Field Operations 1.10

Field Operations Module 1.10

CAPPA Level 1 CAPPA

LAST REVISED April 19, 2012

Field Operations Module Summary This module is designed to give the student the required knowledge to identify the types of equipment necessary to take raw oil well production, condition it, measure it and deliver it to market. They will be able to calculate oil and water cuts given basic information. Surface facilities covered include oil well leases, oil batteries and gas handling facilities. The student will gain the required knowledge required to list and become familiar with the operation of the most common types of meters used in the patch.

Topic 1: Field Operations - Overview Objective 1: Purpose of Field Operations The student will be introduced to field operations. Objective 2: Reasons for Production Measurement The student will learn about the primary users of production data. Objective 3: What Must be Accounted For? The student will learn what production data is required at the well and battery levels. Objective 4: Where the Information Comes From The student will be introduced to the documents used to capture field production information.

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Topic 2: Single Well Oil Battery Objective 5: Production Equipment at a Single Well Oil Battery The student will learn about the equipment found at a single well oil battery for the production, disposition and measurement of oil, gas and water. Objective 6: Calculation of Net Oil and Water Volumes The student will learn how to calculate the amount of net oil and water volumes given a total fluid volume and the water cut.

Topic 3: Multi-Well Oil Battery Objective 7: Oil Flow Lines and Gathering Systems The student will be introduced to radial and satellite oil gathering systems. Objective 8: Production Equipment at a Multi-Well Battery The student will learn about the equipment located at a multi-well battery. Objective 9: Inlet Header The student will learn about the inlet header.

Objective 10: Main Battery The student will be introduced to the purpose and function of the main battery. Objective 11: Separation Equipment The student will learn about the group and test separators.

Topic 4: Treating Oilfield Emulsions Objective 12: Emulsion Definition The student will be introduced to emulsions. Objective 13: What Causes Oil / Water Emulsions to Form The student will learn the conditions under which emulsions form.

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Objective 14: Treating Oil / Water Emulsions The student will be introduced to the five processes used in a heater treater to break emulsions.

Topic 5: Disposition of Products Objective 15: Gas Disposition The student will learn about a Vapour Recovery Unit in an oil battery.

Objective 16: Produced Water Treatment The student will learn about the methods for treating produced water before it can be injected into the ground.

Objective 17: Water Disposition The student will learn the difference between water injection and water disposal wells.

Objective 18: Oil Disposition The student will learn about the two most common ways to move oil from an oil battery onto an oil transmission pipeline. The student will be introduced to a LACT unit.

Objective 19: Battery Summary The student will be introduced to the battery flow schematic.

Topic 6: Field Operations - Measurement Objective 20: Meter Classification The student will be introduced to the various classifications of meters.

Objective 21: Inferential Gas Meters The student will be introduced to a gas orifice meter.

Objective 22: Direct Measurement Gas Meters The student will learn about a gas positive displacement meter. 3 Copyright 2013,14 Canadian Association of Petroleum Production Accounting

Objective 23: Direct Measurement Liquid Meters The student will learn about a liquid positive displacement meter.

Objective 24: Inferential Liquid Meters The student will learn about an inferential liquid meter. Objective 25: Meter Proving The student will learn about the meter proving process and how a meter factor is determined.

Topic 7: Calculation of Net Fluid Volumes Objective 26: Calculation of Net Oil and Water Volumes The student will be shown how to calculate the net oil and water volume given opening and closing meter volumes, water cut and meter factor.

Objective 27: Proration The student will be introduced to prorating production at a multi-well oil proration battery.

Topic 8: Storage Objective 28: Oil and Water Battery Tanks The student will learn about battery oil and water tankage requirements and how tank liquid heights are converted to volumes.

