well effluents.

To prevent accidental closure of rig air supply valves during a test, lock open and label air supply valves to separator instruments.

To ensure proper operation of the pressure safety valve, make sure the swing valve is sealed tight before starting a test.

To detect any leak that could adversely affect the operation of the safety relief valve, keep the needle valve open. The needle valve is located between the safety relief valve and the swing valve.

In all operating conditions, it's recommended that compressed air be supplied to separator instruments. In the event that compressed air is not available, sweet separator gas may be used, but never H2S gas. This is because some of the gas is vented to the atmosphere through the controllers.

Make sure the lifting eyes on the separator frame are in perfect shape and don't show sign of corrosion, especially at the weldings.

During transportation, remove the floats used to control liquid levels to prevent them from falling into the vessel.

Check the expiration date of the official certification test of the separator. Like all pressure vessels, the separator requires periodic recertification.

Maintenance

For information about separator preparation and functional checks, see the recommended steps in

the "Field Operating Handbook (FOH) for Surface Well Testing."

For information about equipment maintenance, see the maintenance manuals for the separator

and the "FOH for Surface Well Testing."

Summary


The main functions of a separator. The different processes for achieving the separation between oil, gas and water. The main parameters that can be controlled and adjusted to optimize the separation. Using the shrinkage tester to get an accurate shrinkage factor.

Self Test

1. What are the main functions of a separator? 2. What processes does the separator use to separate oil, gas, and water? 3. Why should a separator be run at a constant pressure? 4. How is the separator pressure controlled? 5. What type of ACV is mounted on the separator gas line? Why? 6. What is the shrinkage measurement used for? 7. How is the separator protected against overpressure?

F) GAUGE TANK



Introduction

The "Surface Test Equipment" figure shows where the gauge tank is located in relationship to the

other surface testing equipment. On the upstream side, the gauge tank is connected to the

separator by the separator oil line. On the downstream side, it precedes the pump used to empty

the tank and the burners that burn off gas and oil. The gauge tank is unpressurized, unlike its

counterpart the surge tank which is pressurized. The gauge is never used when H2S is present;

the surge tank is used instead.

The functions of the gauge tank are listed below:

Storing liquids when pressure is low

When oil leaves the separator under low pressure, oil burners do not operate properly. To

remedy this problem, oil is stored in the tank where a pump is used to drive it to the burners

under sufficient pressure.

Storing liquids when large samples are required

It is unrealistic to take large samples of oil from a pressurized vessel, like the separator. For this

reason, the gauge tank is used to store oil before it is sampled. From the tank, dead (degassed)

oil can easily be transferred to sample drums.

Metering liquids when flow rate is low

Sometimes oil flow rates are so low that they do not register on the oil meter at the separator.

When it's impossible to measure the flow rate at the separator, the gauge tank is used to

measure the flow rate. The oil flow rate at the gauge tank is calculated by measuring the volume

of oil that accumulates in the tank over a defined period of time.

Calculating the volume correction factor at the tank to calibrate oil meters

The oil flow meter at the separator is not 100% correct. When oil leaves the separator, it still

contains some gas. In addition, the meter may not be correctly calibrated. By comparing the

volume reading at the oil meter with the actual volume measured at the tank, a correction

factor can be obtained. This correction factor, referred to as the "meter combined shrinkage"

factor, reflects two adjustments:

o Meter factor.

This is a calibration measurement that reflects the meter's inaccuracy.

o Shrinkage factor.

The difference in the oil volume read at the separator and the volume measured at the tank is

also due to the loss of gas when the oil is exposed to the atmospheric pressure in the tank. This

loss of volume is called the shrinkage factor. The pure shrinkage factor is measured at the

separator using a shrinkage tester.

Objectives


Explain the purpose of the gauge tank. Describe its applications and limitations. Identify and explain how the main components of the gauge tank work.

Upon completion of the practical exercises for the Gauge Tank, you should be able to:

Disassemble one of the flame arrestors to see how it operates. While emptying one tank compartment using a transfer pump, fill up the other compartment. Direct flow from one compartment to the other. Check the condition of the grounding strap and safety seam. Review FIT and TRIM procedures for the gauge tank.


This topic lists the main components of the gauge tank and describes how the tank is used to

calibrate meters. Click on the graphic or scroll down for detailed information on each

component.

Gauge Tank Components

Safety Seams

They are located on the roof of the gauge tank and are made of plates riveted together. If the

tank is accidentally overpressurized, the rivets will break and the roof of the tank will lift to

relieve the pressure.

Sight Glasses

These are transparent plastic tubes, located on one side of the tank, that monitor the liquid

levels in the tank. A graduated scale on the sight glass permits level readings and calculations of

the change in volume.

Gauging Ports

Located on the roof of the tank, these ports allow liquid levels in the tank compartments to be

manually monitored with a simple measuring stick when sight glasses are out of order.

Liquid Levels

The liquid levels located at the bottom of the tank allow you to see the amount of water and

sediment in the tank. High amounts of sediment are undesirable.

Gas Vent Lines

The tank is fitted with two gas exhaust lines: one per compartment. These lines allow gas in the

oil to escape from the tank. Gas vent lines are made up of a piping system of flexible plastic

hoses that vent gas far away from the work area at the well site or overboard on an offshore rig.

Flame Arrestors

The job of these safety devices, mounted on the gas vent lines, is to stop a fire from propagating

inside the tank. They are equipped with steel wool to ensure that no oil droplets are carried

away with the gas.

Butterfly Valves

The inlet and outlet manifold of the tank are equipped with butterfly valves. These valves are

used to fill or empty the tank.

Inspection Hatch

Each compartment in the tank has a removable panel, allowing the inside of the tank to be

inspected and cleaned.

Grounding Strap

The gauge tank is grounded with a grounding strap, allowing static electricity to be discharged,

so flashes can be avoided. The build up of static charges of electricity may be caused by the

friction from flowing fluids. Onshore, the strap is connected to an iron stake driven into the

ground. Offshore, it's connected to a spot on the rig that's free of paint or grease.

Fire Fighting Ports

The tank is fitted with two ports (not shown) that are designed to connect to the rig's fire

fighting equipment. In case of a fire, these ports are used to inject CO2 foam or Halon inside the

tank.

Calibration of Meters

Technical and economic considerations related to the development of a new reservoir may

depend on the accuracy of oil flow rates. Incorrect flow rates could cause the client to make

incorrect decisions about the well, which could have very expensive implications.

The meters on the oil flow line operate under pressure. Gas bubbles in the oil cause the oil meter

to register volume readings that are altered by the presence of the gas. To correct the volume

reading at the oil meter, a correction factor is derived by comparing the volume reading at the oil

meter with the volume measurement obtained at the tank. The volume correction factor is also

referred to as the "meter combined shrinkage" factor.

The following steps are needed to accurately and safely use the gauge tank to calculate the

volume correction factor:

1. Read the initial level of oil in the tank. 2. Divert the oil flow to the tank and simultaneously take a meter reading at the oil flow line and

record the time. 3. Verify that the level of oil in the tank is rising. (This tells you that oil from the separator was

diverted and is flowing properly.) 4. Verify that there is no pressure build up in the tank. 5. Check frequently at the gas vent line outlets for liquid or foam carryover. To avoid carryover, do

not allow more than 80% of a tank compartment to be filled. 6. Divert the oil flow back to the burners and simultaneously take a meter reading at the oil flow

line and record the time. 7. Before taking the final tank reading, wait until all the gas has escaped from the oil.

The volume correction factor is simply the ratio between the volume obtained in the tank and the

volume registered by the meter.

Note: At the time the final tank reading is taken, the tank temperature is also recorded. A

correction for temperature (temperature coefficient) is applied in order to report flow rates at

standard conditions: 14.65 psi (atmospheric) and 60oF.

The following animation will help you understand the procedures for obtaining a correction

factor to change oil volumes at separator conditions to volumes at stock tank conditions.

Liquid Meter Reading with Tank Correction Multimedia

Objective: To understand the procedure for obtaining a factor for correcting oil volumes from

separator conditions to stock tank conditions

Comment: None

Mac

Read me!

PC

Read me!


Equipment

Gauge tanks are available in 50-, 100- and 200-barrel capacities. Of these, the 100-barrel version

is the most common. The range of gauge tanks available makes it possible to select a gauge tank

that accommodates the required well test while not being larger, more complicated or more

expensive than the overall project demands.

The figure on the right shows a generic gauge tank and lists the specifications for the three

available sizes.

SKID MOUNTED

GAUGE TANK (FGTS-

A/B/C)

Description

The nonpressurized gauge tank is used to measure low flow rates or calibrate inferential or

positive displacement meters. It has two compartments, one of which can be emptied by the

transfer pump while the other compartment is being filled. Sight glasses with a scale permit

calculation of the change in volume based on the physical dimensions of the gauge tank.

Safety features include flame arrestors on each vent of the gauge tank and a thief hatch in case

the vessel is accidentally overpressurized.

A grounding strap is attached to each gauge tank to prevent buildup of static charges.

The gauge tank is never used when H2S gas is present in the effluent because gas released from

the gauge tank is vented to the atmosphere and may endanger personnel.

Specifications

Certification None


Project code FGTS-A FGTS-B FGTS-C

Capacity 50 bbl [8 m3] 100 bbl [16 m

3] 200 bbl [32 m

3]

Service Standard

Working pressure Atmospheric

Working

temperature 32 to 200°F [0 to 93°C]

Compartments 2

Safety devices 2 flame arrestors and bypass

grounding device

shearing roof set at 0.5 psi

Load factor 12 psi 14 psi 10 psi

2-in. rupture disc

setting

1600 psi [112

bar]

1600 psi [112

bar]


CONNECTIONS

Inlet 2-in. LP Fig. 602 WECO Union

Outlet 3-in. LP Fig. 602 WECO Union

DIMENSIONS


Width 87 in. [2.21 m] 87 in. [2.21 m] 87 in. [2.21 m]

Height 96 in. [2.40 m] 96 in. [2.40 m] 96 in. [2.40 m]

Weight (Empty) 4400 lbm [2000

kg]

10,000 lbm [4536

kg]

18,000 lbm [8165

kg]

Gauge Tank Selection Guidelines

The principal criteria for selecting a gauge tank are:

If the project requirements specify that a surge tank is required, a gauge tank is usually not needed.

Storage requirements for some jobs may require more than one gauge tank. The service type required (operating environment) does not allow the use of a gauge tank when

H2S is present..


Extensions (flexible plastic hoses) for the gas vent lines are required. High oil flow rates can cause excessive pressure that will burst the safety seams on the tank.

Safety

The following is a list of key safety considerations for gauge tanks:

The gauge tank is never used when H2S is expected to be in the well effluent. The gas from the gauge tank is vented to the atmosphere, so any H2S in the gas could endanger personnel.

Before diverting the separator oil to the gauge tank, you must check the ability of the gas vent lines to discharge the full volume of gas liberated when the pressure drops from separator to atmospheric pressure. Refer to the charts in the Tank Operations chapter of the "FOH for Surface Well Testing."

When using the gauging ports, check the gas vent lines to make sure a significant amount of gas is not being vented. If a significant amount of gas is being vented, measure the liquid levels later or wear a protective mask. When measuring liquid levels through gauging ports, it's always a good practice to wear a mask.

When diverting the oil to the tank, always limit the flow rate to avoid filling the tank too rapidly. In case of high flow rates, someone should constantly monitor liquid levels and be ready to divert the flow back to the burners to prevent overflow.

Prior to conducting any repair inside of the tank, it must be properly steam cleaned and degassed. The person repairing the tank must be in constant contact with a person on the outside of the tank.

Transport the gauge tank when it's empty; even a partially full tank has a much higher weight than an empty tank.

Do not lift the gauge tank by the top eyes, the stress on the tank walls will destroy the roof safety seam. To lift the tank, use the anchor shoes on the skid that are designed for this purpose.

Maintenance

For information about tank preparation and functional checks, see the recommended steps in the

"Field Operating Handbook (FOH) for Surface Well Testing."

For information about equipment maintenance, see the maintenance manual for the gauge tank


Summary


The functions of the gauge tank.

Why and how the gauge tank is used to calibrate the meters.

The main components of the gauge tank.

The key safety points to observe when using a gauge tank.

Self Test

1. Why is the gauge tank not used when H2S is present in the well effluent? 2. What are the two main uses of the gauge tank? 3. How is it possible to inspect the inside of the tank? 4. What is the purpose of the safety seams? 5. What must you check before passing the separator oil flow to the gauge tank? Why?

6. G) SURGE TANK

Introduction

The "Surface Test Equipment" figure shows where the surge tank is located in relationship to the

other surface testing equipment. On the upstream side, the surge tank is connected to the

separator by the separator oil line. On the downstream side, it precedes the pump used to empty

the tank and the burners that burn off gas and oil. Unlike the gauge tank, the surge tank is a

pressurized vessel. It is always used, instead of the gauge tank, when H2S is present in the well

effluent. The surge tank is H2S resistant. The gas leaving the surge tank is burned off, instead of

being vented to the atmosphere.

The surge tank's functions are listed below:

Low pressure separator

The surge tank was originally designed to work as a low-pressure separator, providing a

secondary stage of separation. It looks like a separator and, like the separator, it's pressurized

and equipped with a pressure regulation system and a safety relief valve. Although the surge

tank is still used as a secondary separator, today its primary use is identical to the gauge tank--

volume measurements for calibrating oil meters.

Storing liquids when pressure is low

When oil leaves the separator under low pressure, oil burners do not operate properly. To

remedy this problem, oil is stored in the tank where a pump is used to drive it to the burners

under sufficient pressure.

Storing liquids when large samples are required

It is unrealistic to take large samples of oil from a pressurized vessel, like the separator. For this

reason, the surge tank is used to store oil before it is sampled. From the tank, dead (degassed)

oil can easily be transferred to sample drums.

Metering liquids when flow rate is low

Sometimes oil flow rates are so low that they do not register on the oil meter at the separator.

When it's impossible to measure the flow rate at the separator, the surge tank can be used to

measure the flow rate. The oil flow rate at the surge tank is calculated by measuring the volume

of oil that accumulates in the tank over a defined period of time.

Calculating the volume correction factor at the tank to calibrate oil meters

The oil flow meter at the separator is not 100% correct. When oil leaves the separator, it still

contains some gas. In addition, the meter may not be correctly calibrated. By comparing the

volume reading at the oil meter with the actual volume measured at the tank, a correction

factor can be obtained. This correction factor, referred to as the "meter combined shrinkage"

factor, reflects two adjustments:

o Meter factor

This is a calibration measurement that reflects the meter's inaccuracy.

o Shrinkage factor

The difference in the oil volume read at the separator and the volume measured at the tank is

also due to the loss of gas when the oil is exposed to the atmospheric pressure in the tank. This

loss of volume is called the shrinkage factor. The pure shrinkage factor is measured at the

separator using a shrinkage tester.

Objectives


Explain the purpose of the surge tank. Describe its applications and limitations. Identify and explain how the main components of the surge tank work.

Upon completion of the practical exercises for the Surge Tank, you should be able to:

Empty the tank using a transfer pump. Check the condition of the grounding strap. Review FIT and TRIM procedures for the surge tank.


This topic lists the main components of the surge tank and describes how the tank is used to

calibrate meters. Click on the graphic or scroll down for detailed information on each

component.

Surge Tank Components

Safety Relief Valve

This valve is located on top of the surge tank. It's the same type of valve as the safety relief valve

used on the separator. The safety relief valve opens in case the pressure in the tank exceeds the

tank's working pressure--50 or 150 psi depending on the version of the surge tank. The outlet on

the safety relief valve is either connected to a separate vent line (recommended) or connected

to the gas vent line on the surge tank that goes to the gas flare, depending on client

requirements and local regulations.

The safety relief valve incorporates a bellows seal that prevents surge tank fluid

discharge from entering the upper part of the valve that's exposed to the atmospheric

pressure. The bellows has an effective area equal to the area of the valve seat so the effect

of any back pressure from the valve outlet on set pressure is eliminated.

The set pressure is the pressure at which you want the safety relief valve to open. The set

pressure is adjusted by the force of a spring on a sealing disc that is exposed to surge tank

pressure.

Sight Glass

The sight glass is a visual level indicator. A graduated scale permits level changes to be recorded

and volume changes to be calculated. The sight glass is made of transparent glass housed in a

steel chamber to resist the pressure inside the tank. In the event the glass ruptures, the safety

glass is equipped with safety valves that prevent fluids inside the surge tank from escaping.

The safety valve works using a ball that automatically seals off the tank from the sight glass

using the pressure differential between the tank and the atmosphere. After a broken glass is

changed, the ball needs to be pushed back in its groove so it can seal off the surge tank from the

sight glass, in case another failure occurs. Use the stem tip to push the ball back by moving the

handle about one quarter turn. Once the ball is in position, turn the handle back to return the

stem to its original position.

Alarm Level System

This system has a low and a high level alarm system. A horn sounds if the liquid in the tank

reaches the low or the high level. Whenever an alarm sounds, the liquid levels are adjusted

manually. So safe operation of the surge tank requires constant supervision of liquid levels. To

be able to run in fully automatic mode, this alarm system must be connected to the ESD or to a

pump.

Gas Vent Line

The surge tank is fitted with a gas vent or exhaust line that allows the gas in the oil to escape

from the tank. (Gas is sent to the gas flare where it is burned off.) The gas vent line for the surge

tank must be independent from the separator gas line. If they were connected, pressure from

the separator gas line could create back-pressure on the surge tank that's higher than the tank's

working pressure.

Flame Arrestor

The job of this optional safety device, mounted on the gas vent line as close as possible to the

surge tank gas outlet, is to stop a fire from propagating inside the tank. It is equipped with steel

wool to stop a flame and to ensure that no oil droplets are carried away with the gas.

Butterfly Valves

The inlet and outlet manifold of the tank are equipped with butterfly valves. These valves are

used to fill or empty the tank.

Grounding Strap

The surge tank is grounded with a grounding strap, allowing static electricity to be discharged,

so flashes can be avoided. The build up of static charges of electricity may be caused by the

friction from flowing fluids. Onshore, the strap is connected to an iron stake driven into the

ground. Offshore, it's connected to a spot on the rig that's free of paint or grease.

Automatic Control Valve

The ACV in the gas vent line is used to maintain and

regulate a positive pressure inside the surge tank. This

pressure is needed when using the surge tank as a second

stage separator and, depending on the pump used, may be

necessary to prime the pump when emptying the tank. The

ACV regulates the gas rate by varying the diameter of the

gas vent line in response to a signal received from a

controller. The controller reacts to any variation in the

surge tank pressure. When the pressure rises, the controller

opens the valve and when the pressure drops, the

controller closes the valve. Once the surge tank pressure is

manually set at the pressure controller, the operating

pressure in the vessel is maintained close to the set value.

For safety purposes, the ACV is normally open. If for any

reason the air pressure supply to the valve is cut, the vessel

will not be overpressurized. For a complete descripton of

the system, see the gas pressure controller in the Separator

Training page.

Nonreturn Valve

This valve is fitted on the gas vent line. It is mounted downstream of the automatic control

valve. It is closed when there's no pressure in the surge tank. The nonreturn valve prevents any

back-pressure from entering the tank, causing the pressure inside the tank to increase above the

maximum working pressure.

Calibration of Meters

Technical and economic considerations related to the development of a new reservoir may

depend on the accuracy of oil flow rates. Incorrect flow rates could cause the client to make

incorrect decisions about the well, which could have very expensive implications.

The meters on the oil flow line operate under pressure. Gas bubbles in the oil cause the oil meter

to register volume readings that are altered by the presence of the gas. To correct the volume

reading at the oil meter, a correction factor is derived by comparing the volume reading at the oil

meter with the volume measurement obtained at the tank. The volume correction factor is also

referred to as the "meter combined shrinkage" factor.

The following steps are needed to accurately and safely use the surge tank to calculate the

volume correction factor:

1. Read the initial level of oil in the tank. 2. Divert the oil flow to the tank and simultaneously take a meter reading at the oil flow line and

record the time. 3. Verify that the level of oil in the tank is rising. (This tells you that oil from the separator was

diverted and is flowing properly.) 4. Verify that there is no pressure build up in the tank. 5. Check frequently at the gas vent line outlets for liquid or foam carryover. To avoid carryover, do

not allow more than 80% of a tank compartment to be filled. 6. Divert the oil flow back to the burners and simultaneously take a meter reading at the oil flow

line and record the time. 7. Before taking the final tank reading, wait until all the gas has escaped from the oil.

The volume correction factor is simply the ratio between the volume obtained in the tank and the

volume registered by the meter.

Note: At the time the final tank reading is taken, the tank temperature is also recorded. A

correction for temperature (temperature coefficient) is applied in order to report flow rates at

standard conditions: 14.65 psi (atmospheric) and 60oF.

The following animation will help you understand the procedures for obtaining a correction

factor to change oil volumes at separator conditions to volumes at stock tank conditions.

Liquid Meter Reading with Tank Correction Multimedia

Objective: To understand the procedure for obtaining a factor for correcting oil volumes from

separator conditions to stock tank conditions

Comment: None

Equipment

Surge tanks are available in 80- and 100-barrel capacity, although the 80-barrel version is the

most common. The 80-barrel version has one compartment and a working pressure of 50 psi.

The 100-barrel version has two compartments and a working pressure of 150 psi. The range of

surge tanks available makes it possible to select a surge tank that accommodates the required

well tests while not being larger, more complicated or expensive than the overall project

demands.

Description

Originally designed as a secondary

stage of separation, the vertical surge

tank now serves an additional

function, replacing the gauge tank

where H2S is present in the effluent.

The pressurized surge tank is used to

measure flow rates. It has a single or

double compartment with an

automatic pressure control valve on

the gas outlet line to maintain a

constant backpressure. The change in

volume can be monitored through the

sight glasses since the physical

dimensions of the tank are known.

Safety features include a relief valve

in case of accidental overpressuring.

A grounding strap is attached to

prevent buildup of static charges.

High- and low-level alarms sound

liquid level warnings.

An additional gas line along the

burner boom is recommended to vent

the surge tank gas line separately

from the separator gas line.

Specifications

Assembly number M-839644 P-872885

Project code VST-B VST-D

Capacity 80 bbl [12.9 m3] 100 bbl [15.9 m

3]

Compartments 1 2

Working pressure 50 psi [34 bar] 150 psi [103 bar]

Load factor (in use) 23 psi 20 psi

Gas flow rate 4.76 MMscf/D 13 MMscf/D


Design codes DNV Drill "N," DOE SI 289, NA CE MR01-75

Service H2S

Working temperature -20 to 200°F [-28 to 98°C]

Safety devices Pressure relief valve

High- and low-level alarms

Grounding device

High-low pressure pilot (optional)

Inert gas injection (optional)

Pneumatic level controller (optional)


CONNECTIONS

Oil inlet 3-in. LP Fig. 602 WECO Union

Oil outlet 3-in. LP Fig. 602 WECO Union

Gas outlet 4-in. LP Fig. 602 WECO Union

Relief valve output 4-in. LP Fig. 602 WECO Union

Drain outlet 3-in. LP Fig. 602 WECO Union

DIMENSIONS

Height 19 ft 9 in. [6 m] 24 ft 3 in. [7.4 m]

Length 7 ft 11 in. [2.4 m] 7 ft 11 in. [2.4 m]

Width 7 ft 11 in. [2.4 m] 8 ft 6 in. [2.6 m]

Weight 13,250 lbm [6100 kg] 24,765 lbm [11,400 kg]

The figure to the right shows a generic surge tank and lists the specifications for the two

available sizes.

Surge Tank Selection Guidelines

The principal criteria for selecting a surge tank are:

If the project requirements specify that a gauge tank is required, a surge tank is usually not needed.

The service type required (operating environment) requires the use of a surge tank when H2S is present.


The surge tank needs less deck space than the gauge tank. The surge tank needs an air supply for the valve controller. Whether the surge tank will be used as a second stage separator. An additional gas vent line is required for the safety relief valve. A surge tank with two compartments may be required.

Safety

Whenever H2S is expected to be in the well effluent, a surge tank must be used instead of a gauge tank.

Before diverting the separator oil to the surge tank, you must check the ability of the gas vent line to discharge the full volume of gas liberated without creating a back pressure greater than the maximum pressure rating of the vessel.

Refer to the charts in the Tank Operations chapter of the "FOH for Surface Well

Testing."

When diverting the oil to the tank, always limit the flow rate to avoid filling the tank too rapidly. In case of high flow rates, someone should constantly monitor liquid levels and be ready to divert flow back to the burners to prevent overflow.

Prior to conducting any repair inside the tank, it must be steam cleaned and degassed. The person repairing the tank must be in constant contact with a person on the outside of the tank.

Transport the surge tank when it is empty; even a partially full tank has a much higher weight than an empty tank.

The exhaust for the safety relief valve must be connected to a 4-in. pipe landing that must be located downstream and far away from the working area.

Transporting the surge tank is a hazardous operation. The following animation will help you understand the different steps involved in this operation.

Erecting a Vertical Surge Tank Multimedia

Objective: To explain how to safely transport, erect and position the tank for use or storage

Comment: This animation covers the preparation, transportation and installation of the surge

tank from the Schlumberger location to the wellsite. A special focus is placed on safety, lifting

and handling practices.

Mac

Read me!

PC

Read me!


Maintenance

For information about tank preparation and functional checks, see the recommended steps in the

"Field Operating Handbook (FOH) for Surface Well Testing."

For information about equipment maintenance, see the maintenance manual for the surge tank


Summary


The main applications of the surge tank.

