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 cann ot be answered by wireline and other techniques such as mud logging, coring, electrical logging, and s eismic measurements. Although extremely valuable, these techniques p rovide 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 pe rformed at various stages in the life of a well. Tradi tionally, 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 hand led 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 co mpletion (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 coring..

What Is Derived from a Test? During the interpretation phase, the data acquired during testing is used to make evaluations. evalu ations. Using the parameters acquired in the data acquisition phase, the following can be calculated: 

Reservoir parameters: Permeability (k) o o o o

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Heterogeneity parameters (lambda [ Hydraulic fracture parameter (Xf ) Initial reservoir pressure (pi)

], omeg egaa [ ], kap app pa [

])

Well parameters: Near well-bore formation damage: skin factor (S) o Inflow performance relationship (IPR) o Wellbore storage coefficient (C) o Geometry of the reservoir and its extent: Reserve quantities Hydraulic communication between wells

The accuracy of these evaluations ev aluations 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 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 d ynamic 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 unde r 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 a nd 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: 

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If the well has been shut for a long lon g 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 b e 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 b ecause, 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:  

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Quickly control pressure and flowrates at the surface and shut the well. Separate the resulting effluent into three separate fluids (oil, gas and w ater) 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:

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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 t ype of environment, well conditions, and the client requirements. The following figure shows a typical offshore layout of surface testing equ ipment.

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

Land operation

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Offshore operation

Well conditions:    

High flowrate and high pressure Effluent properties (oil properties and hydrate h ydrate 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 iden tifies where the equipment is located (zones and an d 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 po ssible 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: 

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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 p ut together for the purpose of producing the well at the surface, measuring the different components o f the well

effluent, taking component samples, and disposing d isposing 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 o il 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 a ccurate 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 ke ep 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, Toda y, 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 bu rner or the other is used, depending depend ing 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 o ut of the separator. A water pump is used to inject water into the oil flame at the burner, which improves combustion, an d to create a water screen behind beh ind the burner, which reduces heat radiation.

High Flow Rate Layout

Although most tests worldwide are run with flow rates up to 500 0 BOPD or 30 MMscf/D, flow rates that surpass separator capacity are sometimes encountered. In these c ases, 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 R ate Test" drawing shows an example ex ample 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 o procedures), oil gravity must be above 10 API (viscosity below 300 centipoises).

Viscosity is reduced downhole by either heating th e oil or by injecting diesel, gas, or steam into the well. At the surface, viscosity is reduced b y adding a heater or steam exchanger ex changer to heat the well effluent before it enters the separator. The "Su rface Testing Layout for a Gas Well or Viscous Oil Test" drawing shows an onshore surface testing la yout that includes a heater. To prevent the formation of hydrates h ydrates (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:   

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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 or ient 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 placemen t 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. 

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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 g eographical restrictions or client approvals. At the choke manifold samples of well w ell 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. 

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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 star ters 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.

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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 recommen ded 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. 

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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 zon es 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: standard onshore layout o standard offshore layout o high flow rate layout o high viscosity and foaming oil layout o

  

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

Self Test 1. 2. 3. 4.

What factors influence a surface testing layout? Why would you locate the choke manifold as close as possible to the flowhead? Why is a well site divided into zones? 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 This training page is divided into the following main headings:    

Introduction Objectives Principles of Operation Equipment

The "Surface Test Equipment" figure shows whe re 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) 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:  

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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 t ypes 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, g reat, 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 Upon completion of this package, you should be able to:    

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.

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

Principles of Operation The flowhead consists of four gate valves: 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 pa cker 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 p roduction 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 w ill 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 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 r eservoir pressure, injecting acid into the formation to increase production, or high pressure injecting of a fluid to enlarge the passages through t hrough 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 s ystem called an emergency shut down (ESD) is recommended because b ecause 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. elevators.The 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 p ossible 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 o f 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 o f 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

Protection

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90,000 lbf 61,000 lbf

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 valv e allows isolation of the surface equipment from the downhole test string. The swab valve allows introduction and retrieval of wireline tools. The flowhead has two wing valves, one allowing fluid to flow from the well and the other for 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.)


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]



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300,000 lbm 200,000 lbm

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490,000 lbm 300,000 lbm

Makeup torque   

Maximum Minimum

Protection



3000 ft-lbf 2000 ft-lbf


Nominal valve ID

Master valve/swab valve 2 9 Ž16 in. [65 mm] Wing valves API 6A classifications

2 1 Ž16 in. [52 mm]

 



PSL2

PSL3


DD

EE


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

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]

Dimensions

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

Description

The well test flowhead consists of four gate valves. Th e 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 valv e allows isolation of the surface equipment from the downhole test string. The swab valve allows introduction and retrieval of wireline tools. The flowhead has two wing valves, one allowing fluid to flow from the well and the other for 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.)


Det Norske Veritas

Design codes

DNV Drill ³N,² DOE SI 289 API 6A, NACE MR 01 75

Assembly number

P-839688

P-873654

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]



 

661,400 lbf 322,900 lbf

 

661,400 lbf 322,900 lbf

Makeup torque   

Maximum Minimum

Protection




 





PSL3

PSL3


EE (H2S, CO2)

EE (H2S, CO2)


P+U, 20 to 250°F

P+X, 20 to 320°F

Connections

* 6 1 Ž2 -in. -4 Acme

Master valve (box)

6 1 Ž2 -in. -4 Acme

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

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]

Weight

8600 lbm [3900 kg]

8600 lbm [3900 kg]

Hostile

Dimensions

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 FHTDM.

Description

The flowhead swivel is inserted between the flow-head master valve and the main valve block. 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 sho uld not be rotated when pressurized.


Det Norske Veritas

Design codes


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  


 

300,000 lbf 200,000 lbf

Connections

4 1 Ž2 -in. -4 Acme

Protection


 

490,000 lbf 300,000 lbf

 

661,400 lbf 322,900 lbf

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



PSL 2

PSL 3

PSL 3


DD (H2S)

EE (H2S, CO2)

EE (H2S, CO2)


P+U

P+U

P+U

20 to 250°F [28 to 121°C] Makeup torque  

Maximum Minimum

 


 


 


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): H 2S 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 b ands (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 m ust be used to prevent sparks. The brass or o r 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 gat e 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 t otally 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 val ves to manipulate the tool string and to compensate for up and down movement (heave) of the offshore r ig 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 m anifold (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 o pening or closing them to prevent handles from falling onto the rig r ig 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 S urface Well Testing." For infomation about equipment maintenance, see the maintenance manuals for the flowhead and the "FOH for Surface Well Testing."

Summary In this training page, we have discussed:   



 

The five principle functions of the flowhead. Each of the components that make up a typical flowhead. 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, 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. operations. The criteria for selecting a flowhead.

Self Test 1. 2. 3. 4.

List the five principal functions of the flowhead. What is the purpose of the swab valve? When is a swivel needed? 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 be fore 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. mo nitored.

The choke manifold, with a design featuring a fixed and adjustable choke, ch oke, 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 enhancin g 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 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 d ownhole as safety devices to control co ntrol 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.. 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 o f 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 FIT)) and tool review and inspection monthly (TRIM TRIM)) procedures for the choke manifold as per the maintenance manual. Dismantle and reassemble the adjustable choke assembly.

Principles of Operation 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, toda y 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 o f the choke when making mak ing 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 b efore 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 prop er 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. 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 t he 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 u sually 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, t hat, 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 t he 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 o pening 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 -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 t he cleanup 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 t ubes 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 sniffer.. The reactive tube connected to the sniffer is made of glass and contains a reactive material for the gas g as that it measures. The concentration of gas is measured by the graduated lines in the reactive tube.

Weco connections

Both the inlet and outlet o utlet 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 no t 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 chok e manifolds and list their specifications.

Description

The choke manifold is used for controlling flow ra te and for reducing the effluent pressure to acceptable levels before it enters the process equip ment. 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. a ccessories.


None

Design codes

API 6A

Assembly number

M-834275

Project code

FMF-AA

Integral bypass valve

NO

Working pressure

3000 psi [207 bar]

Test pressure

6,000 psi [415 bar]

Nominal ID (drift)

2 1 Ž16 in. [52 mm]

Adjustable choke size

1 1 4 in. [32 mm]

Choke bean series

D-52

Protection




PSL 1

Fluid classi ication

AA


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] Weight

590 lbm [260 kg]

Description

The choke manifold is used for controlling flow ra te and for reducing the effluent pressure to acceptable levels before it enters the process equip ment. The choke manifold is composed of four gate valves (five if a bypass b ypass 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 chok e 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.


Det Norske Veritas

Design codes


Assembly number

M-873331

M-873330

Project code

FMF-BBS

FMF-D *


Yes

No

Working pressure

5000 psi [345 bar]

5000 psi [345 bar]

Test pressure

10,000 psi [690 bar]

10,000 psi [690 bar]

Nominal ID (drift)

3 1 Ž8 in. [79 mm]

3 1 Ž8 in. [79 mm]


1 1 Ž2 in. [38 mm]

1 1 Ž2 in. [38 mm]

Choke bean series

D-58

D-58

Protection





PSL 2


DD (H2S)


P+U, 20 to 250°F [28 to 121°C]

Connections

Outlet


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]

Weight

5350 lbm [2390 kg]

4450 lbm [2000 kg]

* 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 acceptable levels before it enters the process equip ment. The choke manifold is composed of four gate valves (five if a bypass b ypass valve is included), a variable choke box, a fixed choke box and tapping points for measuring upstream and downstream pressures. A thermometer well is usually provided. Each chok e 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.


Det Norske Veritas

Design codes


Assembly number

P-579052

P-579053

Project code

FMF-F

FMF-G


No

No

Working pressure

5000 psi [345 bar]

10,000 psi [690 bar]

Test pressure

10,000 psi [690 bar]

15,000 psi [1035 bar]

Nominal ID (drift)

3 1 Ž8 in. [79 mm]

3 1 Ž16 in. [78 mm]


1 1 Ž2 in. [38 mm]

2 in. [51 mm]

Choke bean series

D-58

D-72

Protection




PSL 2

PSL 3


DD (H2S)

EE (H2S, CO2)


P+U, 20 to 250°F [28 to 121°C]

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

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]

Weight

4500 lbm [2040 kg]

Dimensions

4000 lbm [1820 kg]

Description

The choke manifold is used for controlling flow rate and reducing the effluent pressure to acceptable levels before it enters the process equip ment. The choke manifold is composed of four gate valves (five if a bypass b ypass valve is included), a variable choke box, a fixed choke box and tapping points for measuring upstream and downstream pressures. A thermometer well is usually provided. Each chok e 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.