Topic 9: Manually Calculating Storage Tank Volume Objective 29: Oil and Water Battery Tank Measurement The student will learn how tank liquid heights are converted to volumes

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Topic 10: Field Facilities - Gas Objective 30: Gas Hydrates The student will learn about gas hydrates are and the methods used to control their formation. Objective 31: Carbon Dioxide and Hydrogen Sulphide The student will learn about two important impurities: carbon dioxide and hydrogen sulphide. Objective 32: Gas Wellhead and Lease Equipment The student will learn about the equipment found on a gas well lease. Objective 33: Gas Gathering System The student will learn about a gas gathering system. Objective 34: Gas Processing Plant The student will learn about a gas processing plant. Objective 35: Gas Plant Functional Units The student will learn about common processing units found in a gas plant.

LIST OF APPENDICES

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Topic 1: Field Operations - Overview Objective 1:

The student will be introduced to field operations.

PURPOSE OF FIELD OPERATIONS Oil wells produce a commingled mixture of oil, gas, and water. Gas wells produce a mixture of desirable gases (methane, ethane, etc.), heavier hydrocarbons (natural gas liquids), undesirable gases (carbon dioxide, nitrogen, hydrogen sulphide, etc.), and water. The term “effluent” or “well effluent” is used to describe raw production from oil and gas wells. All gas and oil sales contracts have specifications regarding the purity and quality of the product. Very few wells produce well effluent that meets contract specifications without some processing. The primary purpose of field operations is to separate well effluent into constituent components at a purity that meets contract specifications in an economic manner. Specification (“spec”) oil, gas and gas liquids are sold into their respective markets. Produced water is disposed of in an environmentally safe manner. Upgrading of oil well effluent to contract specifications is done in a centralized treating facility called an “oil battery”. Upgrading of gas well effluent to contract specifications is done in a centralized treating facility called a “gas plant”. This Module introduces the student to the design and operation of oil batteries, gas wellhead equipment and gas plants. Figure 1 shows a generalized oil and gas field that shows typical product flows for oil gas and water production. It serves as a framework for this Module.

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Figure 1

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Objective 2:

The student will learn about the primary users of production data.

REASONS FOR PRODUCTION MEASUREMENT

Who Requires the Data? There are several groups that require production measurement data:  Petrinex Petrinex is responsible for maintaining historical production records for each well and pool in Alberta and Saskatchewan.  The Alberta Energy Regulator The Alberta Energy Regulator (AER) requires accurate production volumes from all well and facility operators so that it can: o Prevent hydrocarbon waste by ensuring that wells are produced at the most efficient rate and that well effluent is processed efficiently. o Prevent pollution of the atmosphere, soil and ground water. Over the long term, soil and fresh water may be more valuable resources than oil or gas. o Protect the equity of the Crown and private interests (freehold owners). o Advise the Provincial Government as to the Province’s remaining oil and gas reserves. This allows for the consideration of export agreements that can be made without fear of leaving a short supply of energy for the domestic market. o Provide the Provincial Government with an annual oil and gas production forecast for provincial royalty revenue budgeting purposes.  Alberta Energy Alberta Energy needs accurate production data so they can be sure that Crown royalties are being calculated and paid accurately.  Production Companies Company management needs good statistical data on its operations: o Engineering departments must have an accurate knowledge of how much gas, oil and water is being produced in order to design efficient and economical facilities. o Operations departments must have accurate data in order to determine whether or not their operation is running efficiently and profitably. 8 Copyright  2013, 14 Canadian Association of Petroleum Production Accounting

o Financial planners must have good data in order to be able to plan for future operations.  Others Working Interest Partners, Override Royalty Owners and Freehold Royalty Owners need accurate production and sales data so that they can confirm they are getting their fair share of revenue.