Why and how the surge tank is used to calibrate the meters.

The main components of the surge tank.

The key safety points to observe when using a surge tank.

Self Test

1. Give three reasons for using a surge tank. 2. How is the volume of oil contained in the surge tank calculated? 3. What is the purpose of the ACV mounted on the gas line outlet? 4. How is it possible to prevent back-pressure from entering the surge tank? 5. Why is it important to prevent back-pressure from entering the surge tank? 6. What was the original purpose of the surge tank?

I) TRANSFER PUMPS



Introduction

The "Surface Test Equipment" figure shows where the transfer pump is located in relationship to

the other surface testing equipment.

On the upstream side, the transfer pump is connected to the oil outlet line of either the surge or

gauge tank. On the downstream side, it is connected to the burner oil line.

The most common application of the transfer pump is to empty the tank and send the oil to the

burner under sufficient pressure to ensure efficient burning. The transfer pump can also be used

to send oil from a tank to a pipe line, another tank, or to a tanker. On rare occasions, it can even

be used to reinject oil into the reservoir. Pumps are driven with electric or diesel engines.

There are many different types of oil transfer pumps that can be used for well testing operations.

It is beyond the scope of this training page to discuss each type. Instead, a description of the

operating principles is provided for the most common pumps used: the positive displacement

pump and the centrifugal pump.

Objectives


Explain the main purpose of the transfer pump. Describe the operating principles for the two types of pumps covered in this training page. Explain the purpose of a safety relief valve and describe how a typical safety relief valve works. Draw a fluid circuit schematic for a pump equipped with a bypass valve and explain the purpose

of the bypass valve. List four safety rules that should be observed when working with electrically driven transfer

pumps.

Upon completion of the practical exercises for the transfer pumps, you should be able to:

Identify the type of transfer pumps available in your location. Disassemble the pump section and explain the function of each component. Change the set pressure of the safety relief valve that's presented in this training page. Reassemble the pump section and perform a FIT check.


There are many different types and models of pumps. However, most pumps can either be

broadly classified as positive displacement or centrifugal, depending on the action used to move

the liquid to a higher pressure level.

Positive Displacement Pumps

Positive displacement pumps employ a moving piston and either a plunger (reciprocating pump),

diaphragm (diaphragm pump), or rotor (rotary pump) to move a fixed volume of liquid per

revolution of the pump. From these different categories of positive displacement pumps, only the

rotor type, which is widely used in testing operations, is discussed here.

Rotary Pumps

Rotary pumps are positive displacement pumps that operate by turning a rotating member inside

a housing in such a way that the rotation moves the oil through the transfer pump.

The "Gear Type Transfer Pump" and "Screw Type Transfer Pump" schematics show two

different types of rotary pumps used in the oilfield.

Gear Type Transfer Pump

An electric or diesel engine drives the rotor that

drives the idler shown in the "Gear Type Transfer

Pump" drawing. The rotor gears and the idler gears

closely intermesh taking fluid from the suction port

of the pump and force it out the discharge port in a

continuous stream.

Screw Type Transfer Pump

The pump shown in the "Screw Type Transfer Pump" diagram is usually called a screw pump.

Although the geometry of its pumping elements may seem complex, its operating principle is

simple. The rotor and rubber stator are the key components. The rotor is a single, external helix

with a round cross-section that's machined from high strength steel.

The rubber stator is a double internal helix molded of a tough, abrasion-resistant elastomer,

permanently bonded in an alloy steel tube. As the rotor turns in the stator, oil is conveyed from

the pump's suction port to its discharge port. A continuous seal between the rotor and the stator

helices keeps the fluid moving steadily, at a fixed flow rate proportional to the pump's rotational

speed. This pump should always be filled with fluid before it's run.

The pump shown in the "Screw Type Pump with Bypass Valve" diagram is fitted with a bypass

line. A valve is mounted at the intersection of the bypass line and the discharge line. Before

starting the pump, the discharge line is closed and the valve turned so that the fluid can only

circulate through the pump. This ensures the pump is full of fluid before its started. When the

pump is full, the bypass valve is rotated a quarter turn, opening the pump to the discharge line

and closing the bypass line. Just before the pump is stopped, the valve is turned back to its

original position so fluid can circulate through the pump. This practice ensures that the pump is

filled with fluid before the next operation or prior to storage.

Safety Relief Valve

As these two types of pumps rotate, liquid is delivered to the discharge side of the pump. If the

discharge line is blocked or closed, pressure builds up until the motor stalls, a pump part breaks,

or the discharge line bursts. To avoid these problems, pumps are equipped with a safety relief

valve that prevents pressure buildup.

The "Relief Valve" is an illustration of a typical safety

relief valve mounted on the gear type transfer

pump.

The spring holds the poppet against the seat in the

valve body with a force that's determined by the

spring size and how much the spring is compressed

by the adjusting screw. When the force exerted by

the liquid against the poppet exceeds the force

exerted by the spring, the poppet moves and liquid

starts to flow through the relief valve, returning to

the suction side of the pump.

The "Port Arrangement for the Relief

Valve" drawing shows how the relief

valve is connected to the pump.

Advantages and Disadvantages

Some advantages of rotary pumps are:

They are relatively inexpensive. They function well over a wide range of flow rate capacities, net positive suction head (NPSH),

and oil viscosities. They are well adapted to handling viscous fluids. They are self priming.

Some disadvantages of rotary pumps are:

The close clearances and rubbing contact between moving parts in the pump limit the choice of construction materials.

These pumps are suitable for oil but not water because close clearances between moving parts require the liquid to have lubricating value.

Centrifugal Pumps

A centrifugal pump contains a central rotating wheel called an impeller that uses centrifugal

force to impart high velocity to the liquid, and then converts most of this velocity to pressure.

This type of pump can discharge fluid at high pressure and operates at relatively high rotation

speeds (3600 rpm).

Centrifugal pumps can be of radial flow construction, axial flow construction, or some

combination of the two. The flow in axial flow pumps is parallel to the pump shaft axis, and in

radial flow pumps, the flow enters the center of the wheel and is propelled radially to the outside.

Radial Flow Pump

The "Radial Flow Pump" drawing shows a cut-view of a radial flow pump.

The pump shown in the "Typical Centrifugal Pump" drawing is equipped with a ball valve

mounted on a bypass line. The centrifugal pump requires a lot of power to start the electric

motor. If all the fluid is diverted to the pump, the pump will require even more power to start.

The ball valve allows some of the flow to be diverted, making it easier to start the pump and

preventing pump overload. When the motor reaches normal speed, the bypass valve can be

gradually closed to divert the entire flow through the pump. The ball valve can also be used to

control and adjust the flow rate by diverting some of the flow.

Depending on the flow rate capacity of the centrifugal pump, the configuration of the piping and

valves mounted on the pump differs from pump to pump. Some flow pumps, for example, may

be equipped with a control valve and/or a check valve.

To control and adjust the flow rate, the discharge line for some centrifugal pumps is fitted with a

control valve. This valve can either be operated manually or automatically.

For some centrifugal pumps, a check valve is mounted on the discharge line (downstream of the

control valve) to prevent fluid from returning to the pump.

Advantages and Disadvantages

Some advantages of centrifugal pumps are:

It has a simple construction and quiet operation. It has small space requirements relative to its flow rate capacity. No close clearances between moving parts, so it can handle fluids containing small, solid

particles. Low maintenance requirements make it more dependable.

Some disadvantages of centrifugal pumps are:

They cannot produce as high a discharge pressure as reciprocating pumps. Efficiency is a function of flow rate and pressure. Pumps are designed for a specific flow rate and

pressure, when the flow rate and pressure are actually less than the pump is designed to handle, the pump is less efficient.

When compared to reciprocating pumps, centrifugal pumps are less efficient. High electric power is required to operate the pump. Requires a higher NPSH than positive displacement pumps.

Pump Piping and Installation Details

Suction Piping

It is essential that the suction port of the transfer pump be flooded. A transfer pump should never

be run without fluid. The net positive suction head (NPSH) recommended by the manufacturer

must be applied. To provide this NPSH and ensure that the suction port is flooded at all times, it

is necessary that:

The storage tank supplying the pump should be at sufficient elevation above the fluid entry of the pump.

If a surge tank is used, it can be pressurized to provide sufficient NPSH. The suction piping should be of sufficient size to minimize friction losses in the pipe between the

tank and the pump. The suction pipe should be as large as or preferably larger than the size of the pump suction inlet.

Long radius elbows are recommended to eliminate sharp turns. In addition, the suction piping

should be flushed out and cleaned prior to starting the pump.

Discharge Piping

Like the suction piping, the discharge piping should be of sufficient size to minimize friction

losses in the pipe in order for the pump to supply the required discharge pressure.

Equipment

Transfer pumps are usually described by their maximum flow rate capacity and discharge

pressure. At Schlumberger, the typical transfer pumps are 2000 B/D, 4000 B/D, 5000 B/D or

10,000 B/D capacities. Some models can be driven either by an electric motor or a diesel engine,

sometimes referred to as a pump primer. The choice of the pump primer depends on the safety

regulations. The range of pumps available makes it possible to select a transfer pump that

accommodates the required well tests while not being larger, more complicated, or more

expensive than the overall project demands.

These drawings show examples of several types of transfer pumps and their characteristics. For

each drawing, specifications are provided.

Description The transfer pump is used to empty one compartment of a tank while the other is filling. The

effluent can be pumped directly tothe burner or reinjected into an existing flowline

The unit consists of an electrically driven gear pump with an explosion-proof motor and starter.

The skid-mounted pump has protective panels and a box for electrical cable storage. A safety

relief valve on the pump discharge is sest at 250 psi.

A diesel-powered pump is also available for use in safe areas. The exhaust is fitted with a flame

arrestor.

Specifications

Assembly

number M-816551 M-872831 M-837654

Project code PMP-ECB PMP-FAA PMP-TCB

Certification None DNV type

approval None

Capacity at 250

psi

2000 BOPD

[318 m3/D]

2000 BOPD

[318 m3/D]

2000 BOPD

[318 m3/D]

Service Standard Standard Standard

Operating

temperature

32 to 200°F 32 to 200°F 32 to 200°F

Motor 11-kW electric 11-kW electric 15-hp air-cooled

440 V/60 Hz 440 V/60 Hz diesel engine

380 V/50 Hz 380 V/50 Hz

Explosion

proofing EExd II B T4 EExd II B T4 None

Cable 30 m of 4 x 6 mm2 30 m of 4 x 6 mm2 30 m of 4 x 6 mm2

Transmission Direct drive Direct drive Gear/clutch

Usage Zone 1 Zone 1 Safe area only

Protection Marine

anticorrosion

Marine

anticorrosion

Marine

anticorrosion

coating coating coating

Connections

Inlet 3-in. LP Fig. 206 3 -in. LP Fig. 206 3 -in. LP Fig. 206

WECO Union WECO Union WECO Union

Outlet 2-in. LP Fig. 206 2-in. LP Fig. 206 2-in. LP Fig. 206

WECO Union WECO Union WECO Union

Dimensions

Height 34 in. [0.86 m] 34 in. [0.86 m] 37 in. [0.93 m]


Width 27 in. [0.68 m] 27 in. [0.68 m] 28 in. [0.72 m]

Weight 950 lbm [430 kg] 1060 lbm [480 kg] 930 lbm [420 kg]

Description The high flow rate transfer pump is designed to empty one compartment of a tank while the other

is being filled or to reinject effluent into a flowline.

At high flow rates or under high flowline pressure, a 180-hp electric transfer pump can be used.

The pump is rated at 10,000 BOPD at a nominal pressure of 410 psi.

The skid-mounted pump unit comes with an integral bypass manifold and pneumatic oil control

valve.

The pump is rated for H2S service. With its explosion-proof motor and starter, the pump is

suitable for Zone 1 use.

Specifications


Design codes DNV Drill "N," DOE SI 289


Project code PMP-EFE

Service H2S (to NACE MR 01-75)

Capacity 10,000 BOPD at 410 psi

Maximum working pressure 720 psi

Working temperature -20 to 200°F

Motor 180 hp [130 kW]

440 V/60 Hz

380 V/50 Hz

Starter Star-Delta

Explosion proofing EExd, II BT4


Connections

Inlet 3-in. LP Fig. 602

WECO Union

Outlet 3-in. LP Fig. 602

WECO Union

Dimensions



Width 58 in. [1.47 m]


Transfer Pump The transfer pump is used to empty one compartment of a tank while the other is filling. The

effluent can be pumped directly tothe burner or reinjected into an existing flowline.

The unit consists of an electrically driven screw pump with an explosion-proof motor and starter.

The skid-mounted pump has a protective top anel and an integral bypass manifold. A safety

relief valve on the pump discharge is set at 300 psi.

A diesel-powered pump is also availableforuse in safe areas where an electrical supply is

unavailable. The exhaust is fitted with a flame arrestor.

Specifications

Certification None None

Assembly M-835701 M-837657

number

Project code PMP-EDC PMP-TDC

Capacity 4000 BOPD

[636 m3/D] at 300 psi

4000 BOPD

[636 m3/D] at 300 psi

Service Standard Standard

Motor 35-kW electric

440 V/60 Hz

380 V/50 H

52-hp air-cooled diesel

engine

Inertial starter

Explosion

proofing EEX-d II B T4 None

Cable 30 m of 4 x 25 mm2 30 m of 4 x 25 mm

2

Transmission Antistatic belt Hydraulic

Usage Zone 1 Safe area only


coating


coating

Connections

Inlet 3-in. LP Fig. 206 3-in. LP Fig. 206

WECO Union WECO Union

Outlet 3-in. LP Fig. 602 3-in. LP Fig. 602


Dimensions

Height 56 in. [1.42 m] 60 in. [1.53 m]

Length 132 in. [3.35 m] 146 in. [3.70 m]

Width 33 in. [0.85 m] 33 in. [0.85 m]


Transfer Pump Selection Guidelines

The principal criteria for selecting a transfer pump are:

The pumping capacity (2000 B/D, 4000 B/D, 5000 B/D, or 10,000 B/D) required. The discharge pressure required. Safety regulations dictate the use of an electric or diesel driven pump.


Three-phase electric supply is required for electric pumps. (The 10,000 B/D pump requires a high starting current (200 A) that some rigs cannot supply.)

The availability of electricity or diesel at the wellsite. The 10,000 B/D pump needs a heavy and expensive electric cable. If power is not available from the rig, a generator is needed.

Safety

The following is a list of some general safety considerations to observe when using transfer

pumps. Its important to be aware that each type of pump has its own specific safety points.

Please refer to the proper maintenance manuals.

Pumps must only be operated by experienced personnel. To prevent electrical shocks, the electrical starting box should always be closed when switching

the pump on or off. Electric pumps must be correctly grounded. Electric cables, plugs, and sockets must be in good condition. Because electric pumps require a lot of power, the power supply to the pump must be equipped

with a circuit breaker. Rotate the pump shaft by hand to ensure it turns freely. If the operating voltage of the pump is changed, verify that the pump is rotating in the right

direction. When the pump is rotating, never try make any adjustments or repair; turn off the pump first. Verify that the suction valve is open before starting the pump. Running the pump without fluid

will destroy the pump. When starting the pump, make sure it turns in the correct direction. The correct direction is

usually indicated by an arrow stamped on the pump. To ensure that the suction is flooded at all times, set the tank supplying the pump at sufficient

elevation above the inlet of the pump. Use pressure gauges mounted on suction and discharge lines to quickly verify that the pump is

working properly. Right after starting the pump, bleed off the air or vapors that could be trapped in the pump. If the pump does not deliver fluid at the discharge port within 30 seconds, stop the pump and

verify step-by-step the recommended starting procedure. Verify that the suction and discharge pressures are within the pressure range specified by the

manufacturer. Don't apply pressure that's higher than that required for efficient operation.

Maintenance

For information about pump preparation, functional checks, and equipment maintenance, see the

maintenance manuals for the pumps and the "Field Operating Handbook (FOH) Vol II."

Summary

In this training page, we have discussed the following points:

The most common application of the transfer pump. The two broad categories of transfer pumps used in well testing operations. The two different types of rotary pumps (gear type and screw type) described in this training

page. The importance of flooding the suction port of the transfer pump before running the pump. The key safety points concerning the pumps.

Self Test

1. What is the purpose of a transfer pump in a well testing setup? 2. What types of transfer pumps are used in well testing? 3. How do you decide which pump to use for a particular job? What factors should you consider? 4. What is the NPSH? 5. Why are the positive displacement pumps equipped with a safety relief valve?

J) OIL AND GAS MANIFOLD



Introduction

The "Surface Test Equipment" figure shows where the oil and gas manifolds are located in

relationship to the other surface testing equipment. The purpose of these manifolds is to divert

the flow of oil and gas from the separator to other pieces of equipment.

Gas from the separator flows through the gas manifold (connected to the separator gas line) and

is directed to one of two gas flares.

For a more detailed diagram of the gas manifold connections, click on the gas manifold in the

"Surface Test Equipment" drawing.

The oil manifold (connected to the separator oil line) links the separator to the tank, the transfer

pump, and the burners. It allows oil leaving the separator to be diverted to the tank or the

burners, or sent directly to a production line.

For a more detailed diagram of the oil manifold connections, click on the oil manifold in the

"Surface Test Equipment" drawing.

Objectives


Explain the purpose of the oil and gas manifolds. Draw the oil manifold connections between the separator, tank, transfer pump, and burners. Draw the gas manifold connections to the burners.

Upon completion of the practical exercises for the oil and gas manifolds, you should be able to:

Remove the ball valve from an oil or gas manifold and disassemble it. Verify the condition of the sealing surfaces on the ball valve. Reassemble the ball valve and install it on the manifold. Review FIT and TRIM procedures for oil and gas manifolds.


Oil Manifold

The oil manifold shown in the "Oil Manifold Flow Paths" diagram is composed of an

arrangement of piping, five ball valves, and wing union connections. This arrangement makes it

possible to divert the oil without interrupting the flow. The possible flow paths that the oil from

the separator can take are described in the following paragraphs.

When the oil is sent from the separator to the left burner, valves V2 and V3 are open; and valves V1, V4, and V5 are closed.

When the oil is sent from the separator to the right burner, valves V2 and V5 are open; and valves V1, V3, and V4 are closed.

When the oil from the separator is sent to the tank, valve V1 is open; and valves V2, V3, V4, and V5 are closed.

When it is necessary to empty the tank and send the oil to one of the burners, the position of the valves differs depending on whether a single or double compartment tank is used.

o If a double compartment tank is used, one compartment can be filled while the other is emptied. The valve settings are:

Valves V1 and V4 are open, and either V3 or V5 is open. Valve V2 is closed, and either V3 or V5 is closed.

o If a single compartment tank is used, the tank is emptied when the well is shut in. The valve settings are:

Valve V4 is open, and either V3 or V5 is open. Valves V1 and V2 are closed, and either V3 or V5 is closed.

Note: When one outlet of the oil manifold is not used, it is usually sealed with a plug.

Gas Manifold

The gas manifold in the "Gas Manifold Flow Paths" drawing shows how the gas manifold is

connected to the separator gas line and to the burner flare lines. The gas manifold is made up of

two ball valves that permit the gas leaving the separator to be diverted to either one burner or the

other, depending on the wind direction.

Equipment

There is only one type of oil manifold. Its flexible configuration of valves and ports makes it

possible to accommodate various well testing setups. If the setup requires fewer ports, the unused

ports can be plugged. If more ports are required, a second oil manifold can be connected to the

first.

Description Oil from the separator is routed to the gauge tank or directly to the burner through the oil

manifold. Oil from the tank is also pumped to the burner by way of the manifold.

The oil manifold is skid mounted and usually consists of five 2-in. ball valves. The gas manifold

directs the gas from the separator to the gas flare. The gas manifold is skid mounted and consists

of two 3-in. ball valves.

Specifications

Certifying

authority Det Norske Veritas Det Norske Veritas

Design codes NACE MR 01 75 NACE MR 01 75


Project Code MFD-ACA MFD-ADA

Working pressure

At 100°F

At 200°F

1480 psi [102 bar]

1350 psi [93 bar]

1480 psi [102 bar]

1350 psi [93 bar]

Working

temperature

-20 to 200°F [-28 to

93°C]

-20 to 200°F [-28 to

93°C]

Nominal size 2 in. [51 mm] 3 in. [76 mm]

Connections

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


Dimensions 58 x 28 x 15 in. 38 x 15 x 16 in.

[1.47 x 0.71 x 0.38 m] [0.95 x 0.38 x 0.16 m]



coating


coating

There is only one type of gas manifold. Typically, only one gas manifold is required, but

depending on the complexity of the equipment setup, more than one gas manifold may be used.

A layout with two separators is an example of a complex setup where two gas manifold might be

needed.

The oil manifold is equipped with 5 ball valves (2 in.), and the gas manifold is equipped with 2

ball valves (3 in.).

The figure on the right shows an oil manifold and a gas manifold and lists their specifications.

Safety

The following is a list of key safety considerations for oil and gas manifolds:

All valves should be labeled to indicate flow paths (e.g., from separator to starboard burner) to avoid diverting the flow in the wrong direction.

When diverting flow, always open one valve before closing another. This practice prevents flow interruption and pressure buildup upstream of the valves.

Use the handles provided with the manifolds to open and close the ball valves. To avoid damaging the ball valve, when opening or closing these valves do not use cheaters.

Maintenance

For information about oil and gas manifold preparation and functional checks, see the

recommended steps in the "Field Operating Handbook (FOH) Vol. II."

For information about equipment maintenance, see the maintenance manuals for the oil and gas

manifolds.

Summary


The function of the oil and gas manifolds. The relationship between the flow paths of the oil and the position of the valves. Key safety points for the oil and gas manifolds.

Self Test

1. Draw a standard well test setup showing the different elements connected to the oil manifold. 2. What is the pressure rating of the oil manifold? Why? 3. What type of valve is usually mounted on the oil and gas manifolds? 4. What is the purpose of the gas manifold?

K) BURNERS AND BOOM



Introduction

When testing a well in a remote location, a principal concern is how to dispose of the oil

produced at the surface. Onshore, the oil is usually burned in a burning pit. Offshore, prior the

availability of burners, the only alternative was to store the oil in tanks or tankers, which was

costly and limited the duration of tests to a few hundred barrels.This significantly restricted the

information that could be obtained through well testing.

In the late 1960s, Flopetrol (now Schlumberger Testing) introduced the first flaring system to

safely and efficiently burn oil, making offshore testing economical.

Today, different types of burners are available to dispose of oil, foams, and oil-base muds. They

are usually comprised of one or more burning heads that are mounted on a boom to keep them at

a safe distance from the rig.

The "Surface Test Equipment" figure shows where the oil burner and the gas flare are located in

relationship to the other surface testing equipment. The gas flare is connected to the separator by

the separator gas line. The oil burner is connected to the separator, the tank, and the pump by an

oil manifold.

Objectives


Explain the purpose of an oil burner. Describe the operating principles of an oil burner. With the help of the "FOH for Surface Well Testing," write the rig-up procedures for a burner

boom.

Upon completion of the practical exercises for the burners, you should be able to:

Identify the function of all the items on the burner assembly. Remove and disassemble one oil atomizer from the burner. Check the condition of the seals and

reassemble the oil atomizer. Disassemble one water nozzle. Check it for debris, then clean and reassemble the water nozzle. Disassemble the swivel joint for maintenance and reassemble it. Disassemble the air line check valve for maintenance and reassemble it. Review FIT and TRIM procedures for burners and booms. Function test the ignition system following exactly the steps outlined in the FIT and TRIM

procedures.


To efficiently combust well effluent without producing unburned particles and smoke, the well

effluent must be reduced to very fine droplets. This process, called atomization, is achieved by:

Using the energy resulting from the pressure of the well effluent Supplying additional energy (air pressure) to enhance the process.

This mechanical and pneumatic process takes place in the atomizer.

Atomizer

The atomizer is the heart of the burner system. It consists of a chamber where the oil and air are

combined before the mixture is ignited by a pilot light. The oil enters the atomizer chamber, hits

the cone of the swirl assembly and passes through the slanted slots. The slanted slots of the swirl

assembly induce a swirling motion in the oil flow before it passes through the oil nozzle where it

is sheared into finely atomized droplets.

As the oil passes through the oil nozzle, compressed air provides the energy required for further

atomization. Compressed air leaves the air nozzle in a rotary motion at a velocity close to the

speed of sound. Air striking the oil jet breaks the fluid into even smaller droplets.

When the mixture of oil and air is ignited, the flame produced is rich and under-oxygenated.

Water sprayed into the flame brings more oxygen and avoids the formation of carbon black. The

flame burns clear and yellow (no unburned oil falls out). The water injected into the flame also

reduces heat radiation.

Efficient burning is a critical process and varying air, water, and oil pressures and flow rates are

usually necessary so the flame does not produce excessive black smoke (too rich in oil) or

excessive white smoke (too rich in water). The size of the air and oil nozzles also plays a major

role in the burning process. Detailed information is available in the "Field Operating Handbook

(FOH) for Surface Well Testing."

The following paragraphs detail the main components of an oil burner and give a description of a

mud burner and a boom.

Oil Burner

The different parts of an oil burner are shown in the "Typical Three-Head Burner" diagram and

are described below. Click on the graphic or scroll down for detailed information on each

component.

Hearth

The hearth is a cylindrical tube located in front of the atomizer. It guides the air drawn at the

back of the burner into the vortex created at the atomizer outlet and stabilizes the flame. The

hearth is most efficient when the burner is properly oriented in the wind.