Det Norske Veritas

Design codes


Assembly number

M-837771

M-838980

Project code

FMF-ABJ

FMF-CCM


Yes

No

Working pressure

10,000 psi [690 bar]

10,000 psi [690 bar]

Test pressure

15,000 psi [1035 bar]

15,000 psi [1035 bar]

Nominal ID (drift)

3 1 Ž16 in. [78 mm]

3 1 Ž16 in. [78 mm]


2 in. [51 mm]

2 in. [51 mm]

Choke bean series

D-72

D-72

Protection





PSL 2


DD (H2S)


P+U, 20 to 250°F [28 to 121°C]

Connections

Outlet


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]

Weight

4950 lbm [2250 kg]

3850 lbm [1750 kg]

Description

The choke manifold is used for controlling flow rate and reducing the effluent pressure to acceptable levels before it enters the process equip ment. The choke manifold is composed of four gate valves, a variable choke box, a fixed choke box and tapping points for measuring upstream and d ownstream 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.


Design codes

Det Norske Veritas equivalent DNV Drill ³N,² DOE SI 289 API 6A, NACE MR 01 75

Working pressure

15,000 psi [1035 bar]

Test pressure

22,500 psi [1380 bar]

Nominal valve ID

2 9 Ž16 in. [65 mm]


2 in. [51 mm]

Choke bean series

Cameron Unitaper

Protection




PSL 3


EE (H2S, CO2)


P+U, 20 to 250°F [28 to 121°C]

Connections

3-in. Fig. 2202 F WECO Inlet

Union

(optional 3 1 Ž16 -in. CIW hubs)

Outlet

3-in. Fig. 2202 M WECO

Union (optional Graylock C-25 hubs) Dimensions

Length

65 in. [1.64 m]

Width

105 in. [2.67 m]

Height

44 in. [1.22 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. Th is 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 t he 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 onequarter 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 In this training page, we have discussed:  





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. 2. 3. 4. 5.

What is the role of a choke manifold? Why is the choke manifold equipped with an adjustable choke and a fixed choke? Why is it important to establish critical flow across the choke manifold? What measurements are usually monitored at the choke manifold? 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 t he upstream pressure is building up rapidly. What is the t he 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 t o open the valve does do es not exceed the ESD limit of 6,000 psi hydraulic pressure. In well testing operations, the ESD controls the h ydraulically-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 chok e. 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 the choke manifold, upstream of heater/steam exchanger, and upstream of the separator. The hi-pressure pilot initiates well closure when the pressure in 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 Upon completion of this package, you should be able to:  

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.

Principles of Operation 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 pn eumatic (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 simultaneousl y 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 ha ndle is released.

ESD armed

When the V7 by-pass valve is released (V5 remains open) air flows through the V9 velocit y 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 th rough a small orifice in V9. The small orifice in V9 is always open to compensate c ompensate 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 Th e 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 p ressure principles as the ESD stations. The hiand 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. 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 ex pects the pressure in the flow line to remain at or below a preset pressure value which is set by b y 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 h ydraulic pressure from the actuator and closing the valve on the flow line.

Lo-Pilot Normal Operation

In normal operating mode, the lo-pilot expects ex pects 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 h ydraulic 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 k eep the flow line valve open. If the pressure rises above the th e 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. 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 demon strates 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

con trol the hydraulically activated flow line valve on the Comment: The ESD is designed to control 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 system also allows the reopening of the flow line valve after closure. The animation will show how each special valve works by using generic gen eric 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 ne edle shown is actually static and adjusted only during a shop check.

Mac

PC

Read me!

Read me!

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

Equipment The ESD consists of a pneumatic control con trol console which consists of the various switches and controls used to pressurize the pneumatic (air) and h ydraulic (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 oth er two are low-pressure hoses for connecting to the ESD stations or the hi/lo-pilots. The console has 4 air outlets that c an either be connected to the remote stations or the hi/lo-pilots.

Description

The Emergency Shutdown System S ystem (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 lo w-level threshold (flowline leakage). The ESD-BB system consists of an ESD control co nsole skid that includes a pump, hydraulic h ydraulic 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.


None

Assembly number

P-579063

Project code

ESD-BB

Working pressure

6000-psi maximum actuator pressure

Protection


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]

Weight

1012 lbm [460 kg]

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 These control stations are necessary to ensure the well can be controlled from more than t han one place. Be sure to open o pen the air vessel inlet valve to ensure that the ESD is operational, o perational, 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 In this training page, we have discussed:  





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. 2. 3. 4. 5. 6. 7.

Which valve(s) does the ESD activate? What are the fluids used in the ESD system? Is it possible to use an ESD when H2S is present in the well effluent? How is the ESD activated? Where are the push-button stations usually located? How does a low-pressure pilot work? 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 dr op 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 w ater 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, 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 o f oil and gas because of improper separation, emphasize the need for special equipment and procedures to handle foaming oil. Heat is one o f 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 Upon completion of this package, you should be able to:  



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 o f 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 bot h coils. Follow recommended safety procedures when operating a steam exchanger. Divert the flow to bypass the steam exchanger.

Principles of Operation The steam exchanger is a steam vessel with two coils through which the well fluid p asses. A choke assembly between the coils allows the well to be controlled at the steam exchanger ex changer 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 safet y 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 ex changer 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 temp eratures than could be obtained with water.

The parts of the steam exchanger exchan ger are illustrated in the "Steam Exchanger" diagram an d 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 m aintain 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 r egulates steam intake.

Steam trap

The steam trap is mounted on o n 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. t emperature. o The temperature of the steam is about 90 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 w ell effluent can be liberated with the steam. Offshore the vent line goes overboa rd. 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 w hich 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 a nd choke. The steam flow into the vessel is regulated b y an automatic control valve on o n 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 safet y 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

Assembly number Project code Certifying authority

M-873488 M-873328 STX-BBS STX-CCN Det Norske Veritas

M-874456 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 10,000 psi 15,000 psi [338 bar] [690 bar] [1036 bar] Test pressure Valves 10,000 psi 15,000 psi 22,500 psi [690 bar] [1035 bar] [1380 bar] Coils 7350 psi 15,000 psi 22,500 psi [500 bar] [1035 bar] [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 4.3 MMBtu/hr (4970 lbf/hr steam at 120 psi and Heating capacity 340°F) Relief valve size 6 in. 6 in. 6 in. API 6A CLASSIFICATIONS Product specification PSL2 PSL3 PSL3 level Fluid classification DD (H2S) EE (H2S, CO2) EE (H2S, CO2) Manifold temperature classification P+U, -20 to 250°F [-28 to 121°C] Connections 3-in. Fig. 1002 3-in. Fig. 1502 3-in. Fig. 2202 Inlet (WECO Union) F F F Outlet (WECO Union) 3-in. Fig. 1002 3-in. Fig. 1502 3-in. Fig. 2202 M M M Steam supply 3-in. Fig 206 inlet, 2-in. Fig. 206 outlet DIMENSIONS Height Without relief valve With relief valve Width Length Weight Empty Full of water Protection Options

101 in. [2.62 m] 101 in. [2.62 m] 101 in. [2.62 m] 137 in. [3.49 m] 137 in. [3.49 m] 136 in. [3.47 m] 92 in. [2.34 m] 92 in. [2.34 m] 92 in. [2.34 m] 258 in. [6.55 m] 258 in. [6.55 m] 258 in. [6.55 m] 22,075 lbm 22,625 lbm 35,320 lbm 35,870 lbm Marine anticorrosion coating

23,180 lbm 36,420 lbm

6-in. bursting head M-839101 6-in. rupture disc, 250 M-839102 psi 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)

ex changer must be used because safety safet y regulations Note: In some countries, a steam exchanger prohibit the use of indirect heaters. The steam exchanger is intrinsically safe in terms 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 t emperature controller of the steam exchanger.

Safety The following is a list of key safety considerations for steam exchan gers:  



  

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 t he 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 t hermal expansion that results can generate enough pressure to burst the coils.

Maintenance For information about the preparation and functional fun ctional checks for the steam exchanger, see the recommended steps in the "Field Operating Hand book (FOH) for Surface Well Testing." For information about equipment maintenance, see the maintenance manuals for the steam exchanger.

Summary In this training page, we have discussed: d iscussed:    

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. 2. 3. 4. 5. 6.

Why is it sometimes necessary to heat up the well effluent? What is the purpose of the choke assembly? Why is the steam exchanger safer than t han the indirect heater? How is the steam kept inside the vessel? What precaution should be taken before starting the steam exchanger? 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 t emperature 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 dr op 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 w ater 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, 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 o f 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.




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. t hrough. 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 bot h coils. Follow recommended safety procedures when operating an indirect heater. Divert the flow to bypass the indirect heater.

Principles of Operation 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 h eated by a flame from a diesel d iesel 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 c arrying the fluid to be heated and the flame that's used as a heat source. This system s ystem is intrinsically safer than a direct heater in which the tubes containing the well effluent are in direct contact wi th the flame. A common example of a direct heater he ater 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 chok e 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 p reset 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 ex tinguished. The internal design of the vessel is such that con vection currents prevent any localized heating o f 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 t he water, its temperature is approximately the same as the water, even though the combustion temperature inside the tube m ay be greater than 16 5o 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 t he 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 p ush 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, w hen 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 v alve'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 or iginal position immediately. This delay allows the water temperature to rise slightly above the set point. If the temperature of the water begins to rise, t he 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 r eturn 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 c ycles around the set temperature. This variation around the set temperature can affect p ressure readings at the separator. Flameout shutdown

This safety system, known as the t he 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, or ifice, 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 t he 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 o f the return spring. Consequently, there is no danger of diesel being supplied to the main m ain 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 w ater vessel is heated by a diesel d iesel 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 a nd 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

Assembly number Project code

M-873329 IHT-BAF

Design codes Coil temperature rating Working pressure Test pressure Valves Coils Coil description Nominal valve ID Choke size Choke bean series Heating vessel Heating capacity Diesel supply required Air supply required Safety devices

API 6A classifications Product specification level Fluid classification Manifold temperature classification CONNECTIONS Inlet Outlet Diesel inlet DIMENSIONS Height Without chimney With chimney Width Length Weight Empty With pipe work set Protection Options Air-driven diesel fuel pump (PMP-C) Positive choke bonnet assembly

API 6A, API 12K, NACE MR 01-75, ANSI B3 1-3 -20 to 350°F [-28 to 175°C] 4900 psi [338 bar] 10,000 psi [690 bar] 7350 psi [507 bar] 4-in. XXH by 4-in. XXH 3 1/8 in. 1 1/2 in. D-68 81 in. x 12 ft (2.3-psi working pressure) 2 MMBtu/hr 120 liter/hr at 70 psi [5 bar] 25 scf/min at 70 psi [5 bar] Diesel shutdown valve, activated by pilot light stoppage; flame arrestor on burner air inlet

PSL2 DD (H2S) P+U, -20 to 250°F [-28 to 121°C]

3-in. Fig. 1002 F WECO Union 3-in. Fig. 1002 M WECO Union 1/4-in. NPT

104 in. [2.64 m] 156 in. [3.98 m] 88 in. [2.25 m] 230 in. [5.85 m] 25,250 lbm [11,450 kg] 27,440 lbm [12,450 kg] Marine anticorrosion coating

M-801364 M-805110

Protective panels for frame

M-804203

The indirect heaters are available in 3000 3 000 and 5000 psi pressure ratings. The 3000 psi version is heli-portable. The heating capacity expressed exp ressed 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 a ccommodate the required well test without having h aving to use equipment that is larger, more complicated, or more ex pensive 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: 

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A perfect understanding of the diesel, propane, and air circuits is a prerequisite to a successful and safe job. Before starting or restarting the t he 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.