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The student will learn what production data is required at the well and battery levels. Objective 3:

WHAT MUST BE ACCOUNTED FOR? Production Oil, gas and water volumes as well as total hours on production must be reported monthly for each producing zone in each oil well. Gas, condensate (gas liquids) and water volumes as well as total hours on production must be reported monthly for each producing zone in each gas well. Disposition and Inventory Each month at an oil battery level:  The volume of oil, gas and water received into the oil battery.  The volume and method of oil and condensate disposed.  The volume and method of water disposed.  The volume of gas sold (delivered to a gas plant), used for fuel, flared or vented.  The closing inventory of all liquids in tanks. For a gas plant: Each month at a battery and well level:  The amount of raw (unprocessed) gas received at the gas plant.  Disposition of gas. There is no gas inventory but there may be inventory of hydrocarbon liquids and sulphur. The following must be reported:  The volume of acid gas removed from the raw gas stream together with its disposition.  The volume of hydrocarbon liquids removed from the raw gas stream together with its disposition.  The amount of elemental sulphur recovered from the raw gas stream together with its disposition.  The volume of fuel gas consumed in the gas plant.  The volume of gas flared from the gas plant.  The volume of gas vented from the gas plant.  The volume of residue gas sales from the gas plant.  The volume of water removed from the raw gas stream together with its disposition. Monthly produced wellhead volumes of oil, gas, gas liquids and water are used to determine the royalties that must be paid to the lessor. Monthly sales volumes determine the revenue stream. The above data is reported to Petrinex for both Alberta and Saskatchewan. There are different reporting requirements in other jurisdictions. 10 Copyright  2013, 14 Canadian Association of Petroleum Production Accounting

The student will be introduced to the documents used to capture field production information. Objective 4:

WHERE THE INFORMATION COMES FROM The raw information needed by the PA to account for volumes of oil, gas and other fluids that are produced into a facility (oil battery or gas plant) or disposed of from that facility comes from:    

FDC systems SCADA systems Manual/reports Engineering estimates

Field Data Capture (FDC) Systems Field data capture systems perform daily field volumetric balances. FDC systems capture and store data required for battery liquids balancing of oil, water and condensate as well as operating data such as operating temperatures and pressures. Data contained in the field data capture system, of concern to production accountants, includes truck ticket receipts and dispositions, pipeline sales estimates, tank inventories, production balances, well production tests, gas estimates, hours on production and operating conditions. Data is captured and balanced daily at a battery level. PAs use information provided by FDC systems as a basis for their reporting. FDC systems are prevalent throughout the industry. Telecommunication features allow the data to be relayed daily or even instantaneously to the company head office. Supervisory Control and Data Acquisition (SCADA) Systems SCADA systems use computers that are programmed to deal with real time data capture and the monitoring of facilities. SCADA is essentially a sophisticated version of FDC. A SCADA system uses electronic measurement to monitor operating conditions such as pressure, temperature and flow rates to optimize process recovery and can shut the facility and wells down automatically if a dangerous situation arises. SCADA systems have become prevalent throughout the industry. The facility operation can be monitored in real time at both the field office / control room, at the company’s head office or on any wireless device.

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Other Reports Gauge or Battery Reports – Gauge or battery reports are prepared by the battery operator’s field staff each month. These systems are used in (mostly older) facilities where FDC or SCADA systems have not yet been installed. These reports contain information such as:     

test production data. number of hours that each well produced. opening and closing inventories for all water or oil tanks. opening and closing meter readings. a listing of all shipments received or disposed.

Gas Charts – Many older gas wells use paper charts. These charts provide a permanent record of the volume of gas that passed through the meter adjacent to the chart. The charts are read by trained people to provide gas volumes. Gas and Liquid Analyses – Physical samples of produced gas and liquids are obtained periodically to determine the composition of the fluids being produced and processed. These samples are analysed in a laboratory to determine fluid composition. Purchase Confirmation Statements -advise the producer how much of their monthly oil and gas was delivered from a particular facility. The volume purchased and the price paid by the purchaser is shown on the monthly statement. Engineering Estimates- When data is not directly measured, engineering estimates have to be used to determine:    

amount of lease fuel used amount of flared gas amount of water produced by a gas well the gas equivalent of condensate

These reports will be studied in much greater detail in Module 2.1. It is important for the production accounting staff to maintain good lines of communication with the field staff and the production operations department. If the situation in the field changes, accounting procedures may require modifications to ensure accurate reporting of volumes.