Water ring with nozzles

The water ring consists of a circular tube mounted around the hearth. It is fitted with nozzles to

spray water in the flame as shown in the "Water Nozzle" diagram. A fine spray is mandatory

because big water droplets cause improper combustion and therefore pollution. The amount of

water and the water pressure are also important factors to consider in order to achieve proper

combustion. A maximum water-to-oil ratio of 50% and a pressure between 150 and 240 psi are

recommended. Different sizes of of water nozzles (3 mm and 4.5 mm) are available to match the

required water flow rate and pressure.

Gas pilot light

Located below the atomizer, the gas pilot system consists of a small propane burner and a spark

plug as illustrated in "Gas Pilot Light" diagram. The burner is lit by sending high voltage to the

spark plug from a remote control box.

Swivel joint

The swivel joint, as shown in the "Swivel Joint" figure, acts as a pivot support for the whole

burner. It allows the burner to be positioned up to 75 degrees on either side of the horizontal

axis Oil, water, and air enter in the swivel joint before going to the burner heads.

Oil and air check valves

A check valve is mounted on the oil line upstream of the atomizers to prevent air passing from

the atomizer into the oil line. A typical situation in which this might occur is during the start up

procedure for the burners because air is sent to the atomizers before the oil is sent.

Similarly, a check valve is mounted on the air line upstream from the atomizers to prevent the

oil flow from entering into the air line. It is possible that this might happen if the air compressor

that supplies the burners fails during burning operations.

Valves

On the typical three-head burner, two heads out of three are equipped with ball valves mounted

on the air and oil lines. These ball valves make it possible to select the number of heads that will

optimize burning for a given oil flow rate. The other head cannot be isolated or closed for two

reasons. First, it prevents the air and oil lines from overpressurizing in case the other heads are

closed; and second, the minimum number of heads required for burning is one.

Supporting frame

This device supports the atomizer, cylindrical hearth, piping, swivel joint, and the pilot light

system.

Rotation system

The supporting frame is mounted on a rotation system, actuated by a cable and a hand winch

located at the foot of the boom. This system allows the position of the burner heads to be

varied as necessary, depending on the wind direction. An optional pneumatic rotation system is

also available; it allows the position of the heads to be controlled from a remote station.

Mud Burner

The mud burner was developed as a economical solution to dispose of oil-base mud during

drilling operations. The mud burner is derived from the oil burner and also uses atomizers. It

allows oil-base mud to be burned without polluting the environment. The mud burner can also be

used to burn high viscosity oils.

The mud burner is comprised of three combustion heads fitted on a supporting frame. The upper

head burns a mixture of mud (or high viscosity oil) and diesel. The fine droplets of diesel mixed

with the mud (or high viscosity oil) promote efficient combustion. The two lower heads burn

diesel and create a flame curtain in which any possible fallout from the upper head is burned off.

The lower heads can be modified to burn gas instead of diesel, if necessary. To ensure

continuous ignition, the upper head is fit with two pilot lights. The water injection rings around

the heads spray water droplets into the flame, improving combustion by adding more oxygen. A

drip pan is installed under the heads to collect the hydrocarbon liquids that may have condensed.

The "Mud Burner" drawing shows a typical mud burner with air, water, oil (or mud), and diesel

lines. The 1 in. diesel line is used to supply diesel fuel that is mixed with the mud or the high

viscosity oil. The 2 in. diesel line supplies the lower heads of the mud burner. The oil, air, and

water lines are similar to the ones in a standard burner.

As is true for the standard burner, pressure and flow rate of the different fluids as well as the size

of the different nozzles play a major role in achieving efficient combustion. Detailed information

about pressures, flow rates, and nozzle sizes for mud burners is available in the "Burners-

Booms" chapter of the "Field Operating Handbook (FOH) Vol. II," and in the mud burner

maintenance manual.

Boom

To reduce heat radiation and the risk of fire, the burner is mounted on a boom to keep it away

from the rig. The boom is usually made up of two lightweight sections, which give it a length of

60 ft. The length of the boom can be extended to 85 ft by adding an intermediate section. The

structural design of the boom permits access to the burner.

The boom contains the necessary piping to supply the burner with air, water, oil, and propane; it

also includes the gas flare pipe. The water line is fit with a filter, preventing debris from

plugging the water nozzles. The boom is mounted on the rig with a rotating base plate and guy

lines. Horizontal guy lines allow the boom to be oriented and vertical guy lines fixed to the

structure of the rig (king post) support the boom. The rotating base plate allows horizontal and

vertical movements to facilitate the orientation of the boom. The boom axis should be placed

slightly above the horizontal axis so oil left in the boom piping after flaring operations does not

fall into the sea. This is also important when booms are installed on floating rigs. In order to burn

safely with changing winds, two booms are usually installed on opposite sides of a drilling rig.

An optional water screen placed on the boom, between the burner and the rig, can be used to

reduce heat radiation.

Equipment

Burners can be classified in two main categories: oil burners and mud burners. Oil burners are

usually described by their number of combustion heads which determines the maximum oil flow

rate they can burn. The oil burners have one, three, or four heads. Mud burners are equipped with

three heads. All burners, except the one head model, exist in two versions: standard and H2S

service.

These drawings show examples of several types of burners and their characteristics.

Description

The Spitfire oil burner is a high-capacity, lightweight, compact burner designed for installation

on production platforms or test barges. The use of several interchangeable burning kits makes it

possible to dispose of effluent under a wide range of flow rates.

Oil from the separator or tank is forced through the atomizer head and combined with

compressed air, emerging in tiny droplets. These droplets are ignited by a gas pilot light and

form a rich underoxygenated flame. A cylindrical hearth channels air from behind the flame to

stabilize it.

A water injection ring with 16 water nozzles sprays water into the flame about 16 ft. from the

burner head. The water evaporates rapidly and reacts with the flame to prevent the production of

carbon black, thereby minimizing fallout. The water also reduces radiant heat.

A swivel joint supports the burner and allows the head to turn 75 degrees to either side of the

boom axis.

Specifications

Certification None


Project code BRN-ADA

Service Standard

Number of heads 1

Maximum effluent flow

Operating at 200 psi



4200 BOPD [668 m3/d]

5500 BOPD [875 m3/d]

6000 BOPD [955 m3/d]

Minimum effluent flow 100 BOPD

Air supply 350 ft3/min [9.91 m

3/min] at 100 psi

Maximum water supply 8000 B/D [1275 m3/d] at 75 to 230 psi

Ignition supply 110-V AC, 50/60 Hz


CONNECTIONS

Effluent 3-in. LP Fig. 206 WECO Union

Water 3-in. LP Fig. 206 WECO Union

Air 2-in. LP Fig. 206 WECO Union

Propane for gas pilot 1/2-in. LP

DIMENSIONS

Width 37 in. [0.96 m]




Optional accessories

Pneumatic rotation kit M-808907

Seawater filter M-801519

Diesel pilot light kit M-801656

Atomizerkits

500 to 1200 BOPD

1000 to 4000 BOPD

4000 t0 6000 BOPD

M-804056

M-804056

M-804057

Description

The Seadragon oil burner cleanly disposes of oil produced during offshore well tests to avoid

storage or pollution problems.

Oil from the separator or tank is forced through the atomizer head and combined with

compressed air, emerging in tiny droplets. These droplets are ignited by a gas pilot light to form

a rich underoxygenated flame. A cylindrical hearth channels air from behind the flame to

stabilize it.

Water injection rings, each with 16 water nozzles, spray water into the flame about six feet from

the burner head. The water rapidly evaporates and reacts with the flame to prevent the production

of carbon black, thus minimizing fallout. The water also reduces radiant heat.

A swivel joint supports the burner and allows the head to turn 75 degrees to either side of the

boom axis.

The Seadragon burner is available with 3, 4 or 6 heads to suit the amount of effluent requiring

disposal.

Specifications (BRN-ABC/ACA)

Certification None None


Project code BRN-ABC BRN-ACA

Service Standard Standard


DIMENSIONS

Width 65 in. [1.65 m] 65 in. [1.65 m]

Length 49 in. [1.25 m] 49 in. [1.25 m]

Height 71 in. [1.80 m] 71 in. [1.80 m]


CHARACTERISTICS

Maximum effluent

flow




7500 BOPD [1192

m3/D]

10,000 BOPD [1590

m3/D]

12,000 BOPD [1908

m3/D]

10,000 BOPD [1590

m3/D]

13,300 BOPD [2115

m3/D]

16,000 BOPD [2544

m3/D]

Minimum effluent

flow 100 BOPD per head


3/min] at 100 psi

Maximum water

supply 18,000 BWPD [2862 m

3/D] at 75 to 230 psi


CONNECTIONS

Effluent 3-in. LP Fig. 206 Union

Water 3-in. LP Fig. 206 Union

Air 2-in. LP Fig. 206 Union


Options

Pneumatic rotation

kit M-807718



Specifications (BRN-HBC/HCA)

Certification Det Norske Veritas Det Norske Veritas


Project code BRN-HBC BRN-HCA

Service H2S H2S


Maintenance manual M-075019

DIMENSIONS

Width 65 in. [1.65 m] 65 in. [1.65 m]

Length 49 in. [1.25 m] 49 in. [1.25 m]

Height 71 in. [1.80 m] 71 in. [1.80 m]


CHARACTERISTICS

Maximum effluent

flow




7500 BOPD [1192

m3/D]

10,000 BOPD [1590

m3/D]

12,000 BOPD [1908

m3/D]

10,000 BOPD [1590

m3/D]

13,300 BOPD [2115

m3/D]

16,000 BOPD [2544

m3/D]

Minimum effluent

flow 100 BOPD per head


3/min] at 100 psi

Maximum water

supply 18,000 BWPD [2862 m

3/D] at 75 to 230 psi


CONNECTIONS

Effluent 3-in. LP Fig. 206 Union

Water 3-in. LP Fig. 206 Union

Air 2-in. LP Fig. 206 Union


Options

Pneumatic rotation M-807718

kit



Description

The Invert Oil Mud Burner was primarily designed for disposing of invert oil muds offshore. It

has also been used for disposing of emulsions from polluted beaches and for burning high-

viscosity oils.

The top head burns a mixture of mud and diesel oil, while the lower two heads burn diesel oil

and provide a flame to vaporize any drop-out from the top head. The lower heads can also be

modified to burn gas if it is more readily available.

The volumetric ratio between diesel and mud depends on the amount of water contained in the

mud. Generally, a 1-to-3 ratio permits efficient burning.

The Mud Burner heads have two pilot lights to ensure continued ignition.

The water injection rings around the heads enable fine water droplets to penetrate the flame,

modifying combustion to eliminate black smoke. Water injection also reduces radiated heat.

A swivel joint supports the burner unit and allows the heads to move 60 degrees to either side of

the boom axis.

Specifications

Certification Det Norske Veritas None


Project code BRN-HEA BRN-AEA

Service H2S Standard


CHARACTERISTICS

Upper head

Maximum effluent flow

Operating pressure

Diesel flow rate

Diesel injection pressure

5000 BOPD [795 m3/D]

150 to 600 psi

To suit mud characteristics

10% higher than effluent

Lower heads

Diesel flow rate

Operating pressure

Air supply

Maximum water supply

Diesel pilots

Ignition supply

1000 to 1500 BOPD [159 to 283 m3/D]

70 to 150 psi

350 ft3/min [9.91 m

3/min] at 100 psi

18,000 BPD [2862 m3/d] at 75 to 230 psi

28 gal/hr [127 liter/hr] at 100 to 200 psi

110-V AC, 50/60 Hz

CONNECTIONS

Effluent 3-in. LP Fig. 206 WECO Union

Water 3-in. LP Fig. 206 WECO Union

Air 2-in. LP Fig. 206 WECO Union

Diesel, upper head 1-in. LP Fig. 206 WECO Union

Diesel, lower head 2-in. LP Fig. 206 WECO Union

DIMENSIONS

Width 66 in. [1.65 m]




Burner Selection Guidelines

The principal criteria for selecting a burner are:

The type of effluent to burn. The maximum expected flow rate to determine the required number of heads. The service type required (standard service or H2S service).

Additional considerations for selecting a burner are:

Air compressors required to supply compressed air to the atomizers. The burners need propane for pilot lights. The burners need electricity for the ignition of the pilot lights. The burners need water for proper burning. Water is also needed for the water screen to reduce

heat radiation.

Boom Selection Guidelines

The boom is available in two different lengths, 60 and 85 ft, and in two different temperature

ratings, -4°F (-4 to 200°F) and 32°F (32 to 200°F). It is designed for use on fixed installations,

semisubmersibles, and drillships in winds of up to 160 km/h [100 mph].

These drawings show examples of different booms and their characteristics.

Description

The U-160 burner boom is designed for Schlumberger burners such as the Green Dragon*,

Seadragon* and Mud Burner. It is designed for use on fixed installations, semisubmersibles and

drillships, in winds of up to 160 km/hr [100 mph]. Its unique 'U' shape allows easy, safe access to

burner heads and boom pipe work.

The U-160 is modular and is available in 60- and 85-ft lengths. It must be used in conjunction

with turntable assembly M-813480.

The boom comes equipped with pipe work for an oil line, water line (including filter), air line

(including check valve), gas flare and pilot light supply line.

Additional equipment available includes a water-wall kit to reduce radiant heat, a second gas

flare, diesel oil pipe work for the mud burner, burner head rotation kits and pilot light kits for the

gas flares.

* Mark of Schlumberger

Specifications

Certifying

authority Det Norske Veritas

Design codes DOE SI 289, NACE MR 01 75

Assembly number M-839416 P-578222 M-839415 P-578223

Project code UBM-BA UBM-D UBM-CA UBM-E

Service General H2S General H2S

Working

temperature

Structure

-4 to

200°F

-4 to

200°F

-4 to 200°F

32 to 200°F

-4 to 200°F

-4 to 200°F

Pipe work 32 to

200°F

-4 to

200°F

Length 60 ft [18

m]

60 ft [18

m]

85 gt [25.7

m]

85 gt [25.7

m]

Weight 8140 lbm [3740 kg] 11,252 lbm [5170 kg]


Wind speed limitation versus ice thickness

Case Boom

length

No.

flares

Semisub C 60 ft 1

D 60 ft 2

G 85 ft 1

H 85 ft 2

Fixed installation A 60 ft 1

B 60 ft 2

E 85 ft 1

F 85 ft 2

Above 5-cm ice thickness, the boom must be swung in and secured.

Assumptions: 4-headed burner, oil and water lines full, 3 men near

burner head

The U-160 boom was designed for use within the following

performance parameters:

Semisubmersible Drillship

Rolling ±5 degrees, 9-sec

period

±7.5 degrees, 12-

sec period

Pitching ±5 degrees, 9-sec ±5 degrees, 12-

period sec period

Heaving ±0.5 g ±1.0 g

Applicable forces (newtons)

No.

flares

Ice

(cm)

Wind

(km/hr)

F1L F1W F2 F3 F4L F4W F5

Semisub 1 0 160 71755 41129 144011 8522 0 44963 7532

1 3 125 113355 84543 219110 19496 0 42375 7061

1 5 0 144952 141824 261553 32225 0 343 78

Fixed 2 0 160 61390 23977 123407 6914 0 49867 7796

installation 2 3 120 91957 56673 175009 15112 0 43238 6629

2 5 100 123858 90104 227554 24458 0 35579 5168

Semisub 2 0 160 81758 42031 158574 10022 0 50004 7737

2 3 100 123064 92124 224053 21879 0 30499 4462

2 5 0 163291 146560 283393 35402 0 1059 412

Assumptions: 4-headed burner, oil and water lines full, 3 men near burner head

Abbreviations L = Leeward

W = Windward

Minimum guy line angle 24 degrees

ß 24 degrees

Minimum rigging distances Y 6.7 m

Z 6.3 m

Applicable forces (newtons)

No.

flares

Ice

(cm)

Wind

(km/hr)

F1L F1W F2 F3 F4L F4W F5

Semisub 1 0 160 101401 44355 180825 6306 0 62106 6619

1 3 115 149130 101548 260063 15151 0 49749 5227

1 5 55 185630 160790 314744 24203 0 13710 1216

Fixed 2 0 160 89044 21212 155730 5158 0 68225 6659

installation 2 3 120 126849 62978 215374 11788 0 59222 5609

2 5 100 162614 101038 270046 18446 0 48317 4187

The principal criteria for selecting a boom are:

The heat radiation concern. Heat radiation from a burner mounted on an 85 ft boom is approximately half the heat radiation from a burner mounted on a 60 ft boom.

The working temperature.

Additional considerations for selecting a boom are:

Suitable supports (king posts) required to attach the boom. Usually they are fitted to the rig but Schlumberger can provide king posts.

Vertical and horizontal guy lines needed. Base plate welded to the deck of the rig.

Safety

The following is a list of key safety considerations for burners and booms:

Obtain a rig work permit before performing maintenance or starting burning operations on the rig.

Advise the customer before you start burning to ensure that no other activity on the rig will conflict with burning operations.

Do not light the burner if a helicopter is approaching the platform. The burners are very sensitive to the direction of the wind. Check for wind direction, steadiness,

and strength. A crew of firemen must be ready at all times during the burning operation. When working on the burner boom, always wear a life vest.

Semisub 2 0 160 115983 43885 198693 7482 0 68411 6570

2 3 100 165134 108216 272674 17044 0 41767 3677

2 5 0 206499 175470 330239 26733 0 2834 598

Assumptions: 4-headed burner, oil and water lines full, 3 men near burner head

Abbreviations L = Leeward

W = Windward

Minimum guy line angle 32 degrees

ß 23 degrees

35 degrees

25 degrees

Minimum rigging distances Y 9.4 m

Z 9.9 m

When somebody goes out on the burner boom, the stand-by boat, the barge master, and one testing crew member must be informed.

Securing yourself with a safety line to the boom structure is a personal decision. If the boom falls, being attached to it may be a safety disadvantage.

Do not go out on the boom while burning is in progress. Protect propane bottles and diesel drums from heat radiation by shielding them behind a rig

structure or covering them with wet rags. To help control excessive heat radiation, ensure the sprinkler system for the rig or around the

booms is working. The recommended procedures for installing booms must be strictly observed. They are detailed

in the "FOH for Surface Well Testing" and in the following animations "Burner Boom Preparation" and "Burner Boom Installation."

Burner Boom Preparation Multimedia

Objective: To understand the preparation and installation of 60 and 85 ft burner booms

Comment: This animation is the first part of the Burner Boom animation. Burner boom

installation requires good coordination and communication between the supply boat crew, rig

crew (crane operator), our crew, and the stand-by boat crew.

All safety rules are covered. Installation of the king post is explained, but the location selection is

not covered in this animation.

Mac

Read me!

PC

Read me!


Burner Boom Installation Multimedia

Objective: To understand the installation of 60 and 85 ft burner booms

Comment: After the king post is installed, the burner boom is ready to be lifted from the supply

boat and installed on the rig. Once again all common safety, lifting, and handling practices are

emphasized.

Mac

Read me!

PC

Read me!

Compressed size: 3.6 MB, Expanded (noncompressed) size:6 MB

Maintenance

For information about boom installation, burner preparation, and functional checks, see the

recommended steps in the "FOH for Surface Well Testing."

For information about equipment maintenance, see the "FOH Vol. II" and the maintenance

manuals.

Summary


The atomizer and its operating principles. The separate functions of the main components of the oil burner. The mud burner. The boom. The key safety points that you should be aware of when working around burners and booms.

The preparation and installation of burners and booms.

Self Test

1. How did the oil burner make offshore well testing practical? 2. What is the role of compressed air in the atomization process? 3. What is the purpose of the hearth that's mounted around the atomizer? 4. What is the purpose of the slanted slots in the swirl assembly? 5. Why is diesel mixed with the oil-base mud in the upper head of a mud burner? 6. How is the boom attached to a rig?

K) PIPING


Introduction Objectives Principles Equipment Safety Maintenance Summary Self Test References / Other Useful Links

Introduction

A well testing layout is made of several pieces of surface testing equipment linked together with

pipes and hoses that provide the path for the well effluent. The "Surface Test Equipment"

drawing shows the different pieces of equipment and the piping that connects them. These piping

connections can consist of rigid piping, articulated piping, or flexible hoses. The ability to

combine these different types of piping in different ways makes it possible to handle any type of

well testing layout.

Rigid piping, made of straight pipes and elbows, is used when no movement is needed between

surface testing equipment. Articulated piping or flexible hoses are used when a relative

movement between two elements is necessary. A typical place where articulated piping is used is

the line connecting the flowhead to the choke manifold. Flexible hoses allow the flowhead to be

moved up and down when setting the packer or manipulating tools downhole.

All the elements of a well testing layout--the piping and the surface testing equipment--are

attached together with wing union connections called Weco unions.

Objectives

Upon completion of this training page, you should be able to:

List the main categories of piping used in a well testing setup. Explain how the working pressure for a pipe with union connections is defined. List the colors used in the Schlumberger working pressure color code and their associated

working pressures.

Upon completion of the practical exercises for the piping, you should be able to:

Draw a standard well testing layout and specify the type of piping used to connect the different elements.


Piping Designation

A pipe is defined by its nominal size (approximate diameter) and the type of wing union attached

to the pipe. A 3 in. nominal diameter pipe equipped with a type 602 wing union is usually

referred to as a 3 in., 602 pipe. The nominal size does not correspond exactly to the external or

internal diameter of the pipe, instead it represents either 3 or 4 internal diameters depending on

the thickness of the metal wall. Detailed explanations of pipe diameters are covered in the "Well

Test Piping" chapter of the "Field Operating Handbook (FOH) for Surface Well Testing." Wing

unions are classified by a figure that indicates the cold working pressure (CWP), as described in

the next topic.

Color Code and Pressure Rating

Piping exists in a wide range of pressure ratings. It is very important to use piping that can

handle the expected pressures for a given job. To facilitate piping identification and avoid

confusion, Schlumberger defines its own piping identification system using a color code scheme

that is based on the pressure rating of wing union connections.

The following table summarizes the main color codes used at Schlumberger

Piping Color Codes and Pressure Ratings

Color Code Figure CWP WP (Schlumberger)

yellow 602 6000 psi 3000 psi

red 1002 10,000 psi 5000 psi

black 1502 15,000 psi 10,000 psi

white 2202 20,000 psi 15,000 psi

The wing union connections are classified by a figure that indicates the cold working pressure

(CWP) and the sealing method. The CWP is the maximum pressure at which the manufacturer

guarantees the union not to leak. Expressed in psi, the CWP is easily calculated by multiplying

either the first (e.g., 602) or the two first digits (e.g., 1002) of the figure by 1000. The last two

digits (e.g., 02) refer to the sealing method. For the figures listed in the "Piping Color Codes and

Pressure Ratings" table, the sealing method consists of a lip-type seal ring and a metal-to-metal

seal.

The far right column of the table indicates the working pressure for wing union connections (e.g.,

602, 1002, 1502, and 2202) approved by Schlumberger for well test applications. This pressure

refers to the wing union and must not be confused with the working pressure of the pipe. The

pipe on which the union is welded or screwed has a different pressure rating.

To determine the pressure rating for a whole piece of piping, both the pipe and wing union

working pressures (WP) must be compared. The lower WP is chosen as the working pressure for

the entire piece.

The following example is based on a 3 in. size pipe equipped with a 3 in., 602 wing union.

The WP for 3 in. pipe is 2553 psi (This is taken from a table in the "FOH for Surface Well

Testing.")

The WP for the 3 in., 602 pipe is 3000 psi.

Therefore, the WP of the whole pipe is 2553 psi.

This example applies only to new pipe. Wear and corrosion make it necessary to inspect piping

regularly and down rate the pressure rating accordingly. Therefore, color coding is meaningful

only if regular pipe inspections are performed and color coding updated. The "Well Test Piping"

chapter in the "FOH for Surface Well Testing" details how to calculate the pressure rating for

corroded piping.

NOTE: When using Figure 2202, be aware that different companies use different inside diameter

(ID) measurements for the same figure. At Schlumberger, we only use Weco Figure 2202 3 in.

for 15 kpsi WP. It has an ID of 3 in., whereas other company's Figure 2202 3 in. do not have a 3

in. ID. (e.g., Anson Figure 2202 3 in. has a 2.5 in. ID.)

Equipment

Piping is classified into three categories:

Rigid piping Articulated piping Flexible hoses

Rigid Piping

Rigid piping consists of straight pipes of different lengths (1, 2, and 5 meters are the most

common lengths) and elbows (typically 90 degrees).

Some advantages of rigid piping are:

Good resistance to abrasion Not expensive Almost maintenance free Available in different lengths

Some disadvantages of rigid piping are:

Low resistance to temperature unless fitted with expensive high temperature seals Each pipe requires a seal Weight

Articulated Piping

Articulated piping consists of 90 degrees elbows connected with swivel joints that allow rotation

in one, two, or three planes.

Some advantages of articulated piping are:

Easy rig up Can be configured in an unlimited variety of ways to suit

practically any surface testing layout

Some disadvantages of articulated piping are:

Large number of seals When bearings fail, it is time consuming to change them

Flexible Hoses

Flexible hoses are made of rubber or polymer protected by a flexible metallic carcass such as

Coflexip.