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Never flow the well through the coils if a choke is not installed. Sand particles or corrosive fluids can erode the threads in the t he 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 t he valves closed, the thermal expansion that results can generate enough pressure to burst the coils.

Maintenance For information about the preparation and functional c hecks for the indirect heater, see the recommended steps in the "Field Operating Hand book (FOH) for Surface Well Testing." For information about equipment maintenance, see the maintenance manuals for the indirect heater.

Summary In this training page, we have discussed:    

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. 2. 3. 4. 5.

List five reasons to raise r aise the temperature of the well effluent. Why is this heater called an indirect heater? How is the temperature of the indirect heater regulated? Briefly explain how the flameout shutdown system works. What is the important thing to do prior starting or restarting the indirect heater?

E) SEPARATOR

Introduction The "Surface Test Equipment" figure shows whe re 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 s ystem that carries separated fluids out of the vessel. Its principle function is to separate the well effluent leaving the chok e 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 effluent components and take pressurized oil and gas samples.

Separators are classified by their shape and b y 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 a nd 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.

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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.


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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. r ecorders. 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.

Principles of Operation The operating principles for the separator are cove red 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 furt her 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 enou gh 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 2 0 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 mechanic al 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. Th e function of these mechanical devices devic es 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 liq uids 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 pa sses 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 o f wire mesh, like the mist extractor. It prevents oil particles in the foam (comprised of oil and gas) from passing th rough the separator and being carried awa y 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 do wn.

Weir Plate

This plate, located at the bottom of the vessel, divides the separator into two compa rtments: oil and water. Provided that the water level is controlled, it only permits oil to overflow into the o il 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 a nd 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 the se parameters as constant and stable as possible. Although the tem perature inside the separator is almost equal to the well effluent temperature and cannot be controlled (unless a heat exchanger is conne cted 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 ex amples of how the pressure, gas-liquid interface, and temperature can be used to control separation problems. Separation Problems Problem

Liquid carryover Liquid carryover

Causes

Action

High flow rate

Decrease flow rate

High liquid level

Lower oil/gas interface

Low operating pressure

Raise operating pressure or decrease flow rate

Reduce sensitivity of oil level controller Wave action in separator Increase pressure Foaming

High viscosity Poor oil-gas separation

Heat well effluent Increase retention time

High separator pressure Reduce pressure

Separation Processes

Pressure and Level Controllers This topic covers the controller systems and their associated equipment. Th e gas pressure controller and the oil and water level controllers maintain constant separation conditions inside the tank. To adjust the separator sep arator pressure and the water and oil flow rates, all the controllers use automatic control valves (ACVs). The compressed air used to op erate the controllers is filtered through an air scrubber. The air pressure is reduc ed 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 cond itions of the well. To maintain a constant pressure p ressure 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 con trolling pressure is with a pressure controller that uses a control valve to automatically react to any an y 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 suppl y 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 b y 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 mode l 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 e stablish the set point pressure. Pressure from the separator is applied directly to the Bourdon tube. The "Gas Pressure Controller - Proportional Propo rtional 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 b y 

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The Bourdon tube moves the flapper toward towar d 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 o riginal 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 b y 

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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 t o 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 t he atmosphere through chamber I. This reduction in pressure causes the ACV valve to open under the action of its spring.

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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 t he 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 d ecreased (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" diag ram, 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 ex pressed as a percentage, based on the th e Bourdon tube pressure rating, as described in the following examples. This percentage can vary va ry 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 n arrow (5%) and a wide setting (50%) of the proportional p roportional band changes how the system reacts to a variation in pressure.  

The pressure controller is equipped 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 o f the Bourdon tube rating of 1000 10 00 psi, this means that the ACV will be fully closed when the separator p ressure 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 pressure variation of 250 psi on either side of the separator set point of 400 psi to either e ither 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 3 75 psi and fully open when the separator pressure reaches 425 psi. At this narrow setting, the s ystem is sensitive to small

pressure variations. The system will either close 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 ba nd 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 ban d 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

PC

Read me!

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: 

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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 ch anges the volume of gas and liquid in the separator, which in turn affects the speed and the retention time of the two fluids. The Th e initial set point for the liquid-gas level depends on the gas-oil ratio (GOR) of the well effluent. 

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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 o il level is required.

To cover different GORs, from the oil level co ntroller, 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 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 mo ves 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 th e 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 b y 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 t he 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, t ank, causing similar problems.

Complex Oil Level Controller

The "Oil Level Controller" figure above shows a simple model of an oil o il 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 po int lever allows the desired level of liquid to be set (providing that the oil level is between t he top and the bottom

of the plunger). The diagram shows the oil level controller in a state of equilibrium: equ ilibrium: 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 an d the nozzle and reducing the air passage. Because chamber A is constantly supplied with air through orifice B, the reduction in this t his 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 o il 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 o f 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 o utlet flow, the level of oil in the separator decreases:    



The flapper moves away from the nozzle, widening the gap between the nozzle and t he flapper. This causes the air pressure in chamber A of the relay to t o 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 t o 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 rela y chamber F flows to the automatic control valve and also flows to the proportional band three-wa y valve. The orifice of this valve is adjustable so the amount of air pressure or "feedback" "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 d isplaced (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 t o 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 Fo r 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 con troller 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 chang es the volume of gas and liquid in the separator, which in turn affects the speed and the retention time of o f 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 cov ered in the next version of this animation. a nimation. 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 t he 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 cl oser to the nozzle, causing it to leak air. The air leak from the nozzle is used to open or close a control con trol valve on the separator water outlet.

Automatic Control Valves 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 mo nitor 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 p ressure 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 b y an air compressor. This air from the compressor is first filtered using an air scrubber. The air scrubber is simply a ve rtical pot where the impurities and water settle. After the air is 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 Principles of Operation

Safety Devices In case a malfunction causes the separator pressure to rise to a dangerous level, these d evices 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 cann ot 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 cou ld open within a range of o f 85% to 95% of the WP. Consequently, the operating pressure in t he separator should be kept a t 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 o r below 80% of WP (1152 psi). Check Valve

The check valve is located loc ated 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, 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 a way 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 an y other malfunction of the safety relief valve, the separator is equipped with an additional safety d evice 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 v ery 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% 11 0% of the nominal (600 psi, 720 psi or 1440 psi) separator working pressure (WP). Due to temperature influence and calibration tolerances, it cann ot be guaranteed that the rupture disc will burst at ex actly 110% of WP. It is safe to assume that the disc could burst within a range of 105% 105 % to 115% of the WP. Using this range of values helps ensure, in case of an emergency, eme rgency, that the safety valve will always operate before the disc ruptures.

Safety Devices Principles of Operation

Metering Devices This topic looks at the meters used to measure flow rates for oil, gas, and water as th ey leave the separator. To measure low to high oil flow rates, a positive displacement meter and a vo rtex 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 wat er outlet. The shrinkage factor, measured using a shrinkage tester, represents a correction factor used in oil volu me 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 h igh 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 w ith a 2-in. diameter positive displacement meter that can measure a flow rate from 100 1 00 to 2200 barrels per day. da y. The ball vortex meter consists of a body b ody with an offset chamber and a rotor that are mounted transversely to the flow stream. When liquid flows through the meter, a v ortex 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 magn etic coupling.

Separators used for testing can be equipped equippe d with a 2- or 3-in. diameter d iameter vortex meter. For this type of meter, the flow rate depends not n ot only on the size but b ut also on the type of bearings used as shown in the "Vortex Meters and Flow Rates" table. Vortex Meters and Flow Rates Rating with ball bearings in barrels

Rating with sleeve bearings in

per/day

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

Meter Type

The oil meters located upstream from the automatic control valves o perate under pressure, so the volume of oil measured is greater than if compared to standard conditions (atmospheric pressure o and 60 F). Oil passing the counter may ma y 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 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 or ifice plate to be changed without interrupting the gas flow. The orifice gas meter is designed for this purpose. 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 chan ge the orifice plate in the gas orifice o rifice 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 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 b y 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 up stream 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 u sed to record the static pressure, measured downstream of the orifice plate. In addition, anoth er 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 ho w 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 out put 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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Gas Scrubbers

The gas used to operate the t he 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 scrubb ers 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 o il sight glass of the separator, is used to estimate the shrinkage factor in the field. The shrinka ge 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 pressure to the atmospheric pressure. The shrinkage tester consists of a bottle equipped with a graduated sight glass. Oil and gas g as 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. procedu res. 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 vo lume will change as soon as the dissolved gas disappears under und er 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 Principles of Operation

Piping Systems This topic describes the functions of the other equip ment that's attached to the separator piping system: valves, a bypass manifold, and tapping po ints. Valves

The "Separator Layout with Bypass" drawing sho ws 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 p assing 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 met er 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 conn ect pressure and temperature recorders. The separator is equipped with hammer wing unions for quick connection and disconnection of pipe work.

Piping Systems

Principles of Operation

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 a n helicopter. Because of its lower working pressure, the metal is thinner so the ov erall vessel remains light. The 720 psi is designed to handle high flow rates of oil, because its extended length len gth 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 o f separators and their characteristics. For each drawing, specifications are provided

Description

The three-phase test separator allows separation, metering and sampling o f all phases of well effluent. The horizontal test separator is capable of handling most types of fluid found in today¹s toda y¹s

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 lev el 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 stand ard on each separator.