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Topic 2: Single Well Oil Battery The student will learn about the equipment found at a single well oil battery for the production, disposition and measurement of oil, gas and water. Objective 5:

PRODUCTION EQUIPMENT AT A SINGLE WELL OIL BATTERY A single well oil battery consists of an oil well with a dedicated test separator and one or more production tanks which hold the produced liquid until it can be trucked to another location for processing. The well site equipment separates the wellhead effluent into liquid and gas streams. Small volumes of gas are difficult to measure. For those wells producing small gas volumes along with the oil, an annual test is run with special equipment to accurately measure the amount of gas co-produced with the oil. This is recorded as a “gas-oil-ratio” or (“GOR”). The GOR will used to estimate gas production volumes until the next test. If the gas volumes are large enough to measure, a meter will be installed and measured production volumes will be reported. Often the produced gas is consumed as lease fuel. Volumes in excess of the amount needed for lease fuel are flared. If the gas volume is too low to support continued combustion (either consumed as fuel or flared), it is vented. The Alberta Energy Regulator (AER) is trying hard to eliminate flaring and venting. The produced liquid (an emulsion of oil and water) is temporarily stored in one or more tanks on the lease. Periodically, the liquid is trucked to other facilities to separate the emulsion into specification quality oil (less than or equal to 0.5% basic sediment and water (BS&W)). Single well batteries have the following features:      

Very simple Minimum capital and operating cost Pollution due to flaring or venting of the solution gas Required to determine the initial well productivity and basic reserves Will determine need for future well drilling Will influence design of the production facilities

A sample single well battery equipment schematic for a flowing oil well is shown in Figure 2. 13 Copyright 2013,14 Canadian Association of Petroleum Production Accounting

Figure 2

Separation, Metering and Storage Equipment Equipment located at the well site includes:  a separator to split the inlet well effluent into gas and an oil/water emulsion  meters to record the production volumes  one or more tanks for storing the liquids  a flare for disposing the gas. The meters that we use in the oil and gas industry operate unattended year round regardless of the weather. Hence only the simplest and most rugged meters are used. It is for this reason that we say there is no meter that will accurately measure two-phase flow (i.e. commingled gas and liquid flow). In order to obtain accurate measurement of liquid and gas volumes, the stream is first separated into a distinct gas and a distinct liquid stream before measurement. A two-phase separator is used. Well effluent (a mixture of oil, gas and water) flows into the vessel. Gravity causes the liquids to fall to the bottom and the gas to rise to the top of the vessel (refer to Figure 3 - Two-Phase Separator). Measurement techniques and devices will be discussed in a future module.

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Figure 3

The emulsion leaves the vessel when a preset liquid level is reached. When the liquid level is reached, the float trips a dump valve. The liquid then passes to a storage tank to await shipment to an appropriate facility for further processing. If the oil coming out of the tank is clean enough (i.e. meets oil sales specifications) it will be trucked directly to a pipeline terminal for delivery to a refinery. A back pressure valve on the gas flow line permits the gas to exit the vessel at a preset pressure. Upon leaving the separator, the gas passes through a gas metering device, such as an orifice meter, to record the gas volume. Recent deregulation of the electricity generation Industry has led to mini-gas turbine electric generators being installed at many locations where continuous flaring previously took place. These units make use of the gas to generate small amounts of electricity for on-site use or for sale into the electrical grid. This is a positive use for the gas.