Some advantages of flexible hoses are:

Flexibility Various lengths Virtually maintenance free Resistant to corrosive fluids (Coflexip) Very reliable

Some disadvantages of flexible hoses are:

Low resistance to high temperature (Coflexip) Expensive (Coflexip) Heavy. A crane is needed for the installation (Coflexip) Repair done only by specialists (Coflexip) Fragile when not protected with a metallic carcass

Piping Selection Guidelines

The principal criteria for selecting the type of piping are:

Working pressure

The working pressure of the piping is dictated by the "Schlumberger Pressure Operations

Guidelines" which state:

"When the stream pressure is reduced in stages, each section of the surface testing equipment

shall be selected either to withstand the maximum expected shut-in wellhead pressure, or the

different piping sections shall be protected by a suitable pressure relieving device triggered at

the maximum working pressure of the individual sections."

Flow rate

The size or diameter of the piping depends on the maximum expected flow rate. The most

common sizes of piping used are 2 in. and 3 in. diameters, and 4 in. diameter piping is

sometimes chosen for high gas rate tests.

Detailed informations on pipe sizes and flow velocities is available from these sources:

the "FOH Vol. I," a software program developed by the Early Production Facilities (EPF)

group in Schlumberger, and the API Recommended Procedures 14 E (API RP 14 E).

Relative movement and layout of the well test equipment

Because of pressure loss and erosion in the pipes, it is best to keep piping routes as straight as

possible. However, this is not always possible. To facilitate the connection between some pieces

of equipment, the piping layout must combine rigid piping, articulated piping, and flexible hoses.

Additional piping selection criteria include:

Service type

All the rigid piping used should be of H2S service type with welded wing unions connections.

Rubber hoses and articulated piping must be selected in accordance to the service type required

(H2S or non-H2S).

Piping Racks and Baskets

To prevent unwanted accidents, it is highly recommended to use certified racks and baskets

which have been especially designed for storing and transporting piping.

Safety

The following is a list of key safety considerations for piping:

When high flow rates are expected, firmly anchor the flow lines to the rig structure or to the ground.

Hoses must be attached to heavy pieces of equipment because they can swing under pressure. Never try to loosen or tighten connections under pressure. Do not use steel hammers to tighten wing union connections. Brass or copper hammers must be

used to prevent sparks. They must be in good working condition to avoid injuries from metal chips that can break off of these hammers.

After every job, the piping must be thoroughly cleaned to prevent corrosion from well fluids. Before storage, the piping connections must be greased and covered with greased adhesive

tape. Rigid piping must be repainted when necessary to prevent rust corrosion. Thickness measurements on rigid and articulated piping will help to detect corrosion and

erosion and to avoid failures resulting from these problems. In desert locations, do not put grease on the threads. The sand sticks to the grease and prevents

proper connections. Coflexip hoses must be chosen in accordance to the temperature, pressure, and fluid type

expected. Refer to the manufacturer's specifications. Maximum working temperature versus exposure time limits and minimum bending radius

specifications must be respected for Coflexip hoses. For Coflexip hoses, accurate records of pressure and temperature exposure versus time must be

maintained. Each individual piece of piping must be labelled with its working pressure and service type

stamped on a permanently attached metal band. Piping falls under the scope of the Schlumberger Wireline and Testing Pressure Operations

Guidelines.

Maintenance

The basic maintenance of the piping before and after every job consists of:

A visual inspection to check for wear and corrosion of the pipe and the connections. The seals of the connections must be verified and changed when damaged. Threads and sealing surfaces must be cleaned with a wire brush or fine emery cloth. Swivel joints of articulated piping must be checked for leaks. Bearings must be greased or

changed when necessary. Hoses must be maintained as per the manufacturer's recommendations.

A regular maintenance (Q-check) once a year consists of:

All the points listed above. X-ray or ultrasonic inspection of the metal thickness for articulated and rigid piping must be

done especially when submitted to high fluid velocities and sand production. After inspection, the piping must undergo a hydrostatic test at test pressure. Color code piping according to the results of inspection and testing. (The piping color may need

to be changed if working pressure is down-rated as a result of inspection and testing.)

Summary


The different types of piping in used by Schlumberger. How the pressure rating for rigid piping is calculated. The purpose of the Schlumberger color code and the pressures associated with the colors. The guidelines for selecting piping. Some key safety points about piping.

Self Test

1. Why is articulated piping or flexible hoses used between the flowhead and the choke manifold? 2. What is the purpose of the Schlumberger piping color code? 3. How is the piping for a surface testing layout selected? 4. What is important to check regularly on rigid and articulated piping? Why is it important to

check this? 5. How are piping elements connected? 6. How is the seal made for a figure 1002 connection?

SUBSURFACE SAFETY SYSTEM DST

Downhole Testing and Drill Stem Testing

Downhole Testing - Concepts Downhole Testing - Equipment Downhole Testing - Opening the Well Downhole Testing - End of Test Types of DSTs Well Location and Configuration Testing in Openhole Testing in Cased Hole

Downhole Testing

Downhole tests are conducted either in open or cased

hole; but the primary functions are identical:

Target zone isolation Flow control Fluid conveyance Bottomhole data acquisition

Downhole Testing and Drill Stem Testing

Drill stem testing (DST) is a 70-year-old technique employed by the oil companies to check the

potential of a zone to produce as soon as it had been drilled through.

As the drill bit encounters hydrocarbon bearing rocks, traces of hydrocarbons may be detected in

the drill cuttings returning to surface.

The drilling process would then be interrupted, the well conditioned and the drill string pulled

out of the hole.

At surface, the drill bit would be replaced by a compression packer and tester valve - the DST

tools.

The DST tools and drill pipe are run back to the bottom of the hole to perform the drill stem test

(DST).

It is called a drill stem test as most of the drill string that was used to drill the hole was used

during testing.

Today, for safety considerations, drill pipe connections are generally considered to offer

insufficient sealing protection against live hydrocarbons. The drill pipe is most of the time

replaced by proper production tubing which uses pressure tight threaded premium connections.

Therefore the DST technique has shifted more toward a temporary completion, but the name

DST has lived on.

A completion string is the pipe string normally used to produce the well through and bringing the

well effluents to surface.

In 1926, Johnston Testers, which later became part of Schlumberger through various

acquisitions, was already a major player in this business.

The downhole test string is one of the key elements in the well-test package and experience

shows that it is a safe, proven and reliable method of investigating the reservoir. Test objectives,

logistics and cost play a very important part in deciding the type of downhole equipment to be

used during a well test. The downhole test string is an efficient means of temporarily completing

the well while maintaining maximum flexibility. Test tools currently available allow a wide

range of string designs to choose the optimum string either for conventional DST or in

conjunction with a production-type test string.

Test objectives are normally well defined, however Schlumberger test tools allow a large amount

of flexibility, if well-test programs have to be modified in order for these objectives to be met.

This is the key point of a test string: the tool's various functions permit test sequences to be

changed even with the tools downhole, while still maintaining maximum well control.

Use of one or more downhole control valves ensures the well can be secured if problems occur.

In addition, this can be done with the minimum of pipe

manipulation or pressure adjustment. In fact, current

strings can incorporate fail safe systems which, if

problems do arise, will automatically shut in the well.

This well control will be where it is most effective, i.e., as

close to the reservoir as string design allows ; this is in

addition to usual surface and subsurface safety systems.

Downhole Testing - Concepts

Concepts

Pf : Formation pressure Ph : Hydrostatic annulus pressure exerted by the drilling mud (or completion fluid) Pc : Cushion pressure exerted by the fluid placed in the tubing prior to "opening" the tester valve

Pc < Pf < Ph

Downhole testing is affected by three pressures:

Formation pressure (Pf)

The formation pressure is the pressure of the hydrocarbon bearing reservoir to be tested. As

long as the well is not flowing, this pressure is present across the entire reservoir, from its outer

boundaries all the way to the wellbore.

When the well is produced, the pressure in the wellbore will fall below the original formation

pressure due to pressure losses caused by fluid movement in the formation porous media and

through the formation well interface.

Hydrostatic pressure (Ph)

The hydrostatic pressure is exerted by the column of fluid in the annulus. This fluid (drilling mud

or completion fluid) occupies the entire wellbore prior to running the downhole test string.

During the drilling phase of the well, the mud density is normally adjusted to ensure that Ph > Pf

in order to control the formation pressure.

Cushion pressure (Pc)

The cushion pressure is exerted by the column of fluid in the

tubing. Pc is tuned by either adjusting the height to which the

tubing is filled or by filling the tubing with a lighter fluid such

as water / diesel or in some occasions nitrogen gas in order to

have Pc < Pf and enable the well to flow when the tester valve

is opened.

Downhole Testing - Equipment

Equipment

Packer isolates annulus from formation pressure Safety joint Jars Gauge carrier Tester valve

o Isolates cushion from annulus while running in the hole (RIH) o Controls well flow (on/off) o Shuts the well in close to the formation to reduce wellbore storage

Reversing valves enable cushion to be placed in the Tubing and hydrocarbon fluids to be reverse circulated out at the end of the test.

The packer provides a seal and isolates Ph from Pf. A tester valve (located above the packer in the DST string) performs the following main

functions: o Provide a method of well-control near the formation. o Shut the well in downhole to minimize wellbore storage effects. o Isolates Pc from Ph while running in the hole. o Provides a seal for pressure testing the tubing string above the tester valve.

After the packer is set and sealed, the test valve can then be opened and hydrocarbons can be produced to surface. This will only occur if Pc < Ph.

A reverse circulation valve provides a means of removing produced hydrocarbons from the drill pipe or tubing before pulling the DST string out of the hole. During a test, hydrocarbons may be produced. This fluid must be circulated out before pulling out of the hole. For redundancy, two reversing valves are normally run in the DST string. Some types can be opened and can also be reclosed. These types can be used to spot cushion fluids and hydrochloric acid for perforation clean-up treatments.

Pressure and temperature recorders are run to record or monitor bottomhole pressure and temperature versus time. Many different types are available, including mechanical and electronic, and at least two are normally run in the string. These gauges can be run in gauge carriers or placed inside tubing, drillpipe or drill collars for protection.

Additional tools may also be run to enhance string efficiency, safety and versatility. The

following are some of the available tools:

A bypass to minimize swab and surges effects, and equalize pressure across the packer at the end of a test.

Hydraulic jars are run in almost every DST string. If the packer or anchor is stuck, the jars can then be activated. This is done by picking the string up into an overpull. After the delay time, the jar will provide a large upward shock to help free the tool string from the well. This process can be repeated until the tool string is free.

The safety joint is a tool that by pipe manipulation allows the upper part of the string (above the packer) to be recovered if the packer of the anchor becomes stuck and the jar has lost its performance.

Overpressure safety valves prevent the casing in the well from being over pressurized above its design limits.

Slip joints compensate for temperature expansion and contraction of the tubing in the well during the testing phase.

Tubing conveyed perforators (TCP) perforate the casing with large size guns and test the well in a SINGLE trip into the hole. This technique also enables long perforated intervals to be perforated UNDERBALANCED in a single run, whereas wireline conveyed guns would require many descents.

Downhole Testing - Opening the Well

Opening the Well

Pf > Pc: the well will flow Cleanup

o Cushion fluid o Rathole fluid o Formation fluid

Main flow

This is by far the most delicate part of an exploration well test because there is little prior

knowledge of well behavior and fluid nature.

As the test valve is opened, the reservoir pressure is able to overcome the cushion pressure. The

well starts to flow.

During the initial phase of the test, the rat hole fluids, and later the drilling fluids that have

invaded the formation in the vicinity of the wellbore, flow to surface.

This is known as the cleanup period.

On occasions, the well may have difficulties unloading the heavier invasion fluid that has entered

the formation during the drilling process. In this case, it may require nitrogen lifting. This is

performed by inserting a continuous small diameter (1 1/4 in. to 1 3/4 in.) tubing, known as the

coiled tubing (CT), into the test string to a predetermined depth. N2is pumped from surface down

the CT. The N2 exiting into the test tubing lightens up the fluid column to enable the well to

flow. Once lighter hydrocarbons occupy most of the length of the test string, the hydrostatic head

will fall below flowing reservoir pressure and the well will flow naturally. The coiled tubing can

be reeled out of the hole.

Dowell provides coiled tubing services.

The cleanup is completed when the well effluent at surface changes to reservoir fluid which does

not contain leftover mud particles or cuttings.

The main flow period may then proceed for the planned duration during which downhole

pressure measurements and surface flow rates are recorded.

At the end of the flow period the tester valve is closed. Formation pressure builds up against the

valve while downhole pressure measurement continues.

Downhole shut in against a tester valve is preferred to shutting in against a surface flow control

device as it minimizes the well volume to be recompressed (reduced wellbore storage). The

reduced volume to be compressed is a major time saving advantage. It could save up to several

days rig time.

The pressure build up curve obtained is free of wellbore effects and simpler to analyze and

formations with a dual porosity can also be detected.

Downhole Testing - End of Test

End of Test

Open reverse circulating valve "Reverse" out hydrocarbon tubing contents Close reversing valves Open tester valve Pump in test string to "kill" tested interval Unseat packer Pull out of hole (POOH)

At the end of the test, before the packer is unseated, the hydrocarbons left inside the drillpipe or

tubing string above the closed tester valve have to be "reverse circulated out."

This operation is required for safety and environmental reasons to avoid pulling out and

disassembling a test string that contains flammable hydrocarbons which would spill onto the rig

floor or catch fire.

This is achieved by opening a reversing valve which allows annulus fluid to be pumped into the

drillpipe or tubing string and flushes the hydrocarbons to surface where it can be safely disposed.

The test string is now free of any hydrocarbons and can be pulled out of the hole (POOH) safely.

Types of DSTs

DSTs

DSTs can be broadly classified by well type, type of zonal isolation required, location and

deviation.

These conditions will initially dictate the basic type of tool string required. Well test objectives

will influence the selection of individual tools and the final string design.

Well Type

The first parameter is that of well type, which is either openhole, cased hole or barefoot.

Openhole test: Openhole testing tends to be cheaper because costs for casing and cementing are

not incurred. Two of the main problems are those of hole geometry and condition. Hole

geometry will ideally be in gauge, with no irregularities and thus packer sealing potential is

greatly improved.

Openhole sections also limit the application of pressure on the annulus; therefore, the multiflow

evaluator (MFE) string is the only string that can be run in openhole.

Openhole tests are generally limited to a few hours for fear of well bore unstability problems

which may cause the DST string to become stuck.

Two types of packers are available for openhole DSTs:

Compression packers Inflatable packers

Cased hole test: A well with casing cemented in place has the advantage of a known diameter

and shape, thus improving packer seal capability, and will greatly improve the chance of a

successful test.

In cased hole, the test duration can be considerably longer (less chance of sticking), and test

design can be more flexible.

Deviated holes are more easily tested if they have been cased. Both MFE and pressure controlled

tester (PCT) strings are used in cased hole. Wells with leaking casing almost always preclude the

possibility of using pressure-operated tools.

Barefoot test: The barefoot test is used when an openhole section below the casing shoe is to be

tested, the test tools are placed in the casing and a cased hole packer is set in the casing section

above the casing shoe.

This technique is common on production wells where the zone to be tested is above the targeted

production zone and when it must be tested first.

Both MFE and PCT strings can be used for barefoot tests.

Zonal Isolation

In both openhole and cased hole testing, the relationships between depth of the packer, the

formation to be tested and the total depth of the well are important.

If the formation is far off bottom or above another producing zone, the lower part of the well can

be separated from the formation intended to be tested.

This is done either by an inflate openhole tool string or by a retrievable packer and bridge plugs

in cased hole.

Well Location and Configuration

The location of the well and the type of drilling rig used are also considerations in string design.

These can fall into three general categories of rigs:

Land

In a land well the tool string is fixed in relation to the rig (at the packer depth), and thus the

string design can be relatively simple. Both MFE and PCT systems can be used on land.

Offshore fixed (jack-up)

Offshore wells drilled from a fixed rig (a jackup or production platform) can basically the same

conditions as on a land rig although openhole testing is seldom done offshore due to a higher

drilling cost and thus a higher risk.

However, the offshore environment requires extra downhole/subsurface safety valves for well

safety. Although both MFE and PCT strings can be used, the PCT system is recommended

because it incorporates more safety features.

Offshore floater (semisubmersible rigs and drill ships)

The testing of wells from a semisubmersible rig or drillship involves a range of equipment

including slip joints, downhole safety valves sub surface safety valves and a subsurface

disconnecting system (EZ tree).

Since the rig is moving in relation to the zone to be tested, the string is fixed at two points - one

at the packer and the other at the BOP stack which is located at the sea bed. Slip joints are

included in the string to accommodate the string expansion and contraction due to the various

changes in the temperature in the drill pipe or tubing string.

The Pressure Controlled Tester Valve (PCTV) string is ideal for offshore floating rigs; once the

packer is set, no pipe manipulation at all is required until the packer is to be pulled loose again.

The MFE strings is not recommended for floater testing since the rig movement (heave) would

interfere with the reciprocating actions required to operate the downhole tools.

Straight/Deviated

Deviated wells are drilled from a single production site to drain a larger volume of the reservoir.

This minimizes land occupancy onshore and avoids multiple satellite platforms offshore.

Deviated wells or holes with multiple doglegs present difficulties in pipe manipulation.

Reciprocating tools that rely on string weight can be difficult to operate. In deviated holes,

minimum pipe manipulation should be attempted, and thus the PCT strings are more suitable

than the MFE string.

Testing in Openhole

To confirm a doubtful core Were not able to run the repeat formation tester

(RFT) due to well conditions

What is Expected?

Obtain a representative formation sample Good estimation of the flowing and static bottom hole

pressure

Testing in openhole can be done as a very first investigation of the reservoir parameters. This

could be done with logging tools which are faster and more efficient than using DST tools. But

due to hole geometry, it may not be possible to use these logging tools. Therefore the use of DST

tools could be a good alternative. The place where we select a packer seat is above the zone of

interest. Therefore we have to select a good formation give us a good packer seal.

The following are some advantages of an openhole test:

The well does not need to be cased. (The client could decide, based on the results of the test, if it is economically justified to invest in the operation of running casing and cementing this casing in this well.)

Provides a quick way to estimate the formation pressure and types of fluid in this formation. A fluid sample is normally retrieved from the sample chamber which is built into the tool string.

The disadvantage of an openhole DST is due to the fact that the well is not cased, which could

give an unstable wellbore. Therefore there is always a chance that the well could cave-in and the

tool string could become undesirably stuck.

It is very important to observe the following points when performing an openhole DST.

The drilling mud needs to be in good condition. The place where the packer seat is selected needs to be a good formation and in gauge hole

which can support the packer and the differential pressure. The duration of the entire test has to be kept to a minimum to avoid mud settling and the

wellbore caving-in.

These are the main reasons that an openhole DST is no longer very popular. Due to the higher

risks involved, most clients limits openhole DSTs to land

operations.

Testing in Cased Hole

Precise evaluation of reservoir parameters Determine reservoir barriers and limits Interference tests Perforation under drawdown

What is Expected?

Precise and complete reservoir analysis Allows good sampling facilities Allows maximum flow and injection rates

High equipment safety standard

Testing in casing has become more popular over the years. The test design and the test program

can be more flexible. One of the main advantages of a cased hole DST is that there is no

limitation on the duration of the test. There is no chance of the well caving-in. Casing is placed

and cemented in place before the testing phase of the well.

The following are some additional advantages of the cased hole DST:

A precise evaluation of the reservoir parameters. We can first do a cleanup flow. This will remove cushion fluids, drilling mud left below the packer, perforating debris, cementing debris and formation debris from the wellbore.

A determination of the reservoir limits and barriers. This can be done in a long duration test. Interference tests. These tests could be done to check whether this well and a nearby well have

communication through the reservoir. Also the test could last for a longer duration of time. Underbalance perforating TCP is very often used in conjunction with DST tools and could be

time saving.

We expect the following from a cased hole DST:

Precise and complete analysis of the reservoir tested. This can only be achieved if the well has been cleaned properly and the well can be produced for a longer period of time.

To allow good sampling conditions the well needs to be cleaned properly. Samples containing dirt and debris cannot be analyzed properly using PVT. Sampling can be done using sampling tools on wireline or a sampling tool can be build into the DST tool string.

Maximum flow rates can be achieved with fullbore tools and a maximum drawdown pressure. Injection into the well with a treatment fluid like acid to clean the perforations from debris from the drilling damage, mud invation, cementing debris and perforation damage.

PRESSURE CONTROLLED TESTER STRING

Typical PCT String

Flowhead - When testing

a well, surface shutoff is

usually provided by a flow

control head or flowhead

that functions as a

temporary christmas tree. The flowhead is

located on top of the well and is the first piece

of equipment at the surface through which

fluid flows.

Tubing or drill pipe; This pipe will convey the well effluents

to surface.

Slip joints; During a test when well effluents are produced,

the temperature in the string will increase the pipe will

expand. When pumping a cold fluid the pipe will shrink. To

compensate for this we need these slip joints. This tool is

only a telescopic joint they slide in when put in compression

and stroke out when put in tension. Most slip joints have a

stroke of 5 feet some have a 2 feet stroke. More than one

slip joint can be used. In some cases even as many as 5 slip

joints are connected together. The total length of stroke in that case will be 25

feet.

Fully closed

Drill collars; These heavy weight type drilling pipes are placed in the string to

provide weight on the packer. It is most effective when placed as close to the

packer as possible.

Backup reversing valve; In case the lower reversing valve

becomes plugged, the upper valve can be operated. This

valve is operated on a different operating system for

maximum safety.

Drill collars; These are placed here to provide weight on the

packer and to space out between the the two reversing

valves to avoid having debris block the tool from operating.

Reverse circulating valve; Allows the hydrocarbons to be

circulated out of the string at the end of the Testing

program.

Drill collars; These are placed here to provide weight on the

packer and to space out between the the two reversing

valves to avoid having debris block the tool from operating.

Safety valve (optional); Protects the casing from being

overpressured above its rating. The tool can be

permanently closed at a predetermined pressure.

DGA

Pressure recorders; Pressure recorders in combination with

an inductive coupler allows the operator to communicate

with the pressure recorders to be able to monitor flowing

and shut-in pressures from surface in real time. The benefit

of that is if the buildup pressure has stabilized the buildup can be stopped and

rig time saved.

Main downhole tester valve; The valve can be opened and

closed by surface pressure commands. The valve is placed

as close as it is practically possible to the formation we want

to test. This will greatly reduce the volume of fluid we need

to compress to get a pressure built-up.

HRT

Pressure recorders; These recorders are located above the

packer just in case the safety joint has to be activated so

that these pressure recorders are still retrievable and

important data is not lost. This recorder is still located below the tester valve

which also allows you to compare data with the the recorder located below the

packer in the case of debris course plugging.

Hydraulic jar; This tool is an upstroke hammer. If the lower

part of the string becomes stuck; the first option is to

activate the jar in an attempt to release the tool string. If

this is unsuccessful the safety joint could be activated.

Safety joint; This tool is in the string just in case the lower

part of the string or the packer becomes stuck in the

well.We can disconnect from here as a last resort.

Packer; Seals the hydrostatic pressure from the mud in the

annulus from the formation pressure (remember Ph > Pf) .

Perforated tail pipe; Allows the flow of the formation fluids

into the testing string. In case Wireline tools or TCP guns are

used, the formation fluid needs to be able to enter the

testing string.

Pressure recorders; These are used to record bottomhole

pressure and temperature. These pressure recorders are

placed below the packer to record the flowing and shut-in

pressures as close to the formation as possible.

Wireline reentry guide; Lower most part of the string. If

logging tools (i.e., Wireline sampling tools), production

logging tools or Wireline perforating guns are used during a

DST, the reentry guide allows these tools to be pulled back

into the testing string safely without hanging up on sharp edges. It is also

possible to replace the WLRG with a string of tubing conveyed perforating guns.

RESERVOIR FLUID SAMPLING

This training page is divided into the following topics:

Introduction Objectives Basics Summary Self Test References / Other Useful Links

Introduction

Almost all important engineering and economic studies related to oil and gas production

operations are closely dependent on an understanding of the behavior of reservoir fluids. Among

these studies are

oil and gas reserves, recovery factor and field development programs production forecasts, flowing life of wells, completion and lifting systems surface flowlines, separation and pumping center design treatment, processing and refining plants choice of secondary recovery method.

An important concern of every petroleum engineer, therefore, is the quality of the fluid data upon

which these studies are based. Laboratory analysis techniques on reservoir fluid samples provide

the information needed for an accurate understanding of such fluid behavior. Regardless of the

care and sophistication of the laboratory analyses, a collected sample that does not truly

represent the reservoir fluid will not yield useful data.

The purpose of sampling is to obtain a representative sample of the reservoir fluid identical to the

initial reservoir fluid. This condition is absolutely essential because reservoir engineering studies

using pressure-volume-temperature (PVT) analysis data are always made on the basis of the

reservoir at its initial conditions.

Knowing the importance of collecting representative samples of reservoir fluids, the sampling

operations must be performed using state-of-the-art techniques. Sampling is probably one of the

most delicate field operations since it requires not only a solid experience in well testing and the

operational aspects of fluid collection, but also a good understanding of reservoir and production

engineering.

This training page requires that you be familiar with the characteristics and behaviors of

reservoir fluids.

Objectives

Upon completion of this training page, you should be able to complete the following tasks:

Explain the importance of sampling. Describe how the producing conditions can affect the representativity of a sample. Explain the term "well conditioning" and describe the method used to condition a producing

well. List the two hydrocarbon sampling methods. Select one and state the instances when it is used. Demonstrate that the first condition for sampling is a monophasic flow in the reservoir. Write the procedure for obtaining a valid bottomhole sample in a saturated oil reservoir. Explain why bottomhole sampling is not suitable for gas wells.