Specifications Assembly number

P-873485

P-579035

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

1480 psi [102 bar] at

100°F

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]

Protection Load factor

Marine anticorrosion


coating

coating

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

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

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]

28,260 lbm [12,800 kg]

28,260 lbm [12,800 kg]

Outlets (WECO Union)

DIMENSIONS Height

Weight Empty

With piping set

30,900 lbm [14,000 kg]

30,900 lbm [14,000 kg]

P-579040

M-808721

P-579041

M-806275

P-579082

P-579083

Options

Shrinkage tester (SKTAB/AC) Shrinkage tester (SKTD/C) Low gas flow skid

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 co nsists of an inlet manifold and metering instruments, including an orifice meter for measuring gas flow rate, a positive di splacement 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 d isc 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 stand ard on each separator.


K-874015

Project code

SSEP-HFE


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


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 Inlet

3-in. Fig. 602 F WECO Union

Gas Outlet


Oil/water outlets


Sampling points

1/2-in. NPT F CONTROL/MEASUREMENT

DIMENSIONS

VESSEL SKID

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]

Protection


Option

Shrinkage tester (SKT-A) M-874520

Description

The three-phase test separator allows separation, metering and sampling o f all phases of well effluent. The horizontal test separator is capable of handling most types of fluid found in today¹s toda y¹s 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 con tains 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 d isc system. The outlet from the relief valve can be vented to the gas outlet or to an independent line. A separatormounted shrinkage tester is available to measure the o il 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.


K837655

K-579042

Project code

SEP-SGF

SEP-SGM


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


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

High liquid level Liquid High level

25 MMscf/D [0.71 MMm3 41 MMscf/D [1/16 MMm3 /D]

/D]

13 MMscf/D [0.37 MMm3 18 MMscf/D [0.51 MMm3 /D]

/D]

10,000 BLPD [1600 m3 /D] 23,800 BLPD [3783 m3 /D] 5000 BLPD [800 m3 /D]

10,500 BLPD [1669 m3 /D]

at 1-min retention time

at 1-min retention time

0 psi

6.6 psi

3-in. Fig. 602 F

3-in. Fig. 602 F

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

Low level Load factor 1

CONNECTIONS Inlet (WECO Union) Outlets (WECO Union)

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]

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

M-808721

M-808721

M-806275

M-806275

P-579083

P-579083

Weight

Protection

Options

Shrinkage tester (SKTAB/AC) Shrinkage tester (SKTD/C) Low gas flow skid

Water circuit control set M-874445

M-839169

Protective side panels

M-839175

M-839170

Separator Selection Guidelines

The principal criteria for selecting a separator are: 

Project requirements related to working pressure, emulsion, foam, and cost considerations.

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

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.

Additional selection considerations are:   



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 b y 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: 

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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 t he 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 In this training page, we have discussed:    

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 o ptimize the separation. Using the shrinkage tester to get an accurate shrinkage factor.

Self Test 1. 2. 3. 4. 5. 6. 7.

What are the main functions of a separator? What processes does the separator use to separate oil, gas, and water? Why should a separator be run at a constant pressure? How is the separator pressure controlled? What type of ACV is mounted on the separator gas line? Why? What is the shrinkage measurement used for? 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 t he 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, t ank, 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 o f time.

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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 m ay not be correctly calibrated. By comparing t he 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 m eter'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 Upon completion of this package, you should be able to:   

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.

Principles of Operation This topic lists the main components of the gau ge tank and describes how the tank is used to calibrate meters. Click on the graphic or scroll do wn 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, 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 o f 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. 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 gr ease. 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 accurac y 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 b y the presence of the gas. To correct the volume reading at the oil meter, a correction factor is derived by comparing the vol ume reading at the oil meter with the volume measurement obtained at the t he tank. The volume correction co rrection 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 t he 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 o utlets for liquid or foam carryover 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 o standard conditions: 14.65 psi (atmospheric) and 60 F.

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

PC

Read me!

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 (FGTSA/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, 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 Assembly number Project code Capaci Cap acity ty Service Working pressure Working temperature Compartments Safety devices

Load factor 2-in. rupture disc setting Protection

None M-806271 FGTS-A 50 bbl [8 m ] Standard Atmospheric

M-807480 FGTS-B 100 bbl [16 m ]

M-872892 FGTS-C 200 bbl [32 m ]

32 to 200°F [0 to 93°C] 2 2 flame arrestors and bypass grounding device shearing roof set at 0.5 psi 12 psi 14 psi 1600 psi [112 1600 psi [112 bar] bar] Marine anticorrosion coating

10 psi

CONNECTIONS Inlet 2-in. LP Fig. 602 WECO Union Outlet 3-in. LP Fig. 602 WECO Union DIMENSIONS Length Width

120 in. [3.05 m] 199 in. [5.05 m] 346 in. [8.80 m] 87 in. [2.21 m] 87 in. [2.21 m] 87 in. [2.21 m]

Height Weight (Empty)

96 in. [2.40 m] 96 in. [2.40 m] 96 in. [2.40 m] 4400 lbm [2000 10,000 lbm [4536 18,000 lbm [8165 kg] kg] 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..

Additional selection considerations are:  

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: 

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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.

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Prior to conducting any repair inside of o f the tank, it must m ust 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 t he 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 and the "FOH for Surface Well Testing."


The functions of the gauge tank.



Why and how the gauge tank is used to calibrate the meters. meters.



The main components of the gauge tank.



The key safety points to observe when using a gauge tank.

Self Test 1. 2. 3. 4. 5.

Why is the gauge tank not used when H2S is present in the well effluent? What are the two main uses of the gauge tank? How is it possible to inspect the inside of the tank? What is the purpose of the safety seams? 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 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 o riginally 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.

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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 t he 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 o f 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 m ay not be correctly calibrated. By comparing t he 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 m eter'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.


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 Review FIT and TRIM procedures for the surge tank.

Principles of Operation This topic lists the main components of the surge tan k and describes how the tank is used to calibrate meters. Click on the graphic or scroll do wn 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 sur ge tank fluid discharge from entering the upper part of the v alve 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 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 g lass 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 o riginal 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. 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 o f 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 g rease. 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 var iation in the surge tank pressure. When the pressure rises, t he 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, t he 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 m ounted 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 accurac y 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 b y the presence of the gas. To correct the volume reading at the oil meter, a correction factor is derived by comparing the volu me reading at the oil meter with the volume measurement obtained at the t he tank. The volume correction factor is also referred to as the "meter combined shrinkage" factor. The following steps are needed to accurately a ccurately 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 t he 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 o utlets for liquid or foam carryover carryover.. To avoid carryover, do not allow more than 80% of a tank t ank 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 o standard conditions: 14.65 psi (atmospheric) and 60 F.

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 Project code Capaci Cap acity ty Compartments Working pressure Load factor (in use) Gas flow rate Certifying authority Design codes Service Working temperature Safety devices

Protection

M-839644 P-872885 VST-B VST-D 80 bbl [12. [12.9 9m ] 100 bbl [15. [15.9 9m ] 1 2 50 psi [34 bar] 150 psi [103 bar] 23 psi 20 psi 4.76 MMscf/D 13 MMscf/D Det Norske Veritas DNV Drill "N," DOE SI 289, NA CE MR01-75 H2S -20 to 200°F [-28 to 98°C] Pressure relief valve High- and low-level alarms Grounding device High-low pressure pilot (optional) Inert gas injection (optional) Pneumatic level controller (optional) Marine anticorrosion coating

CONNECTIONS Oil inlet Oil outlet Gas outlet Relief valve output Drain outlet

3-in. LP Fig. 602 WECO Union 3-in. LP Fig. 602 WECO Union 4-in. LP Fig. 602 WECO Union 4-in. LP Fig. 602 WECO Union 3-in. LP Fig. 602 WECO Union

DIMENSIONS Height Length Width Weight

19 ft 9 in. [6 m] 7 ft 11 in. [2.4 m] 7 ft 11 in. [2.4 m] 13,250 lbm [6100 kg]

24 ft 3 in. [7.4 m] 7 ft 11 in. [2.4 m] 8 ft 6 in. [2.6 m] 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.

Additional selection considerations are:     

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 t he 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 r elief 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

PC

Read me!

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 and the "FOH for Surface Well Testing."


The main applications of the surge tank.



Why and how the surge tank is used to calibrate the meters. meters.



The main components of the surge tank.



The key safety points to observe when using a surge tank.

Self Test 1. 2. 3. 4. 5. 6.

Give three reasons for using a surge tank. How is the volume of oil contained in the surge tank calculated? What is the purpose of the ACV mounted on the gas line outlet? How is it possible to prevent back-pressure from entering the surge tank? Why is it important to prevent back-pressure from entering the surge tank? 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 conn ected to the oil outlet line of o f 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 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. 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.




Explain the main purpose of the transfer pump. Describe the operating principles for the two types o f 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 ex ercises 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.

Principles of Operation There are many different types and models of pumps. However, most pumps can either be broadly classified as positive displacement or centrifugal, 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 p iston 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 p ositive 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 b y 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 T ype 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 Pump

The pump shown in the "Screw Type Transfer Pump" diagram is usually usuall y called a screw pump. Although the geometry of its pumping elements may m ay seem complex, its operating principle is simple. The rotor and rubber stator are the k ey 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 B ypass 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 onl y circulate through the pump. This ensures e nsures 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 Ju st before the pump is stopped, the valve is turned back to its original position so fluid can circulate through the p ump. 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 t ype 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 m uch 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 wh eel called an impeller that uses centrifugal force to impart high velocity to the liquid, and then converts most of this velocity to pressure. p ressure. This type of pump can discharge di scharge 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 p ower 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 e asier 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 b y 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 p ump 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 t he 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 t he 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 t ank 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 e liminate 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 p ump 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 o f transfer pumps and their characteristics. For each drawing, specifications are provided.

Description The transfer pump is used to empty empt y one compartment of a tank while the other is filling. The effluent can be pumped directly d irectly tothe burner or reinjected into an existing flowline

The unit consists of an electrically driven gear pump with an explosion-proof 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

M-816551

M-872831

M-837654

Project code

PMP-ECB

PMP-FAA

PMP-TCB

Certification

None

number

DNV type approval

None

Capacity at 250 2000 BOPD

2000 BOPD

2000 BOPD

psi

[318 m3/D]

[318 m3/D]

[318 m3/D]

Service

Standard

Standard

Standard

Operating

32 to 200°F

32 to 200°F

32 to 200°F

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

EExd II B T4

EExd II B T4

temperature Motor

Explosion proofing

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

Marine

Marine

anticorrosion

anticorrosion

anticorrosion

coating

coating

coating

3-in. LP Fig. 206

3 -in. LP Fig. 206

3 -in. LP Fig. 206

WECO Union

WECO Union

WECO Union

2-in. LP Fig. 206

2-in. LP Fig. 206

2-in. LP Fig. 206

WECO Union

WECO Union

WECO Union

Height

34 in. [0.86 m]

34 in. [0.86 m]

37 in. [0.93 m]

Length

52 in. [1.30 m]

52 in. [1.30 m]

59 in. [1.50 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]

Connections

Inlet

Outlet

Dimensions

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 o il control valve. The pump is rated for H2S service. With its explosion-proof motor and starter, the pump is suitable for Zone 1 use.