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The student will learn how to calculate the amount of net oil and water volumes given a total fluid volume and the water cut. Objective 6:

CALCULATION OF NET OIL AND WATER VOLUMES The fluid in the production tank is a mixture of oil and water in the form of an emulsion. Emulsions will be defined and addressed in more detail later in this module. The total volumes of emulsion produced to the tank or removed from the tank can be determined by gauging the tank or by a meter on the liquid flow line. However, total fluid volume is not adequate. The provincial regulators require oil and water production volumes to be reported separately. We can determine separate oil and water volumes from a small, representative sample of fluid from the tank. The percentage of water in the emulsion is determined and reported as the “water cut”. The emulsion volume is multiplied by the water cut to determine the water volume. The oil volume is determined by subtracting the water volume from the emulsion volume The water and other impurities that are separated from the oil are known as Basic Sediment and Water or BS&W. The BS&W content is usually expressed to the nearest tenth of one percent and represents the percentage of BS&W in the total sample (e.g. 0.7% BS&W). The water cut test begins with the operator obtaining a sample (approximately one liter) with a device called a “thief” from the midpoint of the tank. The thieved sample is placed in a glass test vial in a centrifuge and spun for several minutes. The centrifuge drives the water and any sediment to the bottom of the test tube because water and sediments are heavier than oil. The centrifuge tube is graduated so that the water cut can be read directly in percent. A water cut test is sometimes also referred to as a BS&W test, a grind out, a shake out or a centrifuge test. Please see Figure 4 - Centrifuge Tube. For improved accuracy, the operator can obtain multiple samples from different heights in the tank. At a single well oil battery, all liquids must be transferred out by truck for further separation and processing before they can be sold (oil) or disposed of into a suitable reservoir quality zone (water).

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Figure 4

Water Cut Calculation Example: Given: A truck has loaded 60.6 m3 of emulsion from the production tank. The emulsion has a water cut with 1.7% BS&W. Calculate the net oil and water volumes that were loaded onto the truck. Step 1 Calculate Water Volume = product of total emulsion volume and the water cut. Water volume = 60.6 m3 x 1.7/100 = 1.0 m3 (round to 1 decimal) Step 2 — Calculate Oil Volume by Difference Oil volume = 60.6 m3 - 1.0 m3 = 59.6 m3

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Topic 3: Multi-Well Oil Battery In this topic, the student will learn about the function and purpose of the equipment used at a multi-well oil battery. They will also learn how wellhead effluent is processed into marketable crude oil, clean water for injection / disposal and gas for delivery to a gas gathering system. Objective 7:

The student will be introduced to the radial and satellite oil gathering

systems.

OIL FLOW LINES AND GATHERING SYSTEMS When several wells are completed in the same geographic area, they are tied-in through a gathering system to central battery for treating. Liquids either flow or are pumped into the gathering system at low pressures of 700 kPa (100 psi) or less. Oil gathering systems fall into two classes: radial and satellite systems. In the radial system there is one flowline for each well that runs from the wellhead to the central battery where it ties in to the inlet header (Figure 5). The header will be discussed in another Objective. Because each well must be tested approximately once per month, and to limit the complexity of many flow lines entering the facility, we normally will limit the number of wells connected to a header to approximately 15. If our field has more than 15 wells, we will use a satellite battery gathering system.

Figure 5

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In a satellite gathering system, a number of wells remote from the main battery flow into a local well test facility called a “satellite battery”. Each satellite battery has its own radial gathering system as shown in figure 6. Satellite batteries are sometimes called “fieldgate” batteries. Well tests are performed for those wells that are connected to the satellite battery. The tests do not have to be redone at the main battery. Each satellite battery consists of a header and a test separator. One well is tested (flows through the test separator) at a time. After the oil, gas and water volumes have been determined for the well on test, the fluids are re-combined and merged with the fluids from the wells not presently being tested. The recombined satellite effluent flows through a single larger diameter flow line to the central battery for further treating.