Basics

This topic outlines the general considerations and procedures for obtaining representative

samples of formation fluids at the surface and downhole. It is divided into the following sections:

Sampling procedures design Sampling of oil reservoirs Sampling of gas reservoirs Sampling of volatile oil reservoirs

Sampling Procedures Design

Representative Samples

The main objective of a sampling procedure is to obtain a representative sample of the original

reservoir fluid. In designing a sampling procedure, we must consider how the reservoir fluids we

are sampling will be affected by the conditions produced during the sampling process.

When the pressure in an oil reservoir drops below the bubblepoint pressure, the solution

vaporizes and forms a separate phase. Similarly, when the pressure in a gas condensate reservoir

drops below the dewpoint pressure, liquid begins to accumulate in the reservoir from the

condensation of the gas. In either case, the minor phase must build up to a certain critical

saturation within the reservoir rock before it will begin to flow. In the meantime, the composition

of the produced fluid is altered by the selective loss of light or heavy hydrocarbons. While the

liquids in a gas condensate reservoir may never reach a saturation when they can flow, the gas

saturation in an oil reservoir will almost certainly reach a point when gas flow occurs. Due to the

relatively low viscosity of gas, this flow of gas will increase rapidly, exhibiting the typical

performance trend of a solution gas drive reservoir.

Even if these phenomena are not reservoir-wide, the pressure drawdown associated with flow

will often be sufficient to drop the pressure of the fluid in the immediate vicinity of the wellbore

below its bubblepoint or dewpoint pressure and into a two-phase region as illustrated in the

Pressure Distribution graphic.

A sample of the diphasic fluid will not be representative of the original reservoir fluid existing

farther out in the reservoir and thus will not be suitable for analysis. Steps must be taken to

determine the reservoir pressure, temperature and the general category of the reservoir fluid. If

the relationship between reservoir pressure and bubblepoint or dewpoint can be estimated, proper

procedures can be applied to ensure that the sampled fluid is representative.

Another concern about obtaining a representative sample is the degree of variation in the original

reservoir fluid located throughout the reservoir. Large reservoirs having thick vertical oil

columns have been known to exhibit variations in fluid properties with depth. Such variations

cannot be accounted for in a specific sample. A pattern must be established from several samples

taken from various wells that were completed at different intervals. In such cases, proper

sampling procedures can ensure that the sample obtained is representative of the reservoir fluid

at the sampling depth and sampling time.

Timing is also an important consideration in obtaining a representative sample of the original

reservoir fluid. Obviously, it makes sense to sample as early as possible in the reservoir's

producing life. Once production creates significant volumes of free gas on a reservoir-wide basis,

it may be impossible to obtain a sample of the original fluid. Often, a reservoir fluid sample is

part of a well-testing procedure that immediately follows the drilling of the first well in a

reservoir. An example would be a newly discovered field where development plans may rely on

the early determination of expected reserves and production rates.

Estimates of fluid properties can be helpful; e.g., bubblepoint pressure (pb) correlations

employed with early test data can determine if undersaturated reservoir fluid exists. If it is,

sampling in that reservoir could be deferred while more testing is done since such reservoir

fluids might be produced for awhile before the free gas phase forms.

Producing Conditions and Equipment

The producing conditions and surface or subsurface equipment have to be considered when

designing a sampling procedure. The following are the most important considerations:

Type of fluid to sample Stability and accuracy of the gas rate, oil rate and gas/oil ratio (GOR) measurements Proximity of the gas-oil contact (GOC) and the oil-water contact (OWC) to the productive

interval Whether the well is a flowing or a pumping well Dimensions (internal diameters) of the downhole equipment

Dry gas reservoirs and highly undersaturated oil reservoirs where the produced fluids remain in a

single phase under any flowing conditions are relatively easy to sample on the surface. An oil

reservoir at or slightly above the bubblepoint will undoubtedly yield free gas at the bottomhole

flowing pressures and will require conditioning prior to sampling as explained in the next

section.

If samples of oil and gas are taken at the surface, it is vital that the producing rates and GORs be

accurately measured in order to recombine the fluids in the correct ratios to formulate a

representative sample. If the well is not producing with stable GORs or if the separation facilities

are not adequate for accurate measurements, a surface recombination sample should not be

considered.

Water production can be troublesome, even in small amounts. If possible, no well that is

producing water should be considered for obtaining a representative hydrocarbon sample.

Nevertheless, a well producing water may be sampled if the sample is taken above the oil-water

contact in the well or in the separator. Sampling in wells where gas coning occurs or may occur

in the production interval should not be done.

Flowing wells are the best candidates for fluid sampling because production rates are easily

controlled and it is practical to measure the bottomhole pressure. In contrast, subsurface

sampling on a pumping well requires the removal of the pump and rods. For obvious reasons,

wells on continuous gas lift are unsuitable for surface sampling procedures, however if a gas lift

well will flow at low rates on its own, it may be conditioned and sampled like any flowing well.

Although the wireline bottomhole sampler is a slim tool, it may not pass through some tubing

restrictions or twisted tubing. Before deciding on a sampling procedure, it is important to check

that the sampler can reach the producing interval.

Well Conditioning

The objective of well conditioning is to replace the nonrepresentative reservoir fluid located

around the wellbore by displacing it into and up the wellbore with original reservoir fluid.

A flowing well is conditioned by successively lowering its production rates until the

nonrepresentative oil has been produced. The production rate is reduced and the GOR measured

until it stabilizes. This procedure is repeated until a trend in the GOR is established. The GOR

may remain constant, decrease or increase.

If the GOR remains constant, the flow into the wellbore is monophasic with undersaturated oil and the well is ready for sampling.

If the GOR decreases, it is the indication of free gas saturation. In the following two situations, correlations can be used to determine the GOR without free gas production.

o This gas may be due to coning. (i.e., The gas from the gas cap flows into the producing interval.) Some light components from the oil phase will move into the gas phase. Therefore, the produced liquid phase (oil) will produce less gas at the surface, thus lowering the GOR. All the light components which are transferred downhole from the oil phase to the gas phase will not be produced in a gas cap well. Therefore, the GOR will be lower at the surface as fewer light components are available.

o This gas may also be due to the flowing bottomhole pressure being less than the bubblepoint pressure.

If the GOR increases, it may be the indication of the simultaneous production of a gas and oil zone. This well should not be sampled because it is very difficult to determine when it will be adequately conditioned.

At low flow rates, some wells produce slugs of liquid followed by gas. This irregular flow makes

it difficult to measure the GOR accurately. Some wells may have such low productivity that even

a low flow rate requires a large drawdown. Reducing the drawdown enough to bring the flowing

bottomhole pressure above the bubblepoint pressure may result in "heading" and may take a very

long time to achieve.

Pumping oil wells are conditioned in the same general manner as flowing wells. If preliminary

correlations show the reservoir fluid to be saturated, the pumping rate should be reduced in order

to increase the bottomhole pressure. After the GOR stabilizes, the well should be pumped for

several days before taking surface samples. If bottomhole sampling is required, the pump is

stopped after conditioning and the rods and pump removed. Then the well is swabbed at a low

rate to ensure a representative fluid at the bottom of the well before the bottomhole sampler is

lowered.

A gas-condensate well is also conditioned by flowing it at successively lower flow rates and

monitoring the GOR. Generally, the GOR should decrease as the rate is decreased, because the

lower rate results in a lower drawdown which brings the wellbore pressure out of the two-phase

region. The heavier hydrocarbons will be produced rather than condensed in the reservoir,

increasing the liquid volume at the surface and decreasing the GOR. When the GOR stabilizes,

the well is ready for sampling.

The duration of the conditioning period depends upon the volume of reservoir fluid that has been

altered as a result of producing the well below the bubblepoint pressure and how quickly it can

be produced at low rates. Most of the oil wells that have not been produced for a long period of

time require little conditioning. However, some wells may require up to a week of conditioning

to achieve stable GORs.

During the conditioning process, careful records should include

flowing bottomhole pressure and temperature (when possible) flowing tubing pressure and temperature oil and gas flow rates separator pressure and temperature stock tank oil production rate water production rate.

Any other information should also be noted such as, equipment malfunction, sudden surface

temperature changes and measurement methods.

Hydrocarbon Sampling Methods

After conditioning the well, samples may be taken with a bottomhole sampler or individual

samples of oil and gas may be taken at the surface and recombined to obtain a representative

reservoir fluid sample. The choice of the sampling technique is influenced by the following

conditions:

volume of sample required type of reservoir fluid to be sampled degree of reservoir depletion surface and subsurface equipment.

BOTTOMHOLE SAMPLING

Bottomhole sampling is the trapping of a volume of fluid in a pressurized container suspended

on a cable inside the well to the productive interval. This method is used in the following

situations:

Only a small volume is required. The oil to be sampled is not so viscous that it impairs the sampler operation. The flowing bottomhole pressure is known to be greater than the reservoir oil saturation

pressure. The subsurface equipment will not prevent the sampler from reaching the sampling depth or

make its retrieval difficult.

SURFACE SAMPLING

Surface sampling usually consists of taking samples of oil and gas at the separator along with

accurate measurements of their respective flow rates, pressures and temperatures. The oil and gas

samples will later be combined in a laboratory to make a representative sample. This method is

often used when:

a large volume of oil and gas are required for analysis, which is the case for gas condensate fluids

the fluid at the bottom of the well is not representative of the reservoir fluid (e.g., gas condensate reservoirs and oil reservoirs producing large quantities of water)

the facilities at the surface, operated by trained personnel, permit the separation of oil and gas and can measure their rates in optimal conditions.

The main difficulty when sampling at the surface arises from the fact that liquid and gas are in a

dynamic equilibrium inside the separator. Any drop in pressure or increase in temperature of the

separator liquid, which is at its bubblepoint, will result in the formation of gas. In addition, any

increase in pressure or decrease in temperature of the separator gas, which is at its dew point,

will result in the condensation of the heavy components. In such a case, a fluid becomes diphasic

during the sampling operation and disproportionate quantities of the two phases will be collected.

Subsequently, the sample will not be representative.

It is also very important that the sampling points be verified to ensure that the fluids to collect

will not be contaminated (e.g., oil or gas condensate carryover at the gas sampling point, water or

sludge at the liquid sampling point).

When a chemical (glycol, methanol, inhibitors, etc.) is injected upstream of the separator, the

injection must be stopped and the sampling operations started only when the chemical is purged

from the separator. If it is impossible to operate without the chemical injection, the chemical

used and the injection rate must be recorded.

Whenever possible, separator liquid and gas samples should be taken simultaneously to obtain

the same sampling conditions for both fluids.

Sampling of Oil Reservoirs

Preliminary Considerations on Oil Reservoirs

In an oil reservoir, the saturation pressure or bubblepoint pressure (pb) may either be equal to the

initial bottomhole static pressure (pwsi) (saturated reservoirs) or below the initial bottomhole

static pressure (undersaturated reservoirs). If a gas cap is found above the oil, the oil is always

saturated.

In undersaturated oil reservoirs, it is possible to produce the well on a small enough choke size to

ensure a flowing bottomhole pressure (pwf) higher than the bubblepoint pressure. There is no gas

liberation and the flow in the reservoir is monophasic.

On the other hand, in saturated oil reservoirs, the flowing pressure is always below the

bubblepoint pressure. The gas in solution in the oil is liberated and may flow through the

reservoir along with the oil. The flow is diphasic.

It is important to note that when oil and gas flow together through the reservoir, the amount of

produced gas is always higher than the initial gas in solution in the oil. The total surface GOR is

calculated by the following equation:

where:

= production gas/oil ratio

= gas in solution in the oil

= oil formation volume factor

= gas formation volume factor

= oil viscosity

= gas viscosity

= gas/oil relative permeability ratio (proportional to the amount of free gas in the

reservoir)

This equation shows that in a monophasic flow, when there is no free gas and krg / kro is equal to

zero, the GOR is equal to Rs and the well stream is identical to the reservoir fluid. This is the

case of undersaturated reservoirs with pwf > pb and new wells (even in saturated reservoirs

producing with small drawdowns) where there is no free gas and initial production has a GOR

equal to Rs.

In a two-phase flow, free gas exists and krg / kro is not equal to zero. GOR is then greater than Rs

and the well stream is different from the reservoir fluid. This is generally the case of saturated

reservoirs.

These considerations show that the first condition to obtain representative samples is a

monophasic flow in the reservoir.

In summary, samples from oil reservoirs are representative when the sampled oil contains

exactly the same amount of gas in solution that was in the solution during the initial reservoir

fluid.

Pre-Job Required Data

To determine whether the fluid flow in the reservoir is monophasic and whether the reservoir is

saturated or undersaturated, we must estimate the bubblepoint pressure and compare it with the

reservoir static and flowing pressures. For this purpose, the following data are necessary:

initial or actual bottomhole static pressure (pwsi or pws) reservoir temperature oil and gas gravities flowing reservoir pressures at one or several flowrates (pwf) initial and actual GOR (or production history for producing wells) at one or several flowrates.

When sampling is to be done without well testing, these data should be supplied to the personnel

in charge of sampling. They are used in conjunction with the following graphic to obtain an

estimation of pb .

This chart, called the Standing correlation chart, can provide an estimate of the bubblepoint

pressure of an oil. Although the estimates of the method are reported to be accurate within ± 5%,

it is widely accepted that if the composition of the oil being tested is considerably different from

the average composition of the Californian crudes used to create this chart, thus deviations even

as high as 20% can be encountered (i.e. the bubblepoint pressure of a volatile oil with actual pb=

3000 psia could be predicted in the 2400 to 2600 psia range). Since the difference between the

initial reservoir pressure and the fluid's saturation pressure can often be as little as a few hundred

psi, conclusions about the estimated bubblepoint should be treated with extreme care and may

need to be further verified using different references.

All these data and other parameters measured during sampling should be indicated on the

sampling data sheet. This form which accompanies every sample is the only source of

information for PVT analyses.

New Wells or Wells in Undepleted Zones

UNDERSATURATED RESERVOIRS

These reservoirs are characterized by

a constant GOR equal to Rs. At very high drawdowns, the GOR may increase because pwf could be lower than pb

a possible estimation of pb by the STANDING correlation and its value of pb < pwsi will confirm that the reservoir is undersaturated.

Bottomhole and surface sampling can be done with the well flowing at stabilized conditions at

any flowrate for which pwf > pb .

SATURATED RESERVOIRS

These reservoirs are characterized by

a GOR only equal to Rs during a very short production period. The GOR increases slightly if the well is produced at constant and low flowrates. It will increase considerably if the drawdown is increased, which can be due to the higher gas liberation in the reservoir

a possible estimation of pb by the STANDING correlation using GORi = Rsi and its value should be close to pwsi

a pb always equal to pwsi if a gas cap exists.

Bottomhole sampling can be accomplished as follows:

The flowrate should be decreased progressively and the well closed. During the flowrate reduction period, pwf increases and free gas redissolves in the oil. When the well is finally close and initial static conditions are reached, the reservoir fluids will be very close to their initial conditions, pb = pwsi .

At these conditions, the well can be sampled. It will be opened at the smallest possible flowrate (1/16" choke) for ten to fifteen minutes and shut in just before the sampler is activated. During this short flowing period, the drawdown will be practically zero and gas liberation will be too small to affect the validity of the samples.

Surface sampling can be done only if, at a minimum stabilized flow, the GOR is very close to the

initial GOR (GORi). Bottomhole sampling should be done at the same time.

Producing Reservoirs or Wells in Slightly Depleted Zones

GOR IS EQUAL TO GORi

In this case, the flow is monophasic and pws > pwf > pb . Surface and bottomhole sampling are

done in the same conditions than for undersaturated reservoirs.

GOR IS GREATER THAN GORi

In this case,the flow is diphasic. The pb should be determined using the initial GORi and

compared with pws and pwf .

If pws > pb > pwf :

Bottomhole sampling can be achieved in the same manner as saturated reservoirs but the time to

reach stabilized conditions could be very long and depends on the depletion of the reservoir.

Surface sampling can be carried out only if it is possible to reach production conditions where

the GOR is very close to GORi . Nevertheless, if surface samples have been taken with GOR >

GORi , they can be recombined in the laboratory to get a reservoir fluid having a specific pb (i.e.,

equal to pwsi ). This procedure is advisable only when the real pb is known but representative

samples cannot be taken.

If pb > pws :

The reservoir is very depleted and the fluid is diphasic. The initial reservoir fluid no longer exists

and it is impossible to obtain representative samples.

For surface samples, the pb can be adjusted in the laboratory as mentioned previously.

Sampling of Gas Reservoirs

Preliminary Conditions on Gas Reservoirs

Gas reservoirs are classified in three categories:

Dry gas reservoirs

In a dry gas reservoir, the gas always remains entirely in the gas phase, whether at reservoir or

separator conditions.

Wet gas reservoirs

In a wet gas reservoir, the gas remains entirely in the gas phase in the reservoir. However at

separator conditions, the well stream will be in two phases, liquid and gas. As the temperature

drops between the reservoir and the separator, the heavier gas components condense as a

liquid.

Gas condensate reservoirs

In a gas condensate reservoir, also called a retrograde condensate reservoir, when the reservoir

pressure drops with production to a point below pd, condensation of the heavier components in

the gas occurs in the reservoir when one would normally expect vaporization. The well stream

composition will vary with pressure and temperature and the production is always in two

phases at separator conditions.

Very often, wet gas and gas condensate reservoirs exhibit very similar behavior which makes it

sometimes difficult to decide which type of reservoir it is solely on the well testing data.

In undersaturated reservoirs, it is theoretically always possible to produce a well when pwf > pd in

order to avoid liquid condensation in the reservoir and to have a well stream identical to the

initial reservoir fluid.

In saturated reservoirs, the production is always with pwf < pd . Liquid deposit is condensed in the

reservoir and the separator GOR increases proportionally to the difference between pwf and pd .

These considerations show that the sampling operation will require flowing conditions with

almost no liquid condensation: GOR = GORi or pwf greater than or very close to pd .

In summary, samples from gas condensate and wet and dry reservoirs are representative only

when they have the total amount of the heavier components contained in the initial reservoir

fluid.

Gas Reservoir Sampling Procedures

It is difficult to distinguish between wet gas and condensate gas reservoirs. The dewpoint

pressure of a gas condensate reservoir cannot be estimated. For this reason, sampling in such

reservoirs should always be done assuming the most unfavorable conditions (i.e., a gas

condensate reservoir where pd = pwsi ).

Sampling in gas reservoirs should always be done at the surface. The separator liquid and the gas

should be recombined in the laboratory.

Bottomhole sampling in a gas reservoir is inappropriate for the following reasons:

The liquid condensed in the bottomhole sampler, when removed from the well, can never be completely transferred from the sampler to the shipping bottle. Very often, the amount of this condensate is very small and during the transfer at atmospheric temperature, part of the condensate will remain in the sampler. Thus, the sample is not representative. Even if the sampler is heated to the reservoir temperature, complete liquid revaporization could take a very long time and be impossible to check at the wellsite. The only solution is to send the sampling chamber to the laboratory.

From a commercial point of view, the liquid phase is of great interest, but its analysis requires a certain easily obtained at the separator but not reasonably achieved with downhole sampling.

In addition to the usual reservoir sampling conditions, the surface sampling of gas wells require

that the liquid condensed in the production string, between the bottom of the well and the

surface, should be completely removed from the well and produced in the separator. This

condition is satisfied only if the gas velocity is high enough. The following graphic shows the

minimum gas flow rates versus wellhead pressure for different tubing sizes.

New Wells or Wells in Undepleted Zones

At initial conditions, gas wells can always be sampled because pwsi is very close to pd and the

gas/liquid ratio is very close to the initial gas/liquid ratio. Therefore, the well stream contains the

total amount of the heavier components found in the reservoir fluid.

Separator sampling should be done with the well producing at the lowest possible flowrate

(minimum drawdown) but meeting the following conditions:

GOR and wellhead pressure should be constant. Homogeneous flow should occur in the tubing. Liquid deposits should be removed with

sufficient gas flow velocity.

Even when pd is equal to or very close to pwsi and when pwf is slightly lower than pd, the samples

are acceptable.

In wells having a very low permeability, pwf may be considerably lower than pd. The samples

taken are considered modified. In this case, representative sampling is not possible.

Producing Reservoirs or Wells in Depleted Zones

The only data to analyze is the gas/liquid ratio.

If GOR = GORi , the well is producing at monophasic conditions in the reservoir and sampling

can be achieved as explained in the previous section, "New Wells or Wells in Undepleted

Zones."

If GOR > GORi , pwf is below pd but there is no way of establishing whether pws is higher or

lower than pd . The research of conditions required for proper sampling is too long to be advised

as a standard procedure. Sampling should be done as previously described, but its validity will be

known only after pd is measured in the laboratory.

Sampling of volatile oil reservoirs

A volatile oil is an oil which contains large amounts of light hydrocarbons that vaporize easily. A

small drop in pressure makes the relative amount of gas to liquid increase rapidly. In some cases,

this type of reservoir can be confused with a gas condensate reservoir due to a high API gravity

of the liquid at separator conditions and a high GOR.

The STANDING correlation cannot be used to estimate pb because this correlation is valid only

with GOR less than 2000 scf/bbl. These reservoirs should be sampled as gas condensate

reservoirs and the PVT analyses will determine the type of fluid collected. If the results of the

analyses show an oil reservoir, bottomhole sampling is possible and can be done following the

procedure for saturated oil reservoirs.

A table summarizing the different sampling cases presented in this topic is shown in the

following graphic.

Summary of Reservoir Fluid Sampling Possibilities and Procedures

Produ

ced

Fluids

Well

Positi

on

R

ef.

Reservoir and

Flow

Characteristics

SAMPLING POSSIBILITIES

AND PROCEDURES Remarks

Bottomhole

Sampling

Surface

Sampling

O

I

New

reserv

oir

or

1

GOR = GORi =

CONSTANT

pwsi > pb

undersaturated

Well flowing with pwf

> pb Stabilized flow

with pwf > pb

L

undepl

eted

zones

reservoirs

2 GOR > GORi

pwsi > pb

saturated reservoirs

- Progressive

reduction of flow

- Well closed until

stabilized

- Sampling with well

producing at

minimum possible

flow rate

- Flow rate

reduction in order

to get GOR very

close to GORi .

- Stabilized flow

with minimum

drawdown.

Case of reservoirs with

gas cap

Produc

ing

reserv

oir

or

deplete

d

zones

3 GOR = GORi =

CONSTANT

pws > pwf > pb Same procedure as in 1

4 GOR > GORi

pws > pb > pwf Same procedure as in 2

Well conditioning could

be very long

and depends upon the

depletion.

5 GOR > GORi

pwf < pb No sampling

possibility

Representative

sampling is not

possible.

Surface samples can be

recombined

in the lab in order to

have pb = pwsi .

G

A

S

New

reserv

oir

or

undepl

eted

zones

6

GOR = constant =

GORi or

GOR very close to

GORi

Not advisable

Smallest possible

flow but

compatible with

homogen

eous flow

in tubing separator

stability.

Dew point (pd) cannot

be estimated but

measured only in the

laboratory, using

recombined surface

samples.

Produc

ing

reserv

oir

or

deplete

d

zones

7 GOR = GORi

Not advisable

Same procedure as

in 6

8 GOR > GORi Same procedure as

in 6

Validity of sampling

will be known after pd

measurement.

Volati

le

oil or

doubt

ful

cases

New

reserv

oir 9

No possibility of

getting any

reservoir

characteristics

from well test data.

Not advisable Same procedure as

in 6

Sample representativity

will be known after PVT

analysis.

Summary

This summary is an overview of the most important points presented in this training page. It is

included to help you review the information. In this training page, we have presented the

following:

Important studies related to oilfield operations Considerations for obtaining a representative sample How producing conditions can affect a sampling procedure Conditioning a well prior to sampling Surface sampling Bottomhole sampling Summary of all sampling scenarios

Self Test

1. List five studies closely dependent on fluid sampling analysis. 2. Well conditioning recommendations prior to sampling are not designed to achieve which of the

following options: o Flowing the well on successively smaller choke sizes o Ensuring the well is clean o Having the reservoir pressure in the wellbore area above the bubblepoint pressure o Gas liberation from the oil occuring in the reservoir during sampling o Obtaining similar GOR's on two successive flow rates

3. What parameters must be recorded during well conditioning? 4. Why is it important to obtain samples as early as possible in the reservoir's life? 5. What precautions should be taken prior surface sampling? 6. Is it possible to obtain a representative sample in a new gas reservoir having a flowing pressure

much lower than its dewpoint pressure? Why? 7. What parameter will you look at prior to sampling a depleted gas reservoir? 8. A reservoir exhibits a GOR higher than 2000 scf/bbl. How can you verify that the samples you

take are representative?

SURFACE SAMPLING


Introduction Objectives Principles of Operation Safety Summary Self Test References / Other Useful Links

Introduction

Surface sampling usually consists of taking samples of oil and gas at the separator along with

accurate measurements of their respective flow rates, pressures and temperatures, as seen in

Figure 1. The oil and gas samples will be combined later in a laboratory commonly called the

pressure-volume-temperature (PVT) lab to make a representative sample. Water samples may

also be taken at the separator.

Figure 1

Surface sampling also involves taking samples of oil, gas and formation water at the wellhead.

Sampling of formation water is covered in a separate training page.

Surface sampling is used when large volumes of oil and gas samples are necessary. Special

analysis of the produced separator gas and oil as well as detailed crude oil evaluation require

substantial quantities (volume) by far exceeding the quantity that can be recovered with a

bottomhole sampling tool. Large volumes of reservoir fluids are also needed when several PVT

analyses must be made for the same formation.