Det Norske Veritas

Design codes

DNV Drill "N," DOE SI 289

Assembly number

M-816514

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

Protection


Connections

Inlet

3-in. LP Fig. 602 WECO Union

Outlet


Dimensions

Height

92 in. [2.34 m]

Length

81 in. [2.05 m]

Width

58 in. [1.47 m]

Weight

6512 lbm [2954 kg]

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 d irectly tothe burner or reinjected into an existing flowline.

The unit consists of an electrically driven screw pu mp 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 3 [636 m /D] at 300 psi

4000 BOPD 3 [636 m /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 mm

30 m of 4 x 25 mm

Transmission

Antistatic belt

Hydraulic

Usage

Zone 1

Safe area only

Protection



3-in. LP Fig. 206

3-in. LP Fig. 206

WECO Union

WECO Union

3-in. LP Fig. 602

3-in. LP Fig. 602

WECO Union

WECO Union

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]

Weight

3000 lbm [1350 kg]

4400 lbm [2000 kg]

Connections

Inlet Outlet Dimensions

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.

Additional selection considerations are: 

  

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 ob serve 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 t he 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) type) described in this training page. The importance of flooding of flooding the suction port of the transfer pump before running r unning the pump. The key safety points concerning the pumps.

Self Test 1. 2. 3. 4. 5.

What is the purpose of a transfer pump in a well testing setup? What types of transfer pumps are used in well testing? How do you decide which pump to use for a particular job? What factors should you consider? What is the NPSH? Why are the positive displacement pumps equipped with a safety relief valve?

J) OIL AND GAS MANIFOLD



Introduction The "Surface Test Equipment" figure shows whe re the oil and gas manifolds are located loc ated 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 man ifold (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.


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.

Principles of Operation Oil Manifold

The oil manifold shown in the "Oil Manifold Flow Paths" diagram is composed of an arrangement of piping, five ball valves, valves, and wing union connections. connections. This arrangement makes it possible to divert the oil without interrupting the flow. The possible flow 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 ar e 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 o pen; 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. If a double compartment tank is used, one compartment can be filled while the other is o 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. If a single compartment tank is used, the tank is emptied when the well is shut in. The o 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.  

 

w ith a plug. Note: When one outlet of the oil manifold is not used, it is usually sealed with Gas Manifold

The gas manifold in the "Gas Manifold Flow Paths" drawing shows how the g as 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 leav ing the separator to be diverted to either one burner or the other, depending on the wind direction.

Equipment There is only one type of o f oil manifold. Its flexible configuration of valves and ports makes it possible to accommodate various well testing setups. If the setup 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 gau ge tank or directly to the burner through t hrough the oil manifold. Oil from the tank is also pumped to the burner by way wa y 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


Det Norske Veritas

Det Norske Veritas

Design codes

NACE MR 01 75

NACE MR 01 75

Assembly number M-810537

M-810538

MFD-ACA

MFD-ADA

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]

3-in. Fig. 602

3 -in. Fig. 602

WECO Union

WECO Union

58 x 28 x 15 in.

38 x 15 x 16 in.

Project Code Working pressure

Connections

Dimensions

[1.47 x 0.71 x 0.38 m] [0.95 x 0.38 x 0.16 m] Weight

473 lbm [215 kg]

286 lbm [130 kg]

Protection



There is only one type of o f 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 In this training page, we have discussed:   

The function of the oil and gas manifolds. The relationship between the flow paths of the oil and the position of the valves. valves. Key safety points for the oil and gas manifolds.

Self Test 1. 2. 3. 4.

Draw a standard well test setup showing the different elements connected to the oil manifold. What is the pressure rating of the oil manifold? Why? What type of valve is usually mounted on the oil and gas manifolds? 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 S chlumberger 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. 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.


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.

Principles of Operation To efficiently combust well effluent without producing unburned pa rticles and smoke, the well effluent must be reduced to very fine droplets. Thi s process, called atomization, is achieved by: b y:  

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, n ozzle, compressed air provides the energy required for further atomization. Compressed air leaves the air nozz le in a rotary motion at a velocity v elocity 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 ox ygen and avoids the formation of carbon black. The

flame burns clear and yellow (no unburned u nburned 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 p roduce excessive black smoke (too rich in oil) or excessive white smoke (too rich in water). The size of the air and oil nozzles noz zles 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 compon ents 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 o ptional pneumatic rotation system is also available; it allows the position of the t he 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 po lluting the environment. The mud burner bu rner can also be used to burn high viscosity oils. The mud burner is comprised of three combustion heads fitted on a supporting frame. Th e 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 nec essary. 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. ox ygen. A drip pan is installed under the heads to collect the hydrocarbon liquids that may have condensed. The "Mud Burner" drawing shows a typical t ypical 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 "BurnersBooms" chapter of the "Field Operating Handbook (FOH) Vol. II," and in the mud burner b urner 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 b urner.

The boom contains the necessary n ecessary 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 o ne head model, exist in two versions: standard and H2S service. These drawings show examples of several types o f burners and their characteristics.

Description

The Spitfire oil burner is a high-capacity, high-capacit y, 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 th e atomizer head and combined com bined with compressed air, emerging in tiny droplets. These droplets are ignited b y 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 nozz les 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 h ead to turn 75 degrees to either side of the boom axis.

Specifications

Certification

None

Assembly number

M-808872

Project code

BRN-ADA

Service

Standard

Number of heads

1

Maximum effluent flow Operating at 200 psi Operating at 350 psi Operating at 465 psi

4200 BOPD [668 m /d] 3 5500 BOPD [875 m /d] 3 6000 BOPD [955 m /d]

Minimum effluent flow

100 BOPD

Air sup supply ply

350 ft /mi /min n [9. [9.91 91 m /mi /min] n] at 100 psi

Maximum water supply

8000 B/D [1275 m /d] at 75 to 230 psi

Ignition supply

110-V AC, 50/60 Hz

Protection


3

CONNECTIONS Effluent


Water


Air


Propane for gas pilot

1/2-in. LP

DIMENSIONS Width

37 in. [0.96 m]

Length

41 in. [1.05 m]

Height

75 in. [1.90 m]

Weight

660 lbm [300 kg]

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 cleanl y 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 combine d with compressed air, emerging in tiny droplets. These droplets are ignited b y 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 nozz les, 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 h ead to turn 75 degrees to either side of the boom axis. The Seadragon burner is available with 3, 3 , 4 or 6 heads to suit the amount of effluent requiring disposal.

Specifications (BRN-ABC/ACA)

Certification

None

None

Assembly number

M-812172

M-803895

Project code

BRN-ABC

BRN-ACA

Service

Standard

Standard

Protection


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]

Weight

1660 lbm [750 kg]

1875 lbm [850 kg]

CHARACTERISTICS Maximum effluent flow Operating at 200 psi Operating at 350 psi Operating at 465 psi

7500 BOPD [1192 3 m /D] 10,000 BOPD [1590 3 m /D] 12,000 BOPD [1908 3 m /D]

10,000 BOPD [1590 3 m /D] 13,300 BOPD [2115 3 m /D] 16,000 BOPD [2544 3 m /D]


100 BOPD per head

Air sup supply ply



18,000 BWPD [2862 m /D] at 75 to 230 psi

Ignition supply

110-V AC, 50/60 Hz

3


3-in. LP Fig. 206 Union

Water


Air


Propane for gas pilot 1/2-in. LP LP Options

Pneumatic rotation kit

M-807718

Seawater filter

M-801519

Diesel pilot light kit M-807359

Specifications (BRN-HBC/HCA)

Certification

Det Norske Veritas

Det Norske Veritas

Assembly number

M-810075

M-834851

Project code

BRN-HBC

BRN-HCA

Service

H2S

H2S

Protection


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]

Weight

1660 lbm [750 kg]

1875 lbm [850 kg]

CHARACTERISTICS Maximum effluent flow Operating at 200 psi Operating at 350 psi Operating at 465 psi

7500 BOPD [1192 3 m /D] 10,000 BOPD [1590 3 m /D] 12,000 BOPD [1908 3 m /D]

10,000 BOPD [1590 3 m /D] 13,300 BOPD [2115 3 m /D] 16,000 BOPD [2544 3 m /D]


100 BOPD per head

Air sup supply ply



18,000 BWPD [2862 m /D] at 75 to 230 psi

Ignition supply

110-V AC, 50/60 Hz

3



Water


Air


Propane for for gas pilot 1/2-in. LP LP Options

Pneumatic rotation

M-807718

kit Seawater filter

M-801519

Diesel pilot light kit M-807359

Description

The Invert Oil Mud Burner was primarily designed for disposing of inv ert 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 he ads enable fine water droplets to penetrate pen etrate the flame, modifying combustion to eliminate black smoke. Water injection also redu ces radiated heat. A swivel joint supports the burner unit and allows the heads to move 60 degrees de grees to either side of the boom axis.

Specifications

Certification

Det Norske Veritas

None

Assembly number

M-872176

M-808206

Project code

BRN-HEA

BRN-AEA

Service

H2S

Standard

Protection


CHARACTERISTICS Upper head Maximum effluent flow Operating pressure Diesel flow rate Diesel injection pressure

5000 BOPD [795 m /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 m /D] 70 to 150 psi 3 3 350 ft /min [9.91 m /min] at 100 psi 3 18,000 BPD [2862 m /d] at 75 to 230 psi 28 gal/hr [127 liter/hr] at 100 to 200 psi 110-V AC, 50/60 Hz

3

3



Water


Air


Diesel, upper head


Diesel, lower head


DIMENSIONS Width

66 in. [1.65 m]

Length

49 in. [1.25 m]

Height

78 in. [1.98 m]

Weight

1800 lbm [810 kg]

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 H 2S 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 t he 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 d esigned for Schlumberger burners such as the Green Dragon*, Seadragon* and Mud Burner. Bu rner. 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 av ailable 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 secon d gas flare, diesel oil pipe work for the mud burner, burner head rotation kits and pilot p ilot light kits for the gas flares.