Figure 6

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The student will learn about the equipment located at a multi-well oil proration battery. Objective 8:

PRODUCTION EQUIPMENT AT A MULTI-WELL OIL BATTERY Introduction Flow lines from individual wells terminate at an inlet header. This is located at the satellite battery or the central battery and is used to route the production of one well to the test separator while the rest go to the group separator. Effluent from the satellite battery goes to a header at the central battery where it is usually routed to the group separator. Oil, gas and water are separated to sales specifications and forwarded for disposition. Clean oil is stored in a tank (the “stock tank”) while it awaits delivery onto the transmission pipeline that will deliver the clean oil to a refinery. The clean water may be injected back into the reservoir if the field is under waterflood. Otherwise, the clean water will be disposed of into an underground aquifer. The gas will be sent to a gas plant for further processing. A multi-well oil battery may serve from two to several hundred wells. The multiwell prorated battery will contain the following equipment:       

inlet header test separation equipment (test train) group treating equipment (group train) gas, oil and water measurement devices oil & water storage tanks oil, gas, and water disposition systems vapour recovery system.

A diagram showing a sample multi-well battery with oil, water and gas handling facilities is shown on Figure 7. We will discuss each of these items in the following objectives. A larger version is attached in Appendix 1.

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Figure 7

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Objective 9:

The student will learn about the inlet header.

INLET HEADER

The inlet header is a system of pipes and valves that allows the operator to independently flow any directly connected well through either the test train or the group train. For a radial gathering system, where there are usually less than 20 wells connected to a central facility, each well has its own flow line that terminates at the inlet header at the central battery. For a satellite gathering system, each well has its own flow line that terminates at an inlet header at the satellite that it produces to. Each satellite has its own test separator and may have a group separator. The effluent from the test separator (gas and liquid) is measured and then recombined (commingled) with the effluent from the other wells that flow to the satellite. The total commingled fluid is then routed through a larger flow line (trunk line) to the group inlet header at the central battery. The central battery may also have a few wells directly connected. These will flow to the inlet header where they can be routed to either the test or the group train.

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Objective 10:

The student will be introduced to the purpose and function of the

main battery.

MAIN BATTERY A multi-well proration battery has two sets of separation and processing equipment referred to as the “test train” and the “group train”. A “train” is a series of vessels that perform a specific function. Each train at the battery allows us to separate and measure the oil, gas and water for the well(s) flowing through that train. The inlet header system is a combination of pipes and valves that allows the operator to independently flow any well through either the test train or the group train. The test train is sized to handle the flow from any one well at a time whereas the group train is sized to handle production from the remaining wells, all at the same time. While one well is on test (flowing through the test train all by itself), all the other wells will flow through the group train. After the well test is complete, the well that was being tested is switched back to the group train and another well is put on test. This procedure allows us to obtain flow rate information on each well without the expense of dedicated separation and metering facilities for each well. Each month every well undergoes the cycle of production through the group train, then switching through the test separator and back to the group system after completion of its test. The duration and frequency of well testing is specified by the AER when it grants approval for battery operation. The minimum number of tests required per well varies from one test every three months for low productivity (“stripper”) wells to three tests per month for high rate wells.

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Objective 11:

The student will learn about the group and test separators.

SEPARATION EQUIPMENT Test Separation Equipment (Test Train) The test separator may be either a two-phase or three-phase separator. A twophase separator separates the inlet volumes into liquid and gas volumes and was discussed earlier. A two phase separator can be used when there is no free water co-produced with the oil and gas. A three-phase separator is used when free water is co-produced with oil and gas. A three-phase separator separates the inlet volumes into oil emulsion, gas and water. The three-phase separator is identical to the two-phase separator except for the addition of a second dump valve and outlet. A cut away diagram of a three-phase separator is shown on Figure 8.