This training page requires that you be familiar with sampling generalities and with the

characteristics and behaviors of reservoir fluids.

Objectives

Upon completion of this training page and the associated practical exercises, you should be able

to complete the following tasks:

List two sampling techniques for oil and two for gas. Discuss how to prepare the well prior to sampling. Explain why oil samples and gas samples should be taken at the same time. Emphasize the importance of the gas/oil ratio (GOR) in surface sampling. Write a procedure for sampling gas at the separator using the vacuum method. Write a procedure for sampling oil at the separator using a piston bottle. Describe the conditions under which sampling is possible at the wellhead. List the typical volume requirements for oil and gas samples. Take an oil and a gas sample using the procedures applicable at the RTC. Carefully complete the sampling sheet for every sample taken.


This topic outlines the general considerations for obtaining a representative surface sample and

describes the most common oil and gas surface sampling methods used in the field. This topic is

divided into the following sections:

Well conditioning Gas surface sampling methods Oil surface sampling methods Special surface sampling cases Wellhead sampling

Well Conditioning

The stable flow period during which the samples are to be taken, should be preceded by a

cleanup period long enough to eliminate the drilling, completion or stimulation fluids. The well

should then be flowed through the separator. The flow has to be very stable and should be set at a

low flow rate, which will create a minimum differential pressure at the formation level. This

flow rate can be determined by flowing the well through different choke sizes. The choice of this

flow rate depends upon the productivity of the well. In high productivity wells, flow rate stability

is easily achieved. In average or low productivity wells, or when the productivity is unknown,

choosing a flow rate that gives regular flow of the two phases (oil and gas) to the separator might

be difficult. In such cases, the flow must be maintained at the minimum steady rate. When the

gas/oil ratio (GOR) is steady (i.e., within 2 to 5%) between two flow reductions, the well is

producing fluids representative of the reservoir. At this point, the stabilized flowing bottomhole

pressure (pwf) is greater than the saturation (bubblepoint) pressure (pb), which ensures a single-

phase fluid at the formation level. The further the well deviates from constant GOR, the greater

the likelihood that the samples will not be representative.

We always try to sample at the end of a flow period when flow rates are stabilized.

Flowing stability can be checked by the following criteria:

stabilized surface gas and oil flow rates stabilized wellhead pressure and temperature stabilized flowing bottomhole pressure (pwf) obtained with a surface readout system.

Surface sampling of a gas condensate well requires another condition: the liquid condensed in

the tubing (between the bottom of the well and the surface) should completely be removed from

the well and produced in the separator. This condition is satisfied if the ascendant gas speed is

high enough. Figure 2 gives the minimum flow rates versus wellhead pressure for different

tubing sizes.

Figure 2

The gas and liquid samples should be taken at the same time or the difference in time should be

as small as possible because significant changes in the separation conditions, particularly the

temperature, can occur over time.

Obtaining accurate values of gas and oil flow rates prevailing at the time of sampling is very

important. The PVT lab has to rely on the reported GOR for the physical recombination of oil

and gas. Inaccurate flow rates applied to valid surface samples lead to invalid recombined fluid.

The following example emphasizes the importance of reporting accurate GOR:

A volatile oil from Africa produced from a reservoir at 214oF was sampled at a separator

pressure of 168 psia and a temperature of 78oF. The reported field GOR was 1200 scf/bbl. If we

assume that the GOR had been underestimated by 5% (actual GOR = 1260 scf/bbl), then

simulation runs show that the two recombined fluids will exhibit the following differences as

indicated in Table 1:

Comparison of Oil Parameters Based on a 5% Difference in GOR Values

Fluid with GOR = 1200 scf/bbl Fluid with GOR = 1260 scf/bbl

Bubblepoint pressure (pb) 2936 psia 3017 psia

Reservoir oil density at pb 0.574 g/cm3 0.563 g/cm

3

Gas Z factor at pb 0.831 0.829

Total GOR from separator test 1512 scf/bbl 1621 scf/bbl

Oil volume factor (Bo) 2.509 2.607

Table 1

Table 1 (above) shows that only a 5% error in measuring the field GOR can cause wide

variances in the obtained PVT data. Therefore, every action should be taken to ensure that the

gas and liquid meters are properly calibrated, that they function well and that all the necessary

information is recorded. Omissions or erroneously recorded data may render the samples useless.

The separator pressure must be adjusted to minimize any liquid carryover at the gas outlet.

Figure 3 helps to determine this pressure according to the theoretical gas capacity of the

horizontal separators.

Figure 3

The following gas and oil surface sampling methods are presented in decreasing sample validity

order, which means that the first method listed is more widely used. At the end of each method,

there are some special concerns about checking the disconnected bottle for leaks, installing

safety plugs, labeling the bottle and completing a sampling data sheet. These concerns are

presented in depth in the Remarks section following the presentation of all the gas and oil surface

sampling methods.

Gas Surface Sampling Methods

Five methods are described in this section. When sampling gas at the surface, enough gas

volume should be collected to allow recombination with oil at reservoir conditions.

The minimum number of separator gas samples in 20-liter bottles depends on the GOR and is

defined as follows:

If the GOR < 1500 scf/bbl, then 2 bottles are required.

If 1500 < GOR < 3000 scf/bbl , then 3 bottles are required.

If the GOR > 3000 scf/bbl, then 4 bottles are required.

Vacuum Method

This technique, the recommended one, requires a vacuum pump on the wellsite with a vacuum

gauge to determine if the bottle is properly evacuated. The minimum vacuum (maximum

pressure) allowed is 10 mmHg (10 Torr), but the recommended vacuum of 1 to 2 mmHg should

normally be obtained before sampling is attempted. It takes approximately 30 to 60 minutes to

evacuate a 20-liter bottle to this recommended void. Warming the container and/or maintaining it

in a vertical position during purging to allow condensation to drain out can reduce the possibility

of accumulating condensed hydrocarbons in the sample as a result of cooling. The connecting

line between the separator and the bottle should be purged with separator gas. Then, the gas is

allowed to flow in the bottle until separator pressure is reached. Figure 4 describes how to

evacuate the gas bottle.

1. The minimum vacuum allowed is 10 mmHg (10 Torr), however, the recommended vacuum is 1 to 2 mmHg. It takes approximately 30 to 60 minutes to evacuate a 20-liter bottle.

Figure 4

Figure 5 illustrates the vacuum method for gas sampling. Figure 5 also shows the status of the

equipment at the end of step 8.

1. Connect the top of the bottle to the separator gas sampling outlet line.

2. Start with all valves closed. 3. Open valve 1, 2 and 3. The pressure gauge should read the separator

pressure. Close valve 1. 4. Open valve 1, then close valve 1. Open valve 4 to drain gas. Close valve

4. Check for leaks. Repeat this step five times. 5. Open valve 1. The pressure gauge should read the separator pressure. 6. Crack open valve 5 to slowly fill up the gas bottle (approximately 10

minutes for a 10-liter bottle). There should be no appreciable pressure drop at the pressure gauge.

7. When the approximate filling time is completed, check the pressure gauge. It should read the separator pressure. Open valve 5 completely. The pressure reading should not change.

8. Close valve 5 and valve 2. Open valve 4 to drain gas. The pressure gauge should read zero. Close valve 4.

9. Open valve 5. If the gauge does not read the separator pressure, valve 5 is partially plugged and the bottle is not full. Continue sampling by starting again with step 6.

10. If the gauge reads the separator pressure, close valve 5, then valve 1. Open valve 2. Open valve 4 to drain the gas.

11. Disconnect the bottle. Verify that there are no leaks at the valves. Install the safety plugs and label the bottle. Complete the sampling sheet.

Figure 5

Mercury Displacement Method

This method is decreasingly used due to the stringent environmental regulations about mercury.

The bottle, which must be made of steel, is filled with mercury and its top valve connected to the

separator gas sampling outlet line. The bottom valve is slowly opened to drain the mercury in a

graduated flask. The gas enters at the top of the sampling bottle and the mercury flow rate is

carefully controlled by the bottom valve to avoid any drop in pressure. The pressure is read by a

gauge connected at the bottom valve of the bottle. This valve is closed when all but 20 to 30cc of

mercury is collected in the measuring flask. Figure 6 illustrates this technique and shows the

status of the equipment after step 7.


2. Start with all valves closed. 3. Open valve 1, then close valve 1. Open valve 3 to drain the gas from

the line. Then, close valve 3. Check for leaks. Repeat this step five times.

4. Open valve 1, then valve 4. Wait a few minutes for pressure stabilization.

5. Open valve 5, then valve 6. The pressure gauge should read the separator pressure plus approximately 6 psi (mercury hydrostatic head).

6. Slowly open valve 7 to ensure that no appreciable pressure drop at the pressure gauge exists.

7. Let the gas slowly displace all but 20 to 30cc of mercury, which should take approximately 20 minutes depending on the bottle volume.

8. Close valve 7. Wait a few minutes for pressure stabilization. 9. Close valve 4, then valve 1. Open valve 3 and check for leaks. Then,

close valve 3. 10. Close valve 5. Open valve 7 to drain the mercury left in the bottom

line.

11. Disconnect the bottle. Verify that there are no leaks at the bottle valves. Install safety plugs and label the bottle. Complete the sampling sheet.

Figure 6

Air Displacement and Purging Method

This technique consists of filling a bottle with the separator gas by opening the top valve of the

bottle and purging it by throttling with the bottom valve. The container should be kept warm

(i.e., at separator temperature) during the purge to avoid any condensation of the gas in the bottle

in which case the sample will not be representative. When several bottle volumes of gas have

been purged through the bottle, the sample is collected. Figure 7 describes this method. This

figure also shows the status of the equipment at the end of the procedure.


2. Start with all valves closed. 3. Open valve 2 and valve 3. 4. Open valve 1. The pressure gauge should read the separator

pressure. Note this reading. Close valve 1, then open valve 4 to drain gas. Close valve 4. Check for leaks. Repeat this step five times.

5. Slowly open valve 5. 6. Slowly open valve 1 until the pressure gauge reads 75% of the

separator pressure. Close valve 1. 7. Open valve 6 to drain gas to atmospheric pressure. Close valve 6. 8. Repeat steps 6 and 7, seven times (twelve times if the separator

pressure is below 100 psi). 9. Slowly open valve 1 and fill the bottle to 100% separator pressure. 10. Close valve 5. 11. Close valve 2 and open valve 4 to drain gas. The pressure gauge

should read zero psi. Close valve 4. 12. Open valve 5. If the gauge does not read the separator pressure,

valve 5 is partially plugged. Continue sampling by starting again at step 5.

13. If the gauge reads the separator pressure, close valve 5, then valve 1. Open valve 2. Open valve 4 to drain gas.


Figure 7

During the purging procedure, the bottle is filled up at 75% of separator pressure to avoid

condensation. This is especially important when it is not possible to heat the bottle to separator

temperature. The filling procedure has to be slowed down or stopped and restarted when there is

significant cooling across valve 1.

Air Displacement and Circulating Method

This method consists of circulating a certain amount of separator gas through the bottle before

taking the sample. The setup is similar to the "Air Displacement and Purging Method," but a gas

or air flowmeter or a gas meter is attached to the bottom valve of the bottle to measure the

volume of gas passing through the bottle. A transparent tube is used to connect the meter and the

bottle.

The following equations develop the calculations necessary to obtain the volume of gas to

circulate using this sampling method. The volume of the gas needed is calculated as ten times the

product of absolute pressure and the volume of the bottle in a coherent unit system. The

following sample calculation uses liters and atmospheres.

Figure 8 illustrates this technique and shows the status of the equipment at the end of step 7.

1. Connect the bottle as shown. 2. Start with all valves closed. 3. Open valves 2 and 3. 4. Open valve 1. The pressure gauge should read the separator pressure.

Close valve 1, then open valve 4 to drain gas. Close valve 4. Check for leaks. Repeat this step five times.

5. Open valve 1, then slowly open valve 5 to maintain the smallest possible pressure drop.

6. When the bottle pressure at the gauge reaches the separator pressure, open valve 6.

7. Let gas circulate until the volume required by calculation passed through the meter.

8. Close valve 6 and wait for pressure stabilization. 9. Close valve 5 and valve 1. 10. Open valve 4 to drain gas from the top line.

11. Disconnect the bottle. Verify there are no leaks at the valves. Install

Figure 8

the safety plugs and label the bottle. Complete the sampling sheet.

If it is not possible to maintain the bottle at separator pressure during gas circulation and/or

condensate is appearing at the bottom valve, the circulation must be performed at a lower

pressure (e.g., 75% of separator pressure). This is done by controlling the flow at the separator

output (valve 1) and at the bottle lower valve (valve 6). If a significant cooling of the control

valves occurs, purging should be reduced or stopped temporarily. When the volume calculated is

attained, the bottom valve is closed, the pressure on the gauge rises to the separator pressure and

the top valve is closed.

Water Displacement Method

This method is similar to the mercury displacement method, the bottle being initially filled with

water and bled off slowly as the sample of gas is collected.

The major problem with this method is sampling fluid which contains H2S or CO2 or both. These

corrosive gases are easily absorbed by water and will react with steel containers. The

concentrations of these gases read at the wellsite will certainly be different than those read at the

PVT lab. Thus, the type of water used is very important to minimize these liabilities and the

following three possibilities are given in order of decreasing reliability:

Separator water

This is the best choice if the well is producing water at the surface

because this water is already saturated with separator gas. After

ensuring that no hydrocarbon liquid (oil or condensate) is produced at

the separator water tapping point, the sample bottle should be filled

by gravity from the bottom with water at the separator pressure. It

may not be possible to install the bottle below the water output of the

separator, but the separator pressure should be sufficient to make the

water flow. Before filling up the bottle, water is circulated for five (5)

bottle volumes as shown in Figure 9 (right). Take note that the

pressure gauge is attached to the lower valve of the bottle as it is for

oil sampling. Figure 10 (below) illustrates the water displacement

method and also shows the status of the equipment at the end of step

7.

Figure 9

1. Connect the bottle as shown. 2. Start with all valves closed. 3. Open valve 2 and valve 3. 4. Open valve 1. The pressure gauge 1 should read the separator

pressure. Close valve 1. Open valve 4 to drain gas. Close valve 4. Check for leaks. Repeat this step five times.

5. Open valve 1. The pressure gauge 1 should read the separator pressure.

6. Open valve 5, 6 and 7. The pressure gauge 2 should read the separator pressure.

7. Slowly open valve 8 and bleed off water maintaining the pressure gauges 1 and 2 at the separator pressure. If the bottle temperature is below the separator temperature, leave 2% of the water in the bottle to avoid losing any condensate which may have formed during filling. Otherwise, bleed water until the first gas bubbles appear at valve 8.

8. Close valves 6 and 5. 9. Close valve 1 and open valve 4 to drain gas from the top line.


Figure 10

Salt water

This can be seawater or fresh water saturated with sodium chloride. This method is used only if

the water cut is zero. The salt water will reduce the amount of light components from the gas

that pass into solution. The setup is identical to the separator water procedure except that this

method has no bottom pressure gauge and valves 7 and 8 disappear. This procedure also starts

by purging the top line. The following steps illustrate this procedure:

1. Connect the bottle as shown. 2. Start with all valves closed. 3. Open valve 2 and valve 3. 4. Open valve 1. The pressure gauge should read the separator pressure. Close valve 1. Open valve

4 to drain gas. Close valve 4. Check for leaks. Repeat this step five times. 5. Open valve 1. The pressure gauge should read the separator pressure. 6. Slowly open valve 5. 7. Slowly open valve 6 to bleed off salt water. Maintain the sampling pressure between two and

three times atmospheric pressure (30 to 40 psi) with valve 6. This pressure should be well below the separator pressure since it prevents the dissolving of too much gas components in the water. The amount of dissolved gas is directly proportional to the pressure. The drawback is that the gas will likely be in the two-phase region and therefore part of the heavy components will be lost.

8. Close valve 6 when gas appears.

9. Allow pressure to build up to separator pressure. 10. Close valve 5, then valve 1. Open valve 4 to drain gas from the top line. 11. Disconnect the bottle. Verify that there are no leaks at the valves. Install the safety plugs and

label the bottle. Complete the sampling sheet.

Fresh water

Preferably not used when H2S or CO2 or both are present in the effluent. The water cut must be

zero and the procedure is similar to the previous one with all water bled off during sampling.

Fresh water does not prevent the lightest components of gas to dissolve into solution and thus

modifying its composition.

Table 2 summarizes the gas sampling methods presented in this section.

Summary of Gas Surface Sampling Methods

D

E

C

R

E

A

S

I

N

G

S

A

M

P

L

Methods Advantages Drawbacks Field of

Application Equipment

Filling under

vacuum

- No heating

- Fast

- High volumes

sampled

Vacuum pump

and gauge

needed

No limits

- Vacuum pump

- Manifold + valves,

vacuum gauge and

pressure gauge

Mercury

displacement

- No heating

- No vacuum

pump

- Only stainless

steel bottles can

be used, and may

be of low

volume

- Reaction between

mercury, H2S

and other sulfur

compounds

- Large volume of

mercury needed

No limits

- Mercury

- Flasks

- Stainless steel

bottles

- Maniford + valve and

pressure gauge

- Safety equipment

Air

displacement

- High volumes

sampled

Risk of

condensation

No limits

- Flowmeter

- Manifold + valve and

E

V

A

L

I

D

I

T

Y

(a) Purging

(b) Circulation

- No vacuum

pump

due to cooling pressure gauge

- High volumes

sampled

- No vacuum

pump

Risk of

condensation

due to cooling

No limits

- Flowmeter


pressure gauge

- Heating system

Water

displacement

(a) Separator

water

(b) Salt water

(c) Fresh water

- High volumes

sampled

- No vacuum

pump

- Long duration

No limits


pressure gauge

- Separator water

- Flasks

- High volumes

sampled

- Long duration

- Possible change

of composition

Preferably with

no H2S or CO2

present


pressure gauge

- High volumes

sampled

- No vacuum

pump

- Long duration

- Possible change

of composition

Preferably with

no H2S or CO2

present


pressure gauge-

Table 2

Oil Surface Sampling Methods

As stated earlier in this training page, several methods exist to obtain oil samples at the surface.

They are described in this section.

As a precautionary measure, make sure that the upper and lower valves of the separator oil sight

glass are closed prior to its attachment.

The number of oil samples may vary with the client's needs but a minimum of three oil bottles of

around 600cc each is necessary to ensure representativity and sufficient quantity for a normal

PVT study.

All oil surface sampling methods intend to keep the separator liquid at or above its bubblepoint

pressure until it is transferred inside the sample bottle. This is achieved by keeping the sample at

separator pressure and at or below separator temperature.

The temperature of the sample should be maintained at or below the separator temperature to

prevent gas liberation from the oil which could interfere with the bottle filling operation. When

the separator temperature is below the ambient temperature, the sample bottle should be cooled

either in water or in an ice and water mixture or in an ice, salt and water mixture.

Mercury-Free Displacement Method

This method is more and more widely used as it permits the elimination of mercury usage in the

field. Thus, all the environmental and safety constraints concerning mercury are taken away. It is

Schlumberger's recommended procedure.

This technique involves a sampling bottle equipped with a piston which separates the sample

from the displacing fluid initially set at a pressure higher than the separator pressure to avoid a

flash liberation in the bottle. The displacing fluid (hydraulic oil) is noncompressible and replaces

the mercury. The piston bottle features a very low dead volume on the sample side which needs

to be vacuumed before starting the sampling procedure.

Figure 11 describes the piston bottle preparation and the sampling technique. Figure 10 also

shows the status of the equipment at the end of step 11. Note that in this sampling method, valve

5 is black and valve 6 is blue.

1. Start with all valves closed. Open valves 3, 4, 5, 6, 7, 8 and 9. Drain some hydraulic oil through valve 9.

2. Close valve 9 and activate the hydraulic pump to pressurize the bottle 1000 psi above the pressure of the oil to be sampled. Close valve 8.

3. Slowly open valve 2 and flush the top line to the bucket. Close valve 3. 4. Connect a vacuum pump to valve 4. Create a vacuum on the line

between valve 3, the dead volume in the bottle and the vacuum pump. Close valve 4 and remove the pump.

5. Open valve 3. 6. Slowly open valve 9. The pressure at the gauge should drop to the

separator pressure. Drain 660cc of hydraulic oil, which should take approximately 20 minutes. Then, close valve 9.

7. Wait for pressure stabilization. Close valves 2 and 5. 8. Open valve 4 and bleed off the top line. Measure the bottle

temperature. 9. Slowly open valve 9 and drain another 70cc of hydraulic oil to create a

10% gas cap in the bottle for safe transportation. 10. Close valve 9. Note the new pressure on the pressure gauge and the

temperature of the bottle.

11. Close valve 6. Disconnect the bottle. Verify that there are no leaks at the valves. Install the safety plugs and label the bottle. Complete the sampling sheet.

Figure 11

The following multimedia provides a dynamic view of the preparation, operation and quality

assurance of oil sampling with a piston bottle.

Surface Oil Sampling with a Mercury-Free Bottle Multimedia

Objective: To learn about the preparation, operation and assurance of surface oil sampling

Comment: This multimedia depicts the surface sampling of oil with a mercury-free bottle. It

describes the preparation of the bottle, the sampling of oil without H2S, the sampling of oil

containing H2S and the quality assurance check to ensure the sample integrity. Oil is transferred

from the separator to the sample bottle for pressure-volume-temperature (PVT) analysis.

This animation does not demonstrate the difference between the non-H2S and the H2S operation.

Mercury Displacement Method

Despite the fact that this method produces excellent results, it is decreasingly used due to the

more stringent environmental regulations about mercury.

The sampling bottle must be made of steel. The bottle that will contain the oil is first filled up

with mercury and connected to the sampling point at the separator oil sight glass. The mercury is

then slowly withdrawn from the bottle and replaced by the oil coming from the separator. The

volume of the bottle is known and the flask used to drain the mercury is graduated so it is easy to

control the quantity of oil in the bottle. Figure 12 describes how to fill up the bottle with

mercury. Water covers the mercury to prevent mercury vapors from escaping. Figure 11 also

shows the status of the equipment after step 1.

1. The bottle is held vertically. Open valve 4, then valve 5. 2. When the mercury overflows, close valve 5, then valve 4. 3. Tilt the bottle to evacuate the mercury trapped at the top of valve 4. 4. Disconnect the upper tube. 5. Lower the mercury container or lift the sampling bottle to have valve 5

above the mercury level in the container.

6. Disconnect the lower tube.

Figure 12

Figure 12 illustrates the mercury displacement method. At the end of the procedure, an extra

amount of mercury (i.e., 10% of the oil volume contained in the bottle) is removed to create a

gas cushion (gas cap) for safety reasons. As the gas is highly compressible, it will absorb any

expansion of the oil that can be caused by an exposure of the bottle to high temperatures during

shipment, which eliminates the risk of explosion. For example, a 500cc bottle full of oil which is

submitted to a change of 30oC will see an increase of pressure inside the bottle exceeding 4500

psia.

Figure 13 shows the status of the equipment at the end of step 11.

1. Connect the top of the bottle to the separator oil sight glass. 2. Start with all valves closed. 3. Open valve 1, then valve 2 to allow fresh oil to come to the oil sight

glass. Close valve 1, then valve 2. 4. Open valve 1, then close valve 1. Open valve 3 to drain the oil from the

line. Then, close valve 3. Check for leaks. Repeat this step five times. 5. Open valve 1, then valve 4. Wait a few minutes for pressure

stabilization. 6. Open valve 5, then valve 6. The pressure gauge should read the

separator pressure plus approximately 6 psi (mercury hydrostatic head).

7. Slowly open valve 7 to ensure that no appreciable pressure drop at the pressure gauge exists.

8. Let the oil slowly displace 550cc of mercury, which should take approximately 20 minutes depending on the oil viscosity.

9. Close valve 7. Wait a few minutes for pressure stabilization. 10. Close valve 4, then valve 1. Open valve 3 and check for leaks. Then,

close valve 3. 11. Open valve 7 and drain 55cc of mercury to provide a 10% gas cap for

transportation. Record the new pressure at the pressure gauge and the temperature of the bottle.

12. Close valve 5. Disconnect the bottle. Verify that there are no leaks at the bottle valves. Install safety plugs and label the bottle. Complete the sampling sheet.

Figure 13

Displacement and Equilibrium with Separator Gas Method

This method is used when low viscosity fluids (condensates and volatile oils) must be sampled

when mercury-free bottles are not available and when mercury sampling is forbidden . Prior to

sampling, the bottle should be filled up with separator gas using either the vacuum method or the

air displacement and purging method, both found in the Gas Surface Sampling section. Figure 14

illustrates the Displacement and Equilibrium with Separator Gas method and shows the status of

the equipment at the end of step 8.

1. Connect the bottle to the separator oil sight glass as shown. 2. Start with all valves closed. 3. Open valve 5, then valve 6 to allow fresh oil to come to the oil sight

glass. Close valve 5, then valve 6. 4. Open valve 5, then close valve 5. Open valve 7 to drain oil from the

line. Close valve 7. Check for leaks. Repeat this step five times. 5. Open valves 1 and 2 to allow gas to come inside the bottle. 6. Open slowly valves 4 and 7 to flush the bottle with gas. Close valve 7. 7. Open valve 5. The gas contained in the bottle is displaced by the

liquid. 8. Adjust the height of the bottle such a way that 10% of the bottle

volume is left for a gas cap. 9. Wait five minutes for stabilization. The pressure gauge should read the

separator pressure. 10. Close valves 2, 4, 5 and 1. 11. Open valve 3 to drain the top line. Then, close valve 3. 12. Open valve 7 to drain the oil from the bottom line. Then, close valve 7.