* Mark of Schlumberger

Specifications


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 -4 to 200°F 32 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]

Weight

8140 lbm [3740 kg]

Protection


85 gt [25.7 m]

85 gt [25.7 m]

11,252 lbm [5170 kg]

Wind speed limitation versus ice thickness

Semisub

Fixed installation

Case

Boom length

No. flares

C

60 ft

1

D

60 ft

2

G

85 ft

1

H

85 ft

2

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 de signed for use within the following performance parameters: Semisubmersible

Drillship

Rolling

±5 degrees, 9-sec period

±7.5 degrees, 12sec period

Pitching

±5 degrees, 9-sec

±5 degrees, 12-

Heaving

period

sec period

±0.5 g

±1.0 g

Applicable forces (newtons)

No. Ice Wind F1L flares (cm) (km/hr) Semisub

F1W

F2

F3

F4L F4W

F5

1

0

160

71755 41129 144011 8522 0 44963 7532

1

3

125

113355 84543 219110 19496 0 42375 7061

1

5

0

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

2

0

160

81758 42031 158574 10022 0 50004 7737

2

3

100

123064 92124 224053 21879 0 30499 4462

2

5

0

Semisub

144952 141824 261553 32225 0

163291 146560 283393 35402 0

343

78

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. Ice Wind F1L flares (cm) (km/hr) Semisub

F1W

F2

F3

F4L F4W

F5

1

0

160

101401 44355 180825 6306 0 62106 6619

1

3

115

149130 101548 260063 15151 0 49749 4974 9 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 4831 7 4187

Semisub

2

0

160

115983 43885 198693 7482 0 68411 6570

2

3

100

165134 108216 272674 17044 0 41767 4176 7 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

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.





 





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 b urner 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 e xplained, but the location selection is not covered in this animation.

Mac

PC

Read me!

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 read y to be lifted from the supply boat and installed on the rig. Once again all common safety, lifting, and handling practices are emphasized.

Mac

PC

Read me!

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 In this training page, we have discussed:     

The atomizer and its operating principles. The separate functions of the main components of the oil burner. burner. The mud burner. burner. The boom boom.. The key safety points that you should be aware of when working around burners and booms.



The preparation The preparation and installation of burners and booms.

Self Test 1. 2. 3. 4. 5. 6.

How did the oil burner make offshore well testing practical? What is the role of compressed air in the atomization process? What is the purpose of the hearth that's mounted around the atomizer? What is the purpose of the slanted slots in the swirl assembly? Why is diesel mixed with the oil-base mud in the upper head of o f a mud burner? 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 pie ces 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 an d 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.

Principles of Operation 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 o r 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 Ope rating 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 p ressure 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., 100 2) 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 p ressure 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 pie ce of piping, both the pipe and wing union working pressures (WP) must be compared. The lower WP is c hosen 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 (This is taken from a table in the "FOH for Surface Well

Testing.") 

The WP for the 3 in., 602 pipe is is 3000 psi.



Therefore, the WP WP of the whole pipe is 2553 psi.

This example applies only to new pipe. pip e. Wear and corrosion make it necessary ne cessary to inspect piping regularly and down rate the pressure rating accordingl y. 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 Su rface 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 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 o r 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 t he 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. t ests.

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 art iculated 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 t he service type required (H2S or non-H2S). Piping Racks and Baskets

To prevent unwanted accidents, acciden ts, 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: 

  

 

 











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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 m ust 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 m ust 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 Wireline and Testing Pressure Operations Guidelines.

Maintenance The basic maintenance of the piping before and after every job consists of:

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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 t he manufacturer's recommendations. recommendations.

A regular maintenance (Q-check) once a year consists of:  

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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 In this training page, we have discussed:     

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. 2. 3. 4.

Why is articulated piping or flexible hoses used between the flowhead and the choke manifold? What is the purpose of the Schlumberger piping color code? How is the piping for a surface testing layout selected? 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

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Downhole Testing and Drill Stem Testing

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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 b y 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 b y a compression packer and tester valve - the DST tools.

The DST tools and drill pipe are run back to the bottom bo ttom 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 to ward 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 de ciding the type of downhole equipment to be used during a well test. The downhole do wnhole 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 op timum string either for conventional DST or in conjunction with a production-type test string. Test objectives are normally well defined, howev er Schlumberger test tools allow a large amount of flexibility, if well-test programs have to be modified in order for these ob jectives 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 to ols downhole, while still maintaining maximum well control. Use of one or more downhole downho le control valves ensures the well can be b e 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

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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 r unning 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

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Packer isolates annulus from formation pressure Safety joint Jars Gauge carrier Tester valve 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 o 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 P h from Pf . A tester valve (located above the packer in the DST string) performs the following main functions: 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 t esting the tubing string above the tester valve. o 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 P c < 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 t he DST string. Some types can be opened and can also be reclosed. These types can be used to spot cushion fl uids 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 e nhance string efficiency, safety and versatility. The following are some of the available tools: 

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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 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.

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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  

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Pf > Pc: the well will flow Cleanup Cushion fluid o Rathole fluid o Formation fluid o 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 cu shion 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 ma y 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 p redetermined 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 occup y most of the length of the test string, the h ydrostatic 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 wh en the well effluent at surface changes to rese rvoir 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 p eriod 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 p referred 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 be fore 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 t o 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 o penhole, cased hole or barefoot. b arefoot.

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 hou rs 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, c apability, 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 the y 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 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 b e 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 o f 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 p acker 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 con siderations in string design. These can fall into three general categories catego ries 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.

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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.

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Offshore floater (semisubmersible rigs and drill dr ill 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 str ing expansion and contraction due to the various changes in the temperature in the drill dr ill 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 m anipulation 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 m ovement (heave) would interfere with the reciprocating actions required to operate the downhole tools.

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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 str ings 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 st atic bottom hole pressure  

Testing in openhole can be done as a very first investigation of the reservoir parameters. This could be done with logging lo gging tools which are faster and more efficient than u sing 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: 

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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.  

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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

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High equipment safety standard

Testing in casing has become more popular po pular over the years. The test design and the test program can be more flexible. One of o f 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. c aving-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: 

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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 t his 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 D ST tools and could be time saving.

We expect the following from a cased hole DST: 

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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 pr oduced for a longer period of time. t ime. 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 dr awdown pressure. Injection into the well with a treatment t reatment 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. 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 w hen 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 oints 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 t he packer as possible.

Backup reversing valve ; In case the lower reversing r eversing 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 t he 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 t he 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 w ill 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 st ill 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 t he 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 o f 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. str ing. 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 t hese 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, e ngineer, therefore, is the quality of the fluid data upon which these studies are based. Laboratory anal ysis 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 ob tain 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 onl y 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:   

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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 st ate 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. reservoir. Explain why bottomhole sampling is not suitable for gas wells.

Basics This topic outlines the general considerations and p rocedures for obtaining representative samples of formation fluids at the surface and dow nhole. 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 sa mple of the original reservoir fluid. In designing a sampling procedure, we must con sider 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, S imilarly, when the pressure in a gas condensate cond ensate 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 b y the selective loss of light or heavy hydrocarbons. h ydrocarbons. 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 t ypical 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 cate gory of the reservoir fluid. If the relationship between reservoir pressure and bubblepoint o r 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 ob tained is representative of the reservoir fluid at the sampling depth and sampling time. Timing is also an important consideration in obtaining a rep resentative sample of the original reservoir fluid. Obviously, it makes sense to sample as early as p ossible 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 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., bu bblepoint pressure (p b) correlations employed with early test data can determine d etermine 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:   

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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 prod uced 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 undo ubtedly yield free gas at the bottomhole flowing pressures and will require conditioning prior to sampling as exp lained 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 o r 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 th e 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 ma y be conditioned and sampled like an y 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. This gas may be due to coning. (i.e., The gas from the gas cap flows into the producing o 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. This gas may also be due to the flowing bottomhole pressure being less than the o 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 p roductivity that even a low flow rate requires a large drawdown. Reducing the drawdown enough enou gh 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 o rder

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 bot tomhole sampler is lowered. A gas-condensate well is also conditioned by b y flowing it at successively lower flow rates and monitoring the GOR. Generally, the GOR should decrease as the rate is decreased, because be cause 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 h ow 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 in clude      

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 n oted 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 o il 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 labo ratory 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 a rises 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 heav y 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 v erified 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 b e 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 p ressure (p b) may either be equal to the initial bottomhole static pressure (p wsi) (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 chok e size to ensure a flowing bottomhole pressure (pwf ) higher than the bubblepoint bubblepo int pressure. There is no gas liberation and the flow in the reservoir is monopha sic. On the other hand, in saturated satu rated 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 dipha sic. 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 mono phasic flow, when there is no free gas and k rg / k ro is equal to zero, the GOR is equal to R s and the well stream is identical to the reservoir fluid. This is the case of undersaturated reservoirs with pwf > p b 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 R s. In a two-phase flow, free gas exists and k rg z ero. GOR is then greater than R s rg / k ro is not equal to zero. and the well stream is different from the reservoir fluid. This is generally the case o f 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 bubblepo int pressure and compare it with the reservoir static and flowing pressures. For this purpose, the following data are n ecessary:     

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 p b .

This chart, called the Standing correlation chart, c an 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 compo sition of the oil being tested is considerably different from the average composition of the Californian Ca lifornian crudes used to create this chart, thus deviations ev en as high as 20% can be encountered (i.e. the bubblepoint pressure of a volatile oil with actual p b= 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 correlation and its value of pb < pwsi will confirm that the reservoir is undersaturated.

Bottomhole and surface sampling can be done d one with the well flowing at stabilized conditions co nditions at any flowrate for which pwf > p b . 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 correlation using GOR i = 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 t he 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 (GOR i). 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 > p wf > p b . 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 p b should be determined using the initial GOR i and compared with pws and p wf . If pws > p b > p wf : 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 productio n conditions where the GOR is very close to GOR i . Nevertheless, if surface samples have been taken with GOR > GOR i , they can be recombined reco mbined in the laboratory to get a reservoir fluid having a specific p b (i.e., equal to pwsi ). This procedure is advisable only when the real p b is known but representative samples cannot be taken. If p b > p ws : 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 p b 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 > p d 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 < p d . Liquid deposit is condensed in the reservoir and the separator GOR increases proportionally to the difference between pwf and p d . These considerations show that the sampling operation will require flowing conditions with almost no liquid condensation: GOR = GOR i or p wf greater than or very close to p d . 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 cond ensate 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 mo st unfavorable conditions (i.e., a gas condensate reservoir where pd = p wsi ). 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:

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

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 p d 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 r emoved with sufficient gas flow velocity.