Figure 8

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In a three phase separator, incoming liquid strikes a splash plate and falls into the liquid section. A float periodically opens the oil dump valve, while a weighted interface float detects the top of the water layer and operates the water dump valve. Some oil/water emulsions break down (separate into oil and water) without difficulty. Other emulsions are more difficult to break and may require the addition of chemicals and / or heat to speed up the separation process. Threephase separators are usually larger in diameter than two-phase separators to allow ample retention time for gravity separation of the oil and water. The three phase separator is often referred to as a free water knockout (FWKO). Group Separation Equipment (Group Train) A group separator’s function is to take the production from all the wells that are not on test and separate the gas from the oil or oil emulsion. If there is a lot of free water present, a three-phase separator will be used to separate inlet volumes into separate streams of gas, oil emulsion and free water. The gas is measured and sent to the gas gathering system (GGS). Free water (if present) is sent to the water treatment area. Emulsion is sent to the heater treater to remove most of the remaining water and clean the oil to sales specifications.

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Topic 4: Treating Oilfield Emulsions Objective 12:

The student will be introduced to emulsions.

EMULSION - DEFINITION By definition, an emulsion is a mixture of two immiscible fluids in which one liquid, which is called the dispersed (or internal) phase, is uniformly distributed as tiny droplets within the second liquid, which is called the continuous (or external) phase. The size of the dispersed droplets varies widely, ranging from one micron to several millimeters in size. In a water-oil emulsion, the water is in the internal phase and the oil is in the external phase. In an oil-water emulsion, the reverse is true. Most oil field emulsions are initially the water-oil type. If an enhanced recovery project is implemented using water as all or a portion of the injected fluid, then over time, a greater proportion of water will be produced with the oil and hence the emulsion that is produced will gradually change to an oil-water emulsion.

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Objective 13:

The student will learn the circumstances under which emulsions

form.

WHAT CAUSES OIL / WATER EMULSIONS TO FORM Emulsions must be treated to clean the oil to market specifications. The conditions which cause emulsions to form are: 1. Two immiscible fluids - Immiscible fluids are fluids that do not mix at a molecular level even though they may look like a single liquid to the eye. The key is that given sufficient time, the two fluids will separate back into two distinct liquid phases. 2. Agitation - Using oil and vinegar salad dressing as an analogy, if you want to mix the two before you pour it on your salad, you shake the ingredients up – you are making an emulsion. In the field, this agitation or mixing comes from the gas liberated from solution as the pressure drops from reservoir to surface conditions and from the mixing that takes place in the reservoir and as the fluid enters the well bore. 3. An emulsifying agent - An emulsifying agent is a chemical that surrounds each of the tiny dispersed droplets in the internal phase much like a plastic coating. The emulsifying agent coating creates a barrier that prevents the internal phase droplets from merging and becoming large enough to move through the external phase. As a result, the droplets stay suspended in the emulsion. In an oil water emulsion, the emulsifying agent can be any number of things: formation salts, silt, clay, carbon or organic acids. The important thing to note is that the emulsifying agent is present along with the oil and water in the formation. A stable emulsion is an emulsion that will not break down into its components without some form of treating. Emulsions are broadly classified either as tight, meaning difficult to break, or loose, meaning easy to break. Whether an emulsion is tight or loose depends on several factors, including the properties of the oil and water, the percentage of each in the emulsion, and the type and amount of emulsifying agent present.

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The student will be introduced to the five processes used in a heater treater to break emulsions. Objective 14:

TREATING OIL / WATER EMULSIONS Treating Equipment The heater treater (Figure 9) is the most common method of breaking emulsions into separate streams of marketable crude oil (minimum 99.5% clean oil, maximum 0.5% basic sediment and water (BS&W)) and free water for disposal. The water often contains trace amounts of oil or other contaminants and will have to be further purified before it can be sent to a disposal facility. A heater treater is very similar to a three-phase separator except that a heater treater adds heat to speed up the breaking of the emulsion. If there is sufficient gas produced with the oil, the gas will be burned to create heat. If there is not sufficient gas, a portable fuel such as propane will be brought to site for use as fuel.