13. Disconnect the bottle. Verify there are no leaks at the bottle valves. Install safey plugs and label the bottle. Complete the sampling sheet.

Figure 14

Gas or Air Displacement Method

This method is used when low viscosity fluids (condensates and volatile oils) must be sampled

when mercury-free bottles are not available and when mercury sampling is forbidden . High

viscosity fluids will not flow properly by gravity. The bottle initially contains air or separator

gas. The 10% gas cap is made by releasing, as quickly as possible, 10% of the bottle volume of

liquid at the bottom valve. Figure 15 illustrates this technique and shows the status of the

equipment after step 8.

1. Fill the bottle with separator gas using the "Gas Sampling: Air Displacement and Purging Method" (at least 7 times at 75% of separator pressure and up to 12 times if separator pressure is less than 100 psi).

2. Connect the bottle as shown. 3. Start with all valves closed. 4. Open valve 1, then close valve 1. Open valve 3 to drain the oil from the

line. Then, close valve 3. Check for leaks. Repeat this step five times. 5. Open valves 1, 4, 5 and 7. Wait until the pressure gauge reads the

separator pressure. 6. Slowly open valve 6. 7. Purge three oil bottle volumes through valve 6. This is to avoid any

two-phase segregation during filling. 8. Close valve 6, then valve 1. The pressure gauge is still at separator

pressure. 9. Open valve 3 to release 10% of liquid volume to create a 10% gas cap.

Close valve 3. Note the new pressure at the gauge.

Figure 15

10. Close valves 5 and 4. Open valves 3 and 6 to bleed off pressure in the lines.

11. Disconnect the bottle. Verify there are no leaks at the bottle valves. Install safety plugs and label the bottle. Complete the sampling sheet.

Water Displacement Method

This method is similar to the mercury displacement method, except that the bottle is initially

filled with water and bled off slowly as the sample of oil is collected.

The major problem with this method is sampling fluid which contains H2S or CO2 or both. These

corrosive gases are easily absorbed by water and will react with steel containers. The

concentrations of these gases read at the wellsite will certainly be different than those read at the

PVT lab. Thus, the type of water used is very important to minimize these liabilities and the

following three possibilities are given in order of decreasing reliability:

Separator water

This is the best choice if the well is producing water at the surface because this water is already

saturated with separator gas.

Salt water

This can be seawater or fresh water saturated with sodium chloride.

Fresh water

Preferably not used when H2S or CO2 or both are present in the effluent.

Table 3 summarizes the oil sampling methods presented in this section.

Summary of Oil or Condensate Surface Sampling Methods

D

E

C

Methods Advantages Drawbacks Field of

Application Equipment

Displacement

using a piston or

membrane-type

bottle

No mercury

- Vacuum pump

and gauge needed

- Dead volume

No limits

- Vacuum pump and

gauge

- PSR-F or membrane-type

bottle

- Flasks

- Hydraulic oil and pump

- Maniford + valves and

R

E

A

S

I

N

G

S

A

M

P

L

E

V

A

L

I

D

I

T

Y

pressure gauge

Mercury

displacement

Liquid sample

under

monophasic

conditions

- Mercury safety

- Reaction

between

mercury, H2S

and other sulfur

compounds

No limits

- Mercury

- Flasks

- Stainless steel bottles

- Manifold + valves and

pressure gauge

Displacement

and equilibrium

with separator

gas

No mercury

Slight modification

of liquid

composition

due to gas cap

must

be reported.

Liquid of low

viscosity

- Flasks



pressure gauge

Gas or air

displacement

- No mercury

- Easy

sampling

Risk of slight

modification of

liquid composition

due to gas cap

formation

technique

No limits

- Flasks



pressure gauge

Water

displacement

- No mercury

- Liquid sample

under

monophasic

conditions

Reaction between

CO2, H2S and

water

Not to be used

if

CO2 or H2S

present

- Flasks



pressure gauge

Table 3

Remarks

The last step of every method presented mentions that the bottle should be verified for leaks,

which simply consists of immersing both valves of the bottle in a bucket of water and looking for

bubbles. If a leak is detected for an oil or condensate sample, the sample is invalid and sampling

should be repeated. A leaking gas bottle should also be rejected unless the leak is cured before a

significant quantity of gas is lost and the bottle pressure is still within 2% of the separator

pressure. This leak test is illustrated in the "Surface Oil Sampling with a Mercury-Free Bottle"

multimedia.

This step also describes that the bottle must be sealed with the safety plugs (two or four

depending on the bottle type) screwed on both valves. These valves are secured with a wire

closed by a lead seal so that opening the valves will deliberately break the wire. The "Surface Oil

Sampling with a Mercury-Free Bottle" multimedia covers these points as well.

It is also very important to label the bottle as soon as sampling is achieved. This is done by

placing a label inside the wire loop. This label indicates that the bottle is full. In case of H2S,

another label marked "H2S" is inserted through the wire. Figures 16 and 17 show gas and oil

valves sealed with the wire and label attached to them.

Figure 16

Figure 17

The bottles used in the recommended Schlumberger sampling techniques are further described in

the gas sampling bottle (SBG-C) and oil sampling bottle (PSR-F) and (PSRA-F) training pages.

Finally, a sampling data sheet containing all the pertinent information regarding the sampling

operation must be properly filled out and one copy will accompany the bottle. A typical sampling

data sheet is shown in Figure 18.

Figure 18

Special Surface Sampling Cases

Hydrogen Sulphide and Carbon Dioxide

H2S and CO2 concentrations in a sample can change due to reaction, adsorption or absorption

during sampling, transportation and storage. Laboratory analyses frequently report reduced

concentrations because of these phenomena.

H2S and CO2 can react chemically with the steel containers especially if water is present.

Concentration measurements of these gases must be performed at the wellsite immediately after

sampling to prevent their losses from the fluid's composition which could render a sour sample

into a sweet sample.

For gas samples, a way to reduce this problem is to fill the container with the gas to be sampled

and allow some time for the walls to be saturated with the absorbed gases before it is evacuated

and filled again with the sample. Then, the concentrations will be much less affected.

Multistage Separation System

In the case of multistage separation (more than one separator in use), gas and liquid samples

must be taken from the first (high pressure) separator. In some circumstances, liquid samples

could be taken from lower pressure separators, but only if samples of gas are taken from all

higher pressure separators. All gas flow rates must be measured.

Wellhead Sampling

Wellhead sampling is not recommended because it usually implies to work with high pressures

and high flowrates. In addition, it is difficult to know what phase of the flow is collected.

Sampling at the separator is much safer and gives more chances to obtain representative samples.

The following paragraphs describe in which conditions oil and gas samples can be obtained at

the wellhead.

Oil Sampling

Oil sampling at the wellhead is only possible when the wellhead pressure is higher than the

bubblepoint pressure at the wellhead temperature. This condition may be achieved with low flow

rates but a good estimate of the bubblepoint pressure is needed.

It is recommended to take separator samples at the same time if an unexpected diphasic flow

occurs at the wellhead giving non representative samples.

Common sampling methods should be used but it is very important to verify that the equipment

(e.g., bottles, valves, gauges and lines) is rated with a working pressure above the wellhead

pressure.

Gas Sampling

Gas sampling at the wellhead is suitable for dry gas wells where no liquid is formed in the

separator. In this case, a wellhead sample will be identical to a separator sample.

For gas condensate wells, since they usually produce two phases at the surface, this technique is

possible only when monophasic flow is expected at the wellhead, but separator samples should

be taken anyway.

Common sampling methods should be used (e.g., usually the vacuum method) but as for the oil

sampling at the surface, verify that the equipment is rated for a working pressure higher than the

wellhead pressure.

Safety

The following is a list of key safety considerations for surface sampling:

A primary consideration is the need for a vapor space within the liquid sample (i.e., a gas cap). Thermal expansion of the liquid could cause the container to exceed its pressure limits if the temperature rises. An average increase of 1oC (1.8oF) increases the pressure inside the bottle by 10 kg/cm2 (142 psi).

Sample containers should be kept at reasonable surface temperatures and not stored in direct sun or placed in hot areas.

Care must be taken to protect the container, especially the end valves, during shipping and handling. End protectors must be used.

The valves on each end of the sample container must be fitted with safety plugs to prevent accidental opening during transportation.

When samples contain toxic gas like H2S, it must be labeled on the bottle. Pressure ratings of the bottles, connections, valves and fittings must be strictly observed. Every effort should be made to avoid using mercury due to its high toxicity and to its property of

forming irreversible organometallic compounds when found in high concentrations in living species.

If sampling with mercury, strictly follow the safety rules and procedures. If sampling gas with with mercury, do not use an aluminium-alloy bottle. Mercury corrodes

aluminium and forms an amalgam. Before using any sampling bottle, verify that the official pressure test is not overdue. It is a good

practice to have a safety factor of six months for transportation and storage delays. Vacuum pump and vacuum gauge are not classified as explosion proof equipment. Therefore

they must be used in safe areas. Whenever H2S is expected or suspected, strictly observe all H2S safey rules. Government regulations concerning the transportation of flammable and pressurized fluids

must be followed (Department of Transportation (DOT) and International Air Transport Association (IATA)).

All sampling equipment falls under the scope of the Schlumberger Wireline and Testing Pressure Operations Guidelines.

Summary



following:

Well conditioning prior to surface sampling Gas surface sampling methods

o Vacuum method o Mercury displacement method o Air displacement and purging method o Air displacement and circulating method o Water displacement method

Oil surface sampling methods o Mercury-free displacement method o Mercury displacement method o Displacement and equilibrium with separator gas method o Gas or air displacement method o Water displacement method

Special surface sampling methods Safety points about surface sampling

Self Test

1. What is the purpose of the cleanup period? 2. Why should a well be produced at a constant GOR prior sampling? 3. How do you determine the proper flow rate for sampling? 4. What parameters do you monitor to ensure a stable flow? 5. Why should oil and gas samples be taken at the same time? 6. Why does the sampling procedure with a piston bottle recommend pressurizing the bottle at a

pressure higher than the separator pressure? 7. Why is it very important to create a gas cap in oil bottles? 8. Describe the oil sampling method using a piston bottle. 9. Examine the gas sampling method using salt or fresh water and discuss its liabilities. How can we

minimize them? 10. When sampling oil in a bottle at a temperature higher than that of the separator, which natural

process occurs? Condensation or vaporization?

WATER SAMPLING


Introduction Objectives

Principles of Operation Equipment Safety Summary Self Test References / Other Useful Links

Introduction

The goal of sampling water from the formation is to obtain a representative water sample which

will be analyzed to obtain either its various chemical or physical properties or both. The

chemical analyses of waters produced with oil are very useful in oil production problems such as

identifying the source of intrusive water, planning waterflood and saltwater disposal projects and

treating the water to prevent corrosion problems. Electrical logging interpretation requires a

knowledge of the dissolved solids concentration and composition of the interstitial water. The

formation water properties are also required for material balance calculations particularly when

large volumes of water are produced or when the water provides energy to the hydrocarbons

production process. As opposed to oil and gas, the composition of formation water is not as

dependent on temperature and pressure variations. Thus, the sampling procedures are in most

cases simpler.

Water samples can be obtained at the surface from the separator or the wellhead, downhole with

a subsurface sampling tool or with a drill stem test (DST) sampling tool placed in the DST string.

Openhole tools like the repeat formation tester (RFT) and the modular formation dynamic tester

(MDT) also permit you to obtain water samples downhole. These tools are described in the

Wireline section of the PEPTEC on-line training.

Objectives

Upon completion of this training page, you should be able to complete the following tasks:

Identify the purpose of water sampling. Differentiate between a pressurized water sample and a dead water sample. Discuss how to obtain a water sample at the wellhead. Discuss how to obtain a water sample at the separator. List two techniques for obtaining a water sample at downhole conditions.


No single procedure is universally applicable for obtaining a sample of oilfield water. It really

depends on the information needed. Water sampling procedures can be divided in two categories:

Obtain a nonpressurized (dead) water sample Obtain a pressurized water sample

Obtaining a Nonpressurized Water Sample

This technique is used when we want to know the type and concentration of the salts contained

in the water. These major dissolved salts or inorganic constituents are sodium, calcium,

magnesium, chloride, bicarbonate and sulfate. We mainly refer to the salts as water salinity.

They participate in the salinity of the water.

The following figures illustrate three different ways of obtaining this type of a sample at the

surface.

Figure 1a illustrates one method used to obtain an air-free water sample. A plastic or rubber tube

can be used to transfer the sample from a sample valve into the container. The tube and the bottle

should be flushed to remove any foreign material before a sample is taken. After flushing the

system, the end of the tube is placed in the bottom of the container and several volumes of fluid

are displaced before the tube is slowly removed from the container and the container is sealed.

Figure 1a

Figure 1b

Figure 1b illustrates an alternative to the previous method. The sample container, placed into a

larger container, is filled from the bottom until the water overflows both containers. The sample

is then capped under water to prevent air contamination.

Figure 2

Figure 2 shows how to obtain a watersample at the wellhead when oil and water are produced

together. A simple oil and water separator is made. The separation container is first rinsed with

well fluid and then filled from the bottom. An oil-free water sample is obtained from the bottom

of the separator.

These methods permit the measurement of the pH of a water at the sampling point. The pH may

indicate a possible scale-forming or corrosion tendencies of a water. The pH may also show the

presence of drilling-mud filtrate or well treatment chemicals. It is common to see the pH of a

formation water rising during storage at the laboratory because of the formation of carbonate

ions as a result of bicarbonate decomposition.

Soluble iron in the water can precipitate out unless care is taken to keep the oxygen out of the

sample. Thus, a good practice is to take two identical water samples in plastic containers and

acidize one with a solution of hydrochloric acid to fix the iron and keep it in solution until

analysis.

Every sample taken should be clearly labelled with all pertinent data.

Obtaining a Pressurized Water Sample

This technique is used when we want to know the kind and amount of the different gases

dissolved in the water. Most of these gases are hydrocarbons. However, other gases such as CO2,

N2 and H2S are often present.

Usually, a pressurized water sample can be taken at the following locations:

Separator water outlet

This method is identical to the mercury-free displacement method for oil sampling. This bottle is

filled with hydraulic oil or with a mixture of water and glycol at a pressure higher than the

separator pressure. Water enters the bottle on one side of the piston as the transferring fluid is

slowly withdrawn from the other side of the piston. It is particularly important to maintain a

minimum pressure drop across the bottle to ensure that gases stay dissolved in the water, the

solubility of the gases being proportional to the pressure. When the bottle is full of water, a gas

cap is made for safety transportation.

If corrosive gases like H2S and CO2 are expected and need to be measured precisely, a

good practice is to fill the bottle with the water to be sampled, leave it for awhile before it

is evacuated and filled again with water destined for analysis. This technique will limit

the loss of some elements by allowing the walls of the bottle to become saturated with the

adsorbed chemicals.

Downhole with a bottomhole sampler

This method uses a sampling tool run either on electric wireline or slickline and lowered in a

water zone. It permits you to obtain a sample of water at downhole conditions. At the surface,

the sample is transferred under pressure in a bottle. More details about this method are

available in the bottomhole sampling training page.

Downhole with a DST sampling tool

A sampling tool is part of the DST string and is activated by increasing the annulus pressure. This

tool, a fullbore annular sampling chamber (FASC), will trap a sample and when full, will

automatically close. It cannot be reopened downhole. At the surface, the sample can be

transferred in a bottle.

Equipment

This topic describes only the containers used to sample dead water at the surface. The equipment

or tools used to sample water under pressure at the surface or downhole are described in separate

training pages. These tools are the bottomhole sampler, the piston bottle and the FASC.

Containers that are used for water sampling at the surface are made from polyethylene, rubber,

metal or borosilicate glass.

Glass containers are not recommended because glass will adsorb various ions such as manganese

and iron and may contribute boron or silica to the water sample.

Metal containers are not recommended either because they can yield abnormally high iron

content values.

Plastic or rubber containers are not suitable if the sample is to be analyzed for organic contents.

They themselves, contain organic constituents and can contribute to the water sample.

The most satisfactory container is probably the one made of polyethylene but not all

polyethylenes are usable because some of them contain high amounts of metal brought by

catalysts during manufacturing. The metal content of the polyethylene should be obtained from

the manufacturer before use. In fact, the safest way to get the appropriate containers is to obtain

them from the client or the laboratory which will analyse the samples.

Safety

The following is a list of key safety considerations for sampling water:

When obtaining a pressurized water sample at the surface, create a 10% gas cap in the bottle. The gas will absorb any thermal expansion of the water that could be caused by accidental exposure of the bottle to high temperature during storage or shipment. Remember that an average increase of 1oC (1.8oF) increases the pressure inside the bottle by 10 kg/cm2 (142 psi).

When samples contain toxic gas like H2S, it must be labelled on the bottle.

Every effort should be made to avoid using mercury due to its high toxicity and to its property to form irreversible organometallic compounds when found in high concentrations in living species.

If sampling with mercury, strictly follow the safety rules and procedures for mercury use.

Whenever H2S is expected or suspected, srictly follow all H2S safety rules.

Before using any sampling bottle, verify that the official pressure test is not overdue. It is a good practice to have a safety factor of six months for transportation and storage delays.

Summary

In this training page, we have presented the following:

The goal of sampling formation water Various techniques to sample water at the surface How to obtain a pressurized water sample at the separator How to obtain a downhole water sample The advantages and disadvantages of using each type of sampling bottle Safety considerations for sampling water

Self Test

1. Why do we need to sample water from an oil reservoir? 2. Name three methods of obtaining formation water samples. 3. Describe one method to recover a water sample at the surface which is free of air. 4. Why is it important to keep a minimum pressure drop across the bottle when sampling water

under pressure? 5. For a water sample containing H2S gas, it is not unusual to observe a difference between the H2S

readings made at the wellsite and the readings made at the laboratory. Why? How can we reduce this difference?

6. What type of container would you recommend for sampling dead water at the surface? 7. Is it possible to get samples of formation water during openhole operations? How?

BOTTOMHOLE SAMPLING


Introduction Objectives Principles of Operation Safety Summary Self Test References / Other Useful Links

Introduction

In the oil industry, bottomhole sampling usually means a method of trapping a volume of

formation fluid downhole. This training page describes more specifically the method which uses

a pressurized container suspended on a cable inside the well close to the productive interval. This

technique is used in the following situations:

Only a small volume of fluid is required. The oil to be sampled is not so viscous that it impairs the sampler operation.

The flowing bottomhole pressure (pwf) is greater than the reservoir bubblepoint pressure (pb). The subsurface equipment will not prevent the sampler from reaching the sampling depth or

make its retrieval difficult.

Bottomhole sampling is very often used in addition to surface sampling. The main reason being

that a sample obtained downhole using state-of-the-art rules has more of a chance to be

representative than a surface sample resulting from recombination, which heavily depends on the

accuracy of the gas/oil ratio (GOR).

Bottomhole sampling requires extra rig time (e.g., 3 to 4 hours per run for a 2000 meter well)

compared to surface samples which can be taken during a flow period.

This training page requires that you be familiar with general sampling techniques and the

characteristics and behaviors of reservoir fluids.

Objectives



Compare the advantages and disadvantages of bottomhole sampling versus surface sampling. Discuss how to prepare the well prior to bottomhole sampling. Explain why a minimum of two bottomhole samples should be taken. Write a complete sampling procedure including preparation, sampling, transfer and bubblepoint

determination. Break down the procedure by outlining only the key steps. Describe how you can ensure that the samples collected are valid. Detail the procedure to obtain an accurate field bubblepoint pressure. Using the equipment available at the RTC, transfer a sample from the sampler to the shipping

bottle and determine its bubblepoint. Carefully complete the bottomhole sampling sheet for every sample transferred.


This topic outlines the preparation of the well before proceeding with downhole sampling and

gives information on how to obtain and transfer a sample. It also explains how to control the

quality of a sample. It is divided into the following sections:

Well conditioning Sampling procedures Quality control of samples Transfer procedure

Well Conditioning

As already mentioned in the reservoir fluid sampling training page, conditioning consists of

displacing the nonrepresentative fluid located around the wellbore with fresh and unaltered fluid

from the reservoir. This is to ensure that representative fluid is in the wellbore at the sampling

depth. Well conditioning is achieved by flowing the well and gradually reducing the flow rate to

increase the bottomhole pressure. This method also permits you to observe the surface GOR and

other characteristics like gas and oil gravities during the different flow periods.

Sometimes it is not possible to obtain a minimum stable flow rate without having the bottomhole

pressure dropping below the saturation (bubblepoint) pressure. In this case, bottomhole sampling

is performed with the well shut-in. The following are considerations about sampling with the

well flowing and sampling with the well shut-in.

Well Flowing

Bottomhole sampling is achieved with the well flowing when the bottomhole flowing pressure is

well above pb (undersaturated reservoir). The pressure at the sampling depth must be at least 100

to 200 psi higher than the saturation pressure, a good figure being 500 psi. The main objective is

to obtain a stabilized low flow rate over a period of several hours. This flow period should be

preceded by a production period long enough to eliminate all traces of contaminated oil or water.

The stable flow conditions can be verified with the following points:

Stabilized surface gas and oil flow rates and GOR Stabilized wellhead pressure Stabilized flowing bottomhole pressure (pwf)

Well Shut-in

Bottomhole sampling performed with the well shut-in is only done when the smallest possible

rate causes the downhole pressure to drop below the saturation pressure. Shutting in the well will

allow the pressure to build up in the wellbore. Ideally, this will redissolve the gas that has formed

near the well. The time at which sampling is done after the well has been closed, depends on the

productivity of the well. It can vary from 2 hours for a high productivity well to 72 hours for a

low productivity well. A pressure-temperature survey will be very helpful in determining the

gas-oil and oil-water interfaces. These interfaces can be easily determined by plotting the

measured pressure versus depth and noting the points of slope change as shown in Figure 1.

Figure 1

When water is present, the sample should be collected just above the oil-water contact, if the

pressure at that point is at least equal to the bubblepoint pressure. If not, another well should be

considered.

Sampling Procedures

This section is presented as a list of the key steps to follow in order to obtain a representative

bottomhole sample:

The well must have been conditioned to ensure that a single-phase representative reservoir fluid is in the wellbore at sampling depth.

A pressure and temperature survey should be run to determine fluid levels and pressures. It will help to select the sampling depth and confirm that the well is properly conditioned.

The running speed of the sampler should be between 100 and 200 ft/min and reduced before reaching the sampling depth.

Downhole pressure and temperature should be monitored during the filling of the sampler to ensure that the fluid being collected stays representative. Real-time surface readout is the best option. When this is not possible, a memory gauge attached to the sampler can be used.

The sampling depth should be as close as possible to the perforated zone to avoid a large pressure difference between the reservoir and the sampling depth.

A clock-operated sampler should be at the sampling depth around thirty minutes before it starts to take the sample and pulled out about fifteen minutes after the filling operation is completed.

A minimum of two representative samples should be taken for a PVT analysis.

Quality Control of Samples

Every time the sampler is retrieved at surface, the following checks should be made to ensure the

quality and the validity of the sample taken:

Read the opening pressure of the sampler.

The opening pressure of the chamber is an indication of whether any leak or loss occurred

during the trip from the bottom of the well up to the surface. Its value is not directly

comparable to the bottomhole pressure at sampling depth because of the thermal contraction

of the metal and of the fluid, but if all the opening pressures of the recovered samples are

within ±2%, there is good reason to believe that the samples are representative.

Determine the bubblepoint pressure of the sample at ambient temperature.

The field bubblepoint pressure of the sample can be measured either while it is still in the

sampler or after it has been transferred into a bottle. If the bubblepoint determination is made

with the sample in the sampler, the sample will need to be recombined one more time before

the transfer. It is time consuming but the advantage is that the shipping bottle will not be

contaminated if the sample is found bad. If the bubblepoint determination is made after the

sample has been transferred into the bottle, only one recombination is necessary. In the field, it

is probably more convenient to transfer the sample into the bottle first, since it will save

operating time.

When using a sampler which features a nitrogen chamber to keep the sample monophasic, the

bubblepoint measurement has to be made in the bottle because the compressibility of the

nitrogen masks the oil compressibility.

Usually, the best way to ensure the validity of a sample is to compare its bubblepoint pressure

with the bubblepoint pressure obtained from other samples taken at the same conditions. These

pressures should be within 2%.

Before starting the transfer, the recovered fluid should be put back into a single phase (by simply

increasing its pressure) because if it is displaced under diphasic conditions, some heavier

components will be lost in the dead volume of the transfer loop and the composition of the

sample will be irremediably effected.

In some cases, the sampler chamber is sent directly to the PVT lab where all operations are

performed under controlled conditions.

Ideally, the bubblepoint pressure should be measured at bottomhole temperature but for practical

reasons, it is rarely done.

The on-site bubblepoint measurement is performed the same way as in a laboratory by

monitoring the compressibility of the oil both at monophasic and diphasic conditions. It consists

of plotting the pressure of the sample versus the amount of transferring fluid (e.g., hydraulic oil,

mercury and water) withdrawn from the sampling bottle. The fluid pressure-volume curve

obtained should exhibit a sharp change in slope, which reflects the compressibility contrast

between the liquid phase and the gas-liquid phase when the first gas bubbles appear. The field

bubblepoint pressure is the pressure read at the slope change.