Even when pd is equal to or very close to p are acceptable.

wsi and

when p wf is slightly lower than p d, the samples

In wells having a very low permeability, pwf may be considerably lower than p d. The samples taken are considered modified. In this case, rep resentative sampling is not possible. Producing Reservoirs or Wells in Depleted Zones

The only data to analyze is the gas/liquid ratio. If GOR = GOR i , 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 > GOR i , p wf is below p d but there is no way of establishing whether p ws 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 con tains large amounts of light hydrocarbons that vapor ize 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 p b 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 Well Reservoir and R ced Positi Flow ef. Fluids on Characteristics O I

New reserv oir or

1

GOR = GOR i = CONSTANT pwsi > p b undersaturated

SAMPLING POSSIBILITIES AND PROCEDURES Bottomhole Sampling Well flowing with pwf > p b

Surface Sampling Stabilized flow with pwf > p b

Remarks

L

undepl eted zones

reservoirs

2

3 Produc ing reserv oir or deplete d zones

G

New reserv oir or undepl eted zones

4

5

- Progressive reduction of flow - Well closed until GOR > GOR i stabilized pwsi > p b - Sampling with well saturated reservoirs producing at minimum possible flow rate GOR = GOR i = CONSTANT pws > p wf > p b GOR > GOR i pws > p b > p wf

GOR > GOR i pwf < p b

Produc ing reserv oir or deplete d zones

Volati le New oil or reserv doubt oir ful cases

Case of reservoirs with gas cap

- Stabilized flow with minimum drawdown.

Same procedure as in 1 Well conditioning could be very long and depends upon the depletion.

Same procedure as in 2

No sampling possibility

Representative sampling is not possible.

Surface samples can be recombined in the lab in order to have p b = p wsi .

Smallest possible flow but compatible with

6

GOR = constant = GOR i or GOR very close to GOR i

Not advisable





A S

- Flow rate reduction in order to get GOR very close to GOR i .

7

Dew point (pd) cannot be estimated but homogen measured only in the eous flow laboratory, using in tubing recombined surface separator samples. stability.

Same procedure as in 6

GOR = GOR i

Not advisable

8

GOR > GOR i

Validity of sampling Same procedure as will be known after p d in 6 measurement.

9

No possibility of getting any reservoir characteristics from well test data.

Sample representativity Same procedure as will be known after PVT in 6 analysis.

Not advisable

Summary This summary is an overview of the most important points p resented 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 recommendations prior to sampling are not designed to achieve which of the following options: Flowing the well on successively smaller choke sizes o Ensuring the well is clean o Having the reservoir pressure in the wellbore w ellbore 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 o 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 g as 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

This training page is divided into the following topics:       

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 labo ratory commonly called the pressure-volume-temperature (PVT) lab to make a representative sample. Water samples 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 o f 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 are also needed when several PVT analyses must be made for the same formation. This training page requires that you be familiar with sampling gene ralities 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.

Principles of Operation

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 enou gh 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. Th is flow rate can be determined by b y 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 p roductivity wells, or when the productivity is unknown, choosing a flow rate that gives regular flow o f 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 stabilized flowing bottomhole pressure (pwf ) is greater than the saturation ( bubblepoint) ubblepoint) pressure (p b), which ensures a single phase fluid at the formation level. The further the well deviates from 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 rat es stabilized wellhead pressure and temperature stabilized flowing bottomhole pressure (pwf ) obtained with a surface readout system.

Surface sampling of a gas condensate well w ell requires another condition: the liquid condensed in the tubing (between the bottom of o f the well and the surface) should completely b e 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 b e 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 ver y important. The PVT lab has to rely rel y on the reported GOR for the ph ysical recombination of oil and gas. Inaccurate flow rates applied to va lid surface samples lead to invalid recombined fluid. The following example emphasizes the importance of reporting accurate GOR: o

A volatile oil from Africa produced from a reservoir at 21 4 F was sampled at a separator o pressure of 168 psia and a temperature of 78 F. The reported field GOR was 1200 120 0 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 ex hibit the following differences as indicated in Table 1: Comparison of Oil Parameters Based on a 5% Difference in GOR Values

Fluid with GOR GOR = 1200 scf/bbl scf/bbl Fluid with GOR = 1260 scf/bbl scf/bbl Bubblepoint pressure (p b)

2936 psia

3017 psia

Reservoir oil density at p b

0.57 0. 574 4 g/ g/cm cm

0.56 0. 563 3 g/ g/cm cm

Gas Z factor at p b

0.831

0.829

Total GOR from separator test 1512 scf/bbl

1621 scf/bbl

Oil volume factor (Bo)

2.607

2.509 Table 1

Table 1 (above) shows that only onl y 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 an y 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 method s are presented in decreasing sample validity order, which means that the first method listed is more widel y used. At the end of each ea ch 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 cond ensation 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 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 dr ain 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. p ressure. 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. 1. Connect the top of the bottle to the separator gas sampling outlet line. 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 t hat 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. le aks. 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 and Purging Method

This technique consists of filling a bottle with the separator gas b y 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 n ot be representative. When several bottle volumes of gas h ave 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. 1. Connect the top of the bottle to the separator gas sampling outlet line. 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 st arting again at step 5. 13. If the gauge reads the separator pressure, close valve 5, t hen valve 1. Open valve 2. Open valve 4 to drain gas. 14. 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 7

During the purging procedure, the bottle b ottle 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 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. bo ttle. A transparent tube is used to connect the meter and the bottle. The following equations develop the calculations c alculations necessary to obtain the volume of gas to circulate using this sampling method. The volume of the gas needed is calculated calc ulated 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. 2. 3. 4.

Connect the bottle as shown. Start with all valves closed. Open valves 2 and 3. 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 b ottom 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 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 w ellsite 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 w ith 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 t he 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. 2. 3. 4.

Connect the bottle as shown. Start with all valves closed. Open valve 2 and valve 3. 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. t imes. 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. 10. 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 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. 2. 3. 4. 5. 6. 7.

8.

Connect the bottle as shown. Start with all valves closed. Open valve 2 and valve 3. 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. Open valve 1. The pressure gauge should read the separator pressure. Slowly open valve 5. Slowly open valve 6 to bleed off salt water. Maintain the sampling pressure pr essure between two and three times atmospheric pressure (30 to 4 0 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 t herefore part of the heavy components will be lost. Close valve 6 when gas appears.

9. Allow pressure to build up to t o 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 t he 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

Methods

Advantages

Drawbacks

Field of Application

Equipment

No limits - No heating Filling under D vacuum E

- Fast - High volumes sampled

- Vacuum pump

Vacuum pump

- Manifold + valves,

and gauge

vacuum gauge and

needed

pressure gauge

C R E

- Only stainless

A

steel bottles can

S

be used, and may

I

- Mercury

be of low

- Flasks

- No heating

volume

- Stainless steel

- No vacuum

- Reaction between

pump

mercury, H2S

- Maniford + valve and

and other sulfur

pressure gauge

compounds

- Safety equipment

N G

Mercury displacement

No limits

bottles

- Large volume of mercury needed S A Air M displacement P

- High volumes Risk of

L

sampled

condensation

No limits

- Flowmeter - Manifold + valve and

E (a) Purging

- No vacuum

pressure gauge

due to cooling

pump - High volumes (b) Circulation

sampled - No vacuum

V

pump

- Flowmeter

Risk of condensation

No limits

due to cooling

- Manifold + valve and pressure gauge - Heating system

A L

Water

I

displacement

D

- High volumes

I

sampled

(a) Separator T water Y

(b) Salt water

- No vacuum

- Manifold + valve and

- Long duration

No limits

sampled

- High volumes (c) Fresh water sampled - No vacuum pump

- Separator water - Flasks

pump

- High volumes

pressure gauge

- Long duration

Preferably with

- Possible change

no H2S or CO2

of composition

present

- Long duration

Preferably with

- Possible change

no H2S or CO2

of composition

present

- Manifold + valve and pressure gauge

- Manifold + valve and 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 o f the separator oil sight glass are closed prior to its attachment. The number of oil samples may vary v ary 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 b y 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 separa tor temperature to prevent gas liberation from the oil which could interfere with the bottle filling 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 widel y used as it permits the elimination of mercury usage in th e 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. 4 . Create a vacuum on the line between valve 3, the dead volume in the t he bottle and the vacuum pump. Close valve 4 and remove the t he 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, w hich 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 ar e no leaks at the valves. Install the safety plugs and label t he 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 b ottle. It describes the preparation of the bottle, the sampling of oil without H2S, the sampling of oil containing H2S and the quality qu ality assurance check to ensure the sample integrity. in tegrity. 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 eas y to control the quantity of oil in the bottle. Figure 12 describes how to fill up th e bottle with mercury. Water covers the mercury to prevent mercur y vapors from escaping. Figure 11 also shows the status of the equipment after step 1. 1. 2. 3. 4. 5.

The bottle is held vertically. Open valve 4, then valve 5. When the mercury overflows, close valve 5, then valve 4. Tilt the bottle to evacuate the mercury trapped at the top of valve 4. Disconnect the upper tube. 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 o submitted to a change of 30 C 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 t hat no appreciable pressure drop at the pressure gauge exists. 8. Let the oil slowly displace 550cc of o f 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 t he pressure gauge and the temperature of the bottle. 12. Close valve 5. Disconnect the bottle. Verify that there ar e 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 v olatile oils) must be sampled when mercury-free bottles are not available and w hen 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 S ampling 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 Method

This method is used when low viscosity fluids (condensates and v olatile oils) must be sampled when mercury-free bottles are not available and w hen mercury sampling is forbidden . High viscosity fluids will not flow properly by gravity. The bottle initially contain s 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, ex cept 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 w ellsite 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 t he 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

Methods

Advantages

Drawbacks

Field of

No limits Displacement using a piston or D membrane-type E bottle C

- Vacuum pump No mercury

and gauge needed - Dead volume

Equipment

Application

- Vacuum pump and gauge - PSR-F or membrane-type bottle - Flasks - Hydraulic oil and pump - Maniford + valves and

pressure gauge

R E A

- Mercury safety

S I

Mercury

N displacement G

Liquid sample

- Reaction

under

between

monophasic conditions

- Mercury - Flasks

No limits

mercury, H2S

- Stainless steel bottles - Manifold + valves and

and other sulfur

pressure gauge

compounds Slight modification Displacement and equilibrium S with separator A gas

of liquid No mercury

composition due to gas cap

- Stainless steel bottles

viscosity

- Manifold + valves and pressure gauge

be reported.

P

Risk of slight

L

displacement

Liquid of low

must

M

E Gas or air

- Flasks

- No mercury - Easy sampling

modification of

- Flasks

liquid composition

No limits

due to gas cap

- Stainless steel bottles - Manifold + valves and pressure gauge

formation technique

V A L I D

- No mercury

I

- Liquid sample Reaction between

T Y

Water displacement

under

CO2, H2S and

monophasic

water

conditions

Table 3

Not to be used

- Flasks

if

- Stainless steel bottles

CO2 or H2S

- Manifold + valves and

present

pressure gauge

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 lookin g 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 illustrated in the "Surface Oil Sampling with a Mercury-Free Bottle 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 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 o ne copy will accompany accompan y the bottle. A typical sampling data sheet is shown in Figure 18. 18.

Figure 18

Special Surface Sampling Cases Hydrogen Sulphide and Carbon Dioxide

H2S and CO2 concentrations in a sample can change chan ge 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 con tainers 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 coul d 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 eva cuated 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 p ressure 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. col lected. Sampling at the separator is much safer and gives more chances to obtain representative samples. The following paragraphs describe in which cond itions oil and gas samples can be obtained obtain ed at the wellhead. Oil Sampling

Oil sampling at the wellhead is only possible whe n the wellhead pressure is higher than the bubblepoint pressure at the wellhead temperature. This condition cond ition 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 eq uipment (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 the y 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 H 2S, 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 This summary is an overview of the most important points p resented in this training page. It is included to help you review the information. In this training page, we have presented the following:  



 

Well conditioning prior to surface sampling Gas surface sampling methods Vacuum method o Mercury displacement method o Air displacement and purging method o Air displacement and circulating method o Water displacement method o Oil surface sampling methods 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 o Special surface sampling methods Safety points about surface sampling

Self Test 1. 2. 3. 4. 5. 6. 7. 8. 9. 10.

What is the purpose of the cleanup period? Why should a well be produced at a constant GOR prior sampling? How do you determine the proper flow rate for sampling? What parameters do you monitor to ensure a stable flow? Why should oil and gas samples be taken at the same time? Why does the sampling procedure with a piston bottle recommend pressurizing the bottle at a pressure higher than the separator pressure? Why is it very important to create a gas cap in oil bottles? Describe the oil sampling method using a piston bottle. Examine the gas sampling method using salt or fresh water and discuss its liabilities. How can we minimize them? When sampling oil in a bottle at a temperature higher than that of the separator, which natural process occurs? Condensation or vaporization?

WATER SAMPLING This training page is divided into the following topics:  

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 downho le. 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 w ater 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.

Principles of Operation 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 th e surface. Figure 1a illustrates one method used to obtain an air-free water sample. A plastic or rubber tub e can be used to transfer the sample from a sample valve into the container. The tube and the bottle bo ttle should be flushed to remove an y 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 co ntainers. 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 p H 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 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 h ydrocarbons. However, other gases such as CO2, N2 and H 2S 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 b efore it is evacuated and filled again with water destined for analysis. This technique will limit the loss of some elements by allowing the walls o f the bottle to become saturated with the adsorbed chemicals. 

Downhole with a bottomhole sampler This method uses a sampling tool run r un 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.

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Downhole with a DST sampling tool A sampling tool is part of the DST string and is activated by increasing the annulus annulus pressure. This tool, a fullbore annular sampling chamber (FASC), will trap a sample and when w hen 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. su rface. 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 cont ribute 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: 

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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 t hat 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 H 2S, 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.

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If sampling with mercury, strictly follow the t he safety rules and procedures for mercury use.

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Whenever H2S is expected or suspected, srictly follow all H2S safety rules.

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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 of sampling bottle Safety considerations for sampling water

Self Test 1. 2. 3. 4.

Why do we need to sample water from an oil reservoir? Name three methods of obtaining formation water samples. Describe one method to recover a water sample at the surface which is free of air. 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 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 t he surface? 7. Is it possible to get samples of formation water during openhole operations? How?

BOTTOMHOLE SAMPLING This training page is divided into the following topics:       

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 p roductive 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.

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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 bein g 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 heav ily 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 Upon completion of this training page and the associated practical exercises, you should be able to complete the following tasks:    

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Compare the advantages and disadvantages of bottomhole sampling versus surface sampling. Discuss how to prepare the well w ell prior to bottomhole sampling. Explain why a minimum of two tw o bottomhole samples should be taken. Write a complete sampling procedure pr ocedure 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.

Principles of Operation This topic outlines the preparation of the well before p roceeding 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 b y 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 wh en the bottomhole flowing pressure is well above p b (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 v erified with the following points:   

Stabilized surface gas and oil flow rates r ates and GOR Stabilized wellhead pressure Stabilized flowing bottomhole pressure (pwf )

Well Shut-in

Bottomhole sampling performed with the well shut-in is onl y done when the smallest possible rate causes the downhole pressure to drop below b elow 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 be en 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 e asily 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 well should be considered. Sampling Procedures

This section is presented as a list of the ke y steps to follow in order to obtain a representative bottomhole sample: 

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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 t hat the well is properly conditioned. 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 o f 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 start s to take the sample and pulled out about fifteen minutes after the t he 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 fo llowing checks should be made to ensure en sure 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 l oss 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 t he 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 t he samples are representative.

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Determine the bubblepoint pressure of the sample at ambient temperature. The field bubblepoint pressure of the sample can be measured either w hile 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, o nly one recombination is necessary. In the field, it is probably more convenient to transfer the t he 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 bu bblepoint 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 m easured at bottomhole temperature but for practical reasons, it is rarely done. The on-site bubblepoint measurement is performed the same wa y 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 a mount 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 chan ge 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 remed y 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 s ample in which diphasic fluid was recompressed to 4000 psi and decompressed d ecompressed with agitation at every step. A sharp chan ge in compressibility is obtained which facilitates the field bubblepoint reading.

Figure 2

Figure 3 shows the pressure-volume plot of the sa me 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 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 ( p b < p wf ). If p b = p wf , the reservoir fluid was saturated and if p b > p wf , 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 don e because it requires the use of a visual cell. The quality control is then limited to the conformity of the opening pressure p ressure values and their comparison to pwf . All the verifications made on a sample as described d escribed 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 Th e

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. 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 p ressure 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 Th is is achieved by repressurizing the sample 1000 psi p si above the expected bubblepoint pressure or static bottomhole pressure (when p b cannot be estimated). This pressure will be maintained during the transfer. Recombining gas and oil by b y 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 t he pressure rating of the bottle. Before transferring a gas condensate, the sampler chamber should be heated with a heating jacket o to a temperature 2 to 4 C 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 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 bubblepo int determination made with the sample in the bottle: 

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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 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" 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 lab el 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 sho ws 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 o ne copy will accompany accompan y 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.

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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 H 2S, 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 t he 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 t he Schlumberger Wireline and Testing Pressure Operations Guidelines.

Summary This summary is an overview of the most important points p resented in this training page. It is included to help you review the information. In this training page, we have presented the following:   

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Preparation of the well prior to sampling Important steps to follow in order o rder to sample successfully How to ensure the quality and validity of the samples taken: Reading the opening pressure o Determination of the bubblepoint pressure at ambient temperature o 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. 4. 5. 6. 7. 8.

When do you sample downhole with the well shut-in? What measurements should be made when sampling? Why do we need to recompress the sample before the transfer? What is the purpose of the compressibility curve? How can we obtain a better sharp contrast on the compressibility curve? 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

This training page is divided into the following topics:         


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 bo ttle 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 g as sample bottle and its usual code name is SBG-C.

Objectives Upon completion of this training page and the associated practical exercises, you should be able to complete the following tasks:

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Explain the relationship between the general gas law "PV / ZT= constant" and the t he 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 o f 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.

Principles of Operation The usage of the gas bottle bott le is described in the Surface Sampling training pa ge under gas surface sampling methods. 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 th e 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 cap acity 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. Figure 1

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. Gas Bottle Characterizati Characterization on

A gas sampling bottle is not only onl y 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 ma y 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 max imum working pressure for which the bottle was certified. Schlumberger's policy is to base its gas sampling procedures on a maximum allowable bottle o o temperature of 100 C [212 F]. 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 primaril y 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


EE (H2S, Co2)

Working pressure

2150 psi [150 bar]

Test pressure

4250 psi [300 bar]

Working temperature

14 to 212 F [-10 to 100 C]

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]

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Safety Gas bottles are "mobile pressure vessels" designed to contain h ydrocarbon 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 safet y considerations for gas bottles: 

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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 t he 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.

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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.

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Figure 4

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Any repair made on the gas bottle should be followed by a routine test with water at 110% o f 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

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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 d etailed 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.     

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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. pr essure. 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 In this training page, we have presented the following:  

The reasons why we use gas sampling bottles. The components of the gas sampling bottle.

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The technical specification specificationss 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. 2. 3. 4. 5. 6. 7.

Why is a gas sampling bottle characterized by a maximum sampling pressure? What is the Schlumberger policy regarding gas sampling procedures? What are the technical specifications of the SBG-C? What is the purpose of sealing the gas sampling bottle? How is it sealed? Is it possible to sample sour gas with the SBG-C? 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 b ottle described in this training page is built to transport hydrocarbon liquids safely and exists in two versions which differ only b y 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 o f obtaining representative oil samples without the constraints of mercury.

Objectives Upon completion of this training page and the associated practical exercises, you should be able to complete the following tasks:     

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.

Principles of Operation 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 b y most companies and governments preoccupied with the environment. The floating piston system s ystem was then found as an alternative. It was also necessary to improve the sampling procedu res 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 system and permitting the agitation of the sample. The last consideration was to guarantee the o riginal 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 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 bot tle. 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 p ressure 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 bubbl epoint 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 vo lume of the bottle. Each nut is threaded with 4 threads per inch (TPI) allowing for quick dismantling of the bottle for inspection and cleani ng purposes. Six screws evenly distributed on the nuts compress the metal seal and hold (lock) the nuts nu ts 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 pe riods. 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, mod els, 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 o utlet 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

Assembly number M-873200

M-871211

Project code

PSR-F

PSRA-F


EE (H2S, Co2) o

15,000 psi [1035 bar]

o

Working pressure 2860 psi, -10 C/+70 C o

o

Working temperature

14 to 302 F [-10 to 150 C] o o 14 to 158 F [-10 to 70 C]

Capacity

730 cm

Needle valves

Autoclave with 2 x 1/8-in. W125 outlets per valve

Body connections 1/4-in. Autoclave F250C Diameter Length

4.65 in. [118 mm]

Without valves

17.1 in. [436 mm]

With protectors

25.7 in. [654 mm]

Weight (empty, in transport 52 lbm [23.6 kg] box) 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 h ydrocarbon 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: 

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Every new oil bottle is pressure tested by a certifying authority. In France, t he 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 t he 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 

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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 d isassembly 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 In this training page, we have presented the following:     

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 specification specificationss of the PSR-F and PSRA-F. Some important safety considerations for the oil sampling bottle.

Self Test 1. 2. 3. 4. 5.

Why is it important to reduce the dead volumes in the bottle? What is the function of the ball valve in the piston? Why is the bottle equipped with metallic seals? How is the differential pressure minimized across the floating piston? Why is the friction reduced to a minimum between the floating piston and the body?

Well Test Complete

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