The change in slope in the pressure-volume diagram (Figure 2) is usually quite obvious for low

volatility oils (black oils) but difficult to observe for high volatility oils. Thus, the bubblepoint

determination of high volatility oils is not very clear. To remedy this problem, the measurements

should start with the fluid in single phase and pressure well above the expected saturation

pressure. Since increasing the pressure does not guarantee that all gas is back in solution, the

sample should be gently rocked to increase the contact area between the two phases and

accelerate the mass transfer. Agitation is also highly recommended before the pressure value is

taken at each step during depressurization as well as giving sufficient time for this pressure to

stabilize.

Figure 2 shows the pressure-volume plot of a sample in which diphasic fluid was recompressed

to 4000 psi and decompressed with agitation at every step. A sharp change in compressibility is

obtained which facilitates the field bubblepoint reading.

Figure 2

Figure 3 shows the pressure-volume plot of the same sample without agitation. This graph

clearly demonstrates how the lack of agitation can result in a wrong and arbitrary field

bubblepoint pressure estimation with an error which could be as much as 50%.

Figure 3

The field bubblepoint pressure obtained from the graph is corrected for bottomhole temperature

(because of the temperature drop from downhole to the surface), compared to the reservoir fluid

pressure at the time of sampling and compared to the saturation pressures measured from the

other bottomhole samples. If the sample has been recovered at single phase conditions, its

bubblepoint pressure should be less than the flowing bottomhole pressure ( pb < pwf). If pb = pwf,

the reservoir fluid was saturated and if pb > pwf, it is very likely some free gas was caught with

the reservoir fluid.

For gas condensate samples, the dewpoint pressure cannot be measured by observing the change

in the fluid's compressibility. The compressibility of the first droplets of condensate appearing is

so small compared to the compressibility of the dominant gas phase that it will not influence the

compressibility of the entire system. For the time being, the determination of saturation pressures

of gases in the field is not done because it requires the use of a visual cell. The quality control is

then limited to the conformity of the opening pressure values and their comparison to pwf.

All the verifications made on a sample as described above do not guarantee a perfect control of

the quality because they are "blind" tests and do not involve any characterization of the fluid

itself. The following example illustrates the case of samples satisfying the opening and

bubblepoint pressures although they were found useless by the PVT lab:

Three samples were sent to the lab with neat depressurization diagrams exhibiting sharp contrast

in compressibility and similar opening and bubblepoint pressures. When the bottles were opened,

formation water was found in the samples because the sampling depth chosen was wrong. The

gas dissolved in the water at downhole conditions caused the fluid to show reasonably high

saturation pressures.

Today, the Schlumberger fluid property evaluation (FPE) system, available at the wellsite, can

eliminate this uncertainty. It permits you to validate the samples and to optimize the sampling

program by providing on-site measurements of fluid properties and compositional analysis.

Transfer Procedure

The sampling chamber of the bottomhole sampler cannot be used as a transportation and storage

container. Thus, the sample is transferred into a bottle suitable for shipment to a PVT laboratory.

This type of bottle is certified for shipping and storing reservoir fluids under pressure and should

have a capacity of at least 10% greater than the sampler chamber.

The transfer procedure is a delicate operation and every precaution should be taken to ensure that

the representativity of the sample is not lost between the sampler and the bottle. The lines

between the sampler and the bottle should be purged to eliminate air from the system.

Due to the temperature change from downhole to the surface, the fluid in the sampler is almost

always in a two-phase condition. To prevent losing part of the fluid during the transfer, it is

compulsory to displace the collected sample in a homogeneous and monophasic state. This is

achieved by repressurizing the sample 1000 psi above the expected bubblepoint pressure or static

bottomhole pressure (when pb cannot be estimated). This pressure will be maintained during the

transfer.

Recombining gas and oil by just increasing the pressure is a long process. It takes time for a

hydrocarbon mixture to reach its phase equilibrium under a given set of pressure, volume and

temperature conditions and time is always a constraint at the wellsite. However, agitating the

sample during the transfer will speed up the equilibrium process, which explains why a good

transfer bench features an agitation device.

When the sample has been transferred into the bottle, it is very important to drain an extra

amount of transfer fluid from the bottle (10%) to create a gas cushion which will absorb any

expansion of the liquid phase due to a possible temperature increase. This ensures that the

internal pressure will never reach or pass beyond the pressure rating of the bottle.

Before transferring a gas condensate, the sampler chamber should be heated with a heating jacket

to a temperature 2 to 4oC above the reservoir temperature because, as can be seen in Figure 4, at

downhole pressure and ambient temperature, a gas condensate can be found in the diphasic

region but also could behave as a saturated oil (when the ambient temperature becomes less than

the cricondentherm).

Figure 4

A very viscous oil may also need to be heated to the downhole temperature before its transfer

from the sampler to the bottle.

The following steps summarize the transfer procedure with the bubblepoint determination made

with the sample in the bottle:

Repressurization of the sampler chamber 1000 psi above the expected bubblepoint pressure or static bottomhole pressure.

Displacement and agitation of the sample into the bottle at the pressure mentioned in the previous step.

Determination of the bubblepoint pressure with agitation and pressure stability checks at every transfer fluid withdrawing step.

Transfer of Bottomhole Sample Multimedia

This animation illustrates the recombination, agitation and transfer of an oil sample from a

bottomhole sampler into an oil bottle. It also covers the bubblepoint determination.

Objective: To understand the operating principles of transferring the bottomhole sample (BHS)

and the determination of the bubblepoint

Comment: This is a continuation of the "Surface Oil Sampling with a Mercury-Free Bottle"

animation.

Remarks: Once the sample has been transferred from the bottomhole sampler into the bottle, the

bottle should be verified for leaks. The leak test simply consists of immersing both valves of the

bottle in a bucket of water and looking for bubbles. If a leak is detected, the sample is invalid and

sampling should be repeated. This leak test is illustrated in the "Surface Oil Sampling with a

Mercury-Free Bottle" multimedia.

The bottle must be sealed with the safety plugs on both valves. The valves are secured with a

metallic wire closed by a lead seal so that opening the valves will deliberately break the wire.

It is also very important to label the bottle as soon as the transfer procedure is achieved. This is

done by placing a label inside the wire loop. This label indicates that the bottle is full. In case of

H2S, another label marked "H2S" is inserted through the wire. Figure 5 shows a valve of an oil

bottle sealed with the wire and a label attached to it.

Figure 5

This type of oil sampling bottle is further described in its own training page. A bottomhole

sampler used for this technique is also described in its own training page.

Finally, a sampling data sheet containing all the pertinent information regarding the sampling

operation must be properly filled out and one copy will accompany the bottle. A typical sampling

data sheet is shown in Figure 6.

Figure 6

Safety

The following is a list of key safety considerations for bottomhole sampling:

Bottomhole sampling can involve high pressures. The equipment must be in perfect condition.

Although the sample chamber is designed to contain pressure, the tool should be handled with care and not dropped.

A primary consideration is the need for a vapor space within the liquid sample (i.e., a gas cap). Thermal expansion of the liquid could cause the container to exceed its pressure limits if the temperature rises. An average increase of 1oC (1.8oF) increases the pressure inside the bottle by 10 kg/cm2 (142 psi).

Sample containers should be kept at reasonable surface temperatures and not stored in direct sun or placed in hot areas.

Care must be taken to protect the container, especially the end valves, during shipping and handling. End protectors must be used.

The valves on each end of the sample container must be fitted with safety plugs to prevent accidental opening during transportation.

When samples contain toxic gas, like H2S, the name of the gas must be labeled on the bottle. Pressure ratings of the bottles, connections, valves and fittings must be strictly observed. Every effort should be made to avoid using mercury due to its high toxicity and to its property of

forming irreversible organometallic compounds when found in high concentrations in living species.

If sampling with mercury, strictly follow the safety rules and procedures. Before using any sampling bottle, verify that the official pressure test is not overdue. It is a good

practice to have a safety factor of six months for transportation and storage delays. Whenever H2S is expected or suspected, sampling must be carried out with protective

equipment. Government regulations concerning the transportation of flammable and pressurized fluids

must be followed (Department of Transportation (DOT) and International Air Transport Association (IATA)).

All sampling equipment falls under the scope of the Schlumberger Wireline and Testing Pressure Operations Guidelines.

Summary



following:

Preparation of the well prior to sampling Important steps to follow in order to sample successfully How to ensure the quality and validity of the samples taken:

o Reading the opening pressure o Determination of the bubblepoint pressure at ambient temperature

Transfer procedure Safety considerations

Self Test

1. Why is bottomhole sampling done? 2. What is the main advantage of bottomhole sampling over surface sampling?

3. When do you sample downhole with the well shut-in? 4. What measurements should be made when sampling? 5. Why do we need to recompress the sample before the transfer? 6. What is the purpose of the compressibility curve? 7. How can we obtain a better sharp contrast on the compressibility curve? 8. Why is it not possible to accurately measure the saturation pressure of a gas condensate

sample? 9. Why should the shipping bottle have at least a capacity 10% greater than the sampler chamber?

GAS SAMPLING BOTTLE



Introduction

Usually during a well test, samples of produced fluids are taken at the surface or downhole or

both places for further analysis in a laboratory. Due to the hazardous nature of these fluids and

the high pressures involved, the samples are collected in special containers or bottles which

comply with stringent regulations in terms of design, manufacturing, testing, certification,

operation and transportation. The gas sampling bottle described in this training page is built to

transport hydrocarbon gases safely and simply consists of a cylindrical aluminium container

equipped with a valve on each side. It is the latest Schlumberger standard gas sample bottle and

its usual code name is SBG-C.

Objectives



Explain the relationship between the general gas law "PV / ZT= constant" and the sampling procedure with a gas bottle.

List the technical characteristics of the SBG-C. Gas sampling bottles are considered as "mobile pressure vessels." Write the important safety

regulations that govern this type of vessel. Perform a FIT and TRIM procedure for the SBG-C. Take a gas sample using the procedures applicable at the RTC. Prepare the gas bottle for shipment.


The usage of the gas bottle is described in the Surface Sampling training page under gas surface

sampling methods. It should be noted that this bottle cannot be used for sampling with mercury

because it is made of an aluminium alloy.

This topic describes the main components of the SBG-C. It also examines how a gas bottle is

characterized and how this applies to the SBG-C. Figure 1 illustrates each component of the

SBG-C.

Gas Bottle Components

Body

The body of the gas bottle is simply a cylinder threaded at both

ends to receive the valves. It is made of an aluminium alloy

resistant to H2S, CO2 and chlorides and has a capacity of 20

liters. On one side, it is stamped with the bottle specifications

and the certification data.

Valves and Safety Plugs

The gas bottle is equipped with two valves. Each valve has a

threaded lateral outlet to connect the sampling line. A safety plug

covers the outlet during storage and transportation. It acts as a

seal and protects the threads. The valves and the safety plugs

feature a small hole to pass a metallic wire through for sealing

such that opening the valves or removing the plugs will break the

seal.

Protectors

Two protectors are connected on both sides of the bottle. They

protect the valves during transportation. They also serve as

handles to carry the bottle and they can be used as stands to hold

the bottle vertically.

Figure 1

Gas Bottle Characterization

A gas sampling bottle is not only defined by a working pressure and a test pressure but also by a

maximum sampling pressure versus temperature. This is a direct consequence of the general gas

law "PV / ZT = constant" which governs the pressure of a gas sample versus its temperature.

Since a gas sample bottle may be exposed to high temperatures after it has been filled, the initial

filling pressure at the initial filling temperature must be such that the bottle's internal pressure

will never exceed the safe maximum working pressure for which the bottle was certified.

Schlumberger's policy is to base its gas sampling procedures on a maximum allowable bottle

temperature of 100oC [212

oF].

Figure 2 gives the maximum sampling pressure versus sampling temperature for the SBG-C.

Figure 2

Equipment

The SBG-C was developed to answer all the field needs particularly in terms of safety, weight and

volume capacity. Figure 3 shows the gas bottle and lists its specifications.

Description

The SBG gas sample bottle is designed primarily for sampling the separator gas

needed for PVT recombination studies.

The bottle is manufactured in aluminum alloy and is suitable for H2S service.

A unique serial number, including the year of manufacture, is stamped on each

bottle, which comes with an individual fiberglass transport box.

Specifications

Certification Bureau Des Mines/Lloyds

Design codes API 6A, NACE MR0175

Assembly number P-579057

Project code SBG-C

Fluid classification EE (H2S, Co2)


Test pressure 4250 psi [300 bar]

Working temperature 14 to 212 oF [-10 to 100

oC]

Capacity 20 liter

Diameter 9 in. [229 mm]

Length with protectors 43.5 in. [1106 mm]

Weight empty (empty, in transport box)

60 lbm [27 kg]

Weight of box 49 lbm [22 kg]

Safety

Gas bottles are "mobile pressure vessels" designed to contain hydrocarbon gases along with

corrosive gases like H2S and CO2. As such they are subjected to stringent regulations regarding

testing, certification, operation and transportation. The following is a list of key safety

considerations for gas bottles:

Every new gas bottle is pressure tested by a certifying authority. In France, the certification is valid for two years and should be renewed every two years to verify that the bottle still complies with the actual regulations.

When no local regulations exist or when they are less severe than the French regulations, the French regulations apply.

Before using a gas bottle, verify that the official pressure test is not overdue. It is a good practice to have a safety factor of six months for transportation and storage delays. This is particularly important if the bottle is sent to the French PVT laboratory for analysis because the French regulations do not allow a pressurized sample to enter if the certification due date is less than six months.

Gas bottles should be kept at reasonable surface temperatures and not stored in direct sun or placed in hot areas.

Care must be taken to protect the bottle, especially the end valves, during shipping and handling. End protectors must be used. A fiberglass container is provided to protect the bottle during shipment.

Government regulations concerning the transportation of flammable and pressurized fluids must be followed. The SBG-C and its fiberglass container meet the International Air Transport Association (IATA) dangerous goods transportation requirements. Figure 4 shows the SBG-C container properly labelled with the appropriate stickers to comply with IATA rules.

Figure 4

Any repair made on the gas bottle should be followed by a routine test with water at 110% of the working pressure.

When sampling gas containing H2S, it must be clearly labelled on the bottle. To prevent any accidental opening of a bottle containing a valid sample, both valves should be

stopped with a metallic wire closed by a lead seal. In addition, a safety plug should be fitted on each valve.

Always use the colored labels to distinguish between an empty bottle and a full bottle. The green "empty" label should be attached to a bottle which is ready to use. The red "full" label must be attached to the bottle immediately after the sample is taken. Figure 5 shows a gas bottle valve sealed with the wire and a label attached to it.

Figure 5

Solvents used to clean the hydrocarbon containers are usually toxic. Carefully read and follow the safety instructions given with every solvent.

Gas sample bottles fall under the scope of the Schlumberger Wireline and Testing pressure operations guidelines.

Maintenance

This topic lists the main steps of the maintenance procedure for the SBG-C. The detailed

procedure should be performed according to the FIT and TRIM requirements spelled out in the

surface sampling section of the Field Operating Handbook (FOH) vol. II.

Verify the validity of the official test. Inspect all the threads (e.g., valves, safety plugs and protectors). Rinse the bottle with solvent and dry with filtered air. If necessary, dismantle the valves for complete cleaning. Pressure test the bottle at 100% of its nominal working pressure with water. If the valves have

been removed, pressure test at 110% of its nominal working pressure. After the pressure test, rinse the bottle with solvent and dry with filtered air. Close the valves. Install the safety plugs. Seal and label "empty" so that opening the valve will

deliberately break the wire. Install end protectors. Fill out the history card.

Summary


The reasons why we use gas sampling bottles. The components of the gas sampling bottle.

The technical specifications of the SBG-C. The parameters that define a gas sampling bottle. Some important safety considerations for the gas sampling bottle. An overview of the main maintenance procedures applicable to the SBG-C.

Self Test

1. Why is a gas sampling bottle characterized by a maximum sampling pressure? 2. What is the Schlumberger policy regarding gas sampling procedures? 3. What are the technical specifications of the SBG-C? 4. What is the purpose of sealing the gas sampling bottle? 5. How is it sealed? 6. Is it possible to sample sour gas with the SBG-C? 7. Why is the bottle equipped with two valves?

OIL SAMPLING BOTTLE


Introduction

Usually during a well test, samples of produced fluids are taken at the surface or downhole or at

both places for further analysis in a laboratory. Due to the hazardous nature of these fluids and

the high pressures involved, the samples are collected in special containers or bottles which

comply with stringent regulations in terms of design, manufacturing, testing, certification,

operation and transportation. The oil sample bottle described in this training page is built to

transport hydrocarbon liquids safely and exists in two versions which differ only by their size

and working pressure. It is the latest Schlumberger standard oil sample bottle and its usual code

name is PSR-F for the 10 kpsi version and PSRA-F for the 15 kpsi version.

This bottle was primarily designed to answer the needs of obtaining representative oil samples

without the constraints of mercury.

Objectives



Draw a schematic of the PSR-F and explain how it works. List the technical specifications of the PSR-F and the PSRA-F. Perform a FIT and TRIM procedure for the PSR-F or the PSRA-F. Collect an oil sample using the procedures applicable at the RTC. Prepare the oil bottle for shipment.


Prior to describing the bottle in detail, it is important to know the different considerations that

dictated its design.

For a long time, mercury was the transfer fluid used in the field due to its specific properties.

Today, its high toxicity makes it prohibited by most companies and governments preoccupied

with the environment. The floating piston system was then found as an alternative.

It was also necessary to improve the sampling procedures and the equipment that had not been

upgraded in years. Voids in the transfer systems that were filled with mercury before now use a

vacuum. It was important to reduce the dead volumes to a minimum to avoid the flashing of the

samples.

Another aspect to consider was the improvement of the precision of the field bubblepoint

pressure by reducing the internal frictions of the piston system and permitting the agitation of the

sample.

The last consideration was to guarantee the original conditions of the sample even after a long

period of storage by using metal-to-metal seals.

The following topic describes the oil piston bottle and focuses on its specific features. Figure 1

shows a cut view of the different components of the PSR-F.

Figure 1

Oil Bottle Components

Valves and Safety Plugs

The bottle is equipped with two precision valves. They are colored

differently to help the user distinguish between the two different sides of

the bottle. The blue valve is located on the transfer fluid side and the

black valve on the sample side. These high pressure needle valves

feature metal-to-metal seals and comprise of two lateral outlets each.

Figure 2 shows how the bottle is connected using the valves outlets on a

typical oil surface sampling setup at the separator.

Figure 2

To ensure a complete seal of the bottle, the outlets are covered with safety plugs. Figure 3 shows

a cut view of a precision valve.

Figure 3

Floating Piston Assembly

The floating piston is used as an interface between the transfer fluid and the liquid which is to be

sampled. It has a very special design to provide the best sealing with the minimum friction. The

arrangement of the sealing parts gives only a 2 psi maximum differential pressure across the

floating piston. It comprises of two O-rings that achieve the inner seal and a special quad-ring

located in the groove of a low friction ring that achieves the outer seal. This low friction feature

permits you to obtain an accurate bubblepoint pressure.

The piston is centralized by two special wiper rings. They allow a minimum clearance with the

cylinder which prevents sand or debris from impeding its movement.

One side of the piston has a semispherical seat to receive the ball, reducing the dead volume of

the bottle. The other side includes a ball check valve that closes the transfer fluid orifice when

the piston touches the transfer fluid side of the bottle. This happens at the end of the transfer

procedure and permits you to leave a minimum amount of pressurized driving fluid behind the

piston which keeps the seals at no differential pressure. Even a leak through the piston could not

modify the sample significantly.

An equalizing duct prevents the pressure from being trapped behind the screws. Tests proved

that without the duct, the trapped pressure could loosen the screws. Figure 4 shows the floating

piston and its associated components.

Figure 4

Ball

As stated in the bottomhole sampling training page, agitation of the sample speeds up the

equilibrium between the oil and the oil phases. This phenomenon is particularly useful when

recombining or decompressing a sample for bubblepoint determination. The ball will improve

the agitation process. It should be noted that the ball fits completely in the piston and cap profile

reducing the dead volume of the bottle.

Cylinder, Plugs and Nuts

The bottle is made of a cylinder covered at both ends by a plug and a threaded nut. On the

transfer fluid side, the plug is flat to shoulder the flat side of the piston. On the sample side, the

plug has a semispherical shape to receive the ball when the piston is fully pushed by the transfer

fluid which reduces the dead volume of the bottle. Each nut is threaded with 4 threads per inch

(TPI) allowing for quick dismantling of the bottle for inspection and cleaning purposes. Six

screws evenly distributed on the nuts compress the metal seal and hold (lock) the nuts in place.

This system permits the nuts to be gently tightened on the cylinder by hand for easy disassembly

later on.

Metal Seals

The plugs-to-cylinder body seals are made of an American Petroleum Institute (API) flange-type

metal seal to prevent oil migration during long storage periods.

Protectors

Different types of protectors are available. They are used to protect the valves and facilitate the

transportation of the bottle. The one shown in Figure 1 can also serve as a stand when sampling

and when reassembling the bottle. Figure 5 shows two other types of protectors.

Figure 5

Equipment

The oil bottle is available in two models, the PSR-F, which has a pressure rating of 10 kpsi, and

the PSRA-F, which has a pressure rating of 15 kpsi. The PSR-F has a lateral outlet of 1/8 in. and

a lower outlet of 1/4 in., whereas the PSRA-F has a lateral outlet of 1/8 in. and a lower outlet of

1/8 in.

Description

The PSR-F/PSRA-F oil sample bottles are designed for mercury-free

transfer of samples from bottomhole sampling tools, or for mercury-free

surface sampling.

The bottles feature a piston with special low-friction seals for accurate

bubblepoint checks. A heavy ball assists in homogenization of the sample.

Metal-to-metal seals avoid gas migration during long storage periods. Dead

volumes are reduced to a minimum. Each bottle has a unique serial

number.

Specifications

Certifying

authority Bureau Des Mines

Design codes API 6A, NACE MR0175


Project code PSR-F PSRA-F

Fluid

classification EE (H2S, Co2)

Working pressure 2860 psi, -10oC/+70

oC

15,000 psi

[1035 bar]

Working

temperature

14 to 302 oF [-10 to 150

oC]

14 to 158 oF [-10 to 70

oC]

Capacity 730 cm3

Needle valves

Autoclave with 2 x 1/8-in.

W125 outlets per valve

Body connections 1/4-in. Autoclave F250C

Diameter 4.65 in. [118 mm]

Length

Without valves 17.1 in. [436 mm]

With protectors 25.7 in. [654 mm]

Weight (empty, in transport

box)

52 lbm [23.6 kg]

Options

Oscillating stand M-872901

Figure 6

Figure 6 shows a generic oil bottle and lists the specifications for both models.

Safety

Oil bottles are "mobile pressure vessels" designed to contain hydrocarbon gases along with

corrosive gases like H2S and CO2. As such, they are subjected to stringent regulations regarding

testing, certification, operation and transportation. The following is a list of key safety

considerations for oil bottles:

Every new oil bottle is pressure tested by a certifying authority. In France, the certification is valid for two years and should be renewed every two years to verify that the bottle still complies with the actual regulations.

When no local regulations exist or when they are less severe than the French regulations, the French regulations apply.

Before using a oil bottle, verify that the official pressure test is not overdue. It is a good practice to have a safety factor of six months for transportation and storage delays. This is particularly important if the bottle is sent to the French PVT laboratory for analysis because the French regulations do not allow a pressurized sample to enter if the certification due date is less than six months.

Oil bottles should be kept at reasonable surface temperatures and not stored in direct sun or placed in hot areas.

Care must be taken to protect the bottle, especially the end valves, during shipping and handling. End protectors must be used. A fiberglass container is provided to protect the bottle during shipment.

Government regulations concerning the transportation of flammable and pressurized fluids must be followed. The oil bottle and its fiberglass container meet the International Air Transport Association (IATA) dangerous goods transportation requirements. Figure 7 shows the PSR-F and Figure 8 shows the PSRA-F containers properly labelled with the appropriate stickers to comply with IATA rules.

Figure 7

Figure 8

Any repair made on the oil bottle should be followed by a routine test with water at 110% of the working pressure.

When sampling oil containing H2S, it must be clearly labelled on the bottle. To prevent any accidental opening of a bottle containing a valid sample, both valves should be

stopped with a metallic wire closed by a lead seal. In addition, two safety plugs should be fitted on each valve.

Solvents used to clean the hydrocarbon containers are usually toxic. Carefully read and follow the safety instructions given with every solvent.

Always use the colored labels to distinguish between an empty bottle and a full bottle. The green "empty" label should be attached to a bottle ready to use. The red "full" label must be attached to the bottle immediately after the sample is taken. Figure 9 shows a oil bottle valve sealed with the wire and a label attached to it.

Figure 9

Oil sample bottles fall under the scope of the Schlumberger Wireline and Testing pressure

operations guidelines.

Maintenance

For information about preparation, assembly and disassembly of the oil bottle, see the "Technical

Circular 162," dated March 1991, which should be found in the transfer bench maintenance

manuals (TRB-B/C) and (TRB-D) (references M-075037 and M-075100 respectively).

Summary


The reasons behind the design of this oil sampling bottle. The operating principles of the oil sampling bottle. The components of the oil sampling bottle. The technical specifications of the PSR-F and PSRA-F. Some important safety considerations for the oil sampling bottle.

Self Test

1. Why is it important to reduce the dead volumes in the bottle? 2. What is the function of the ball valve in the piston? 3. Why is the bottle equipped with metallic seals? 4. How is the differential pressure minimized across the floating piston? 5. Why is the friction reduced to a minimum between the floating piston and the body?

Well Test Complete

Documents

Transcript of Well Test Complete