Figure 9

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Five factors work together within the heater treater to break down the emulsion. These various factors work together to accomplish three things. First, they assist in the destruction of the emulsion through rupture or weakening of the emulsifying agent film surrounding each droplet. Secondly, they assist with the joining together of the droplets to form larger drops and lastly they promote the settling out of larger water drops. Major Factors 1) Heat Heating of the emulsion happens in the lower third of the heater treater. The emulsion rises through the hot water layer and picks up heat from the water. The water is maintained at the correct temperature by a thermostatic controlled burner. Heat is beneficial in several ways. a) It increases the energy or speed of the molecules. As each of the droplets is heated, it moves more quickly through the emulsion. b) Heat thins the emulsion (reduces its viscosity) which allows the droplets to move more quickly. c) Heat improves chemical efficiency. d) Heat increases the density contrast between oil and water 2) Chemicals Chemicals attack and neutralize the effects of the emulsifying agent which allows the droplets in the internal phase to coalesce more easily. 3) Gravity Gravity separation is significant within a heater treater. The lightest product (gas) rises to the top, the heaviest product (water) falls to the bottom and the oil sits in between the two, ready to be extracted from the middle of the heater treater. Heater treaters are sized much larger than separators. The fluid may be within the treater for 8-20 times longer than in a conventional separator. The lengthy retention time allows longer for gravity separation to take place.

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Minor Factors 4) Water Washing Water washing takes place in the bottom of the treater. The emulsion enters the treater at the bottom and flows upward from the bottom to the top. At the bottom of the treater is a large box with holes cut in the top called the spreader, which uniformly disperses the emulsion in the treater. As the emulsion leaves the spreader, it rises upwards through the large body of free water, which has already separated from the emulsion. Because water molecules are very polar, this free water acts like a magnet to attract out the small water droplets from the emulsion. This is exactly the same principle demonstrated when you wet a cloth before you go to wipe up a spill. A wet cloth attracts more water drops than a dry cloth. 5) Filtration A wire mesh filter pack placed in the middle of the treater provides a large surface upon which the water phase can collect. The filter strips the water out of the emulsion as the oil portion rises upwards through the heater treater. 6)One Additional Force - Electrostatics There is one additional force that we can make use of – electricity.

Figure 10

An electrostatic heater treater (see Figure 10) contains a series of charged plates. Each plate carries either a positive or negative charge. As the emulsion passes between pairs of oppositely charged plates, water is attracted to them. Unfortunately, electricity is expensive and can be unreliable in our remote oilfield installations. Any loss of power means that untreated emulsion flows through the unit, resulting in non-specification oil in our sales tanks. Wet oil must be 30 Copyright  2013, 14 Canadian Association of Petroleum Production Accounting

reprocessed through the facility as the oil transmission pipeline operator will refuse to receive non-spec. oil into their system. SUMMARY OF TREATER OPERATIONS Settling The settling section is the last section of the treater. In this section, the main process taking place is the merging together of the tiny water droplets to form larger water droplets, which then settle out by gravity. The time required for this coalescence is called settling time. The size of the settling section determines the maximum volume of emulsion that can be processed through the unit each day. Treater Temperatures In practice, the treater temperature has the greatest influence on all the factors affecting economics. Treating temperatures are normally about 50 degrees C (120 degrees F). Operating the treater at a higher temperature than necessary causes losses in three ways. 1) It causes the lightest liquid hydrocarbons to be vapourized to gas within the treater. This is undesirable for two reasons. First, the vapourization causes shrinkage in the liquid volumes. The operator would rather have liquids than gas because liquids are more valuable. 2) Because only the lighter hydrocarbons are vapourized (the heavier ones do not) the oil becomes denser and more viscous and less valuable (lower oil price). 3) High oil temperatures cause further vapourization of the oil while it is sitting in the clean oil stock tank. This is called stock tank vapour losses or weathering losses. These losses again cause shrinkage in the volume and a resultant increase in the density and viscosity and a lower oil price. Onward The oil leaving the treater should now meet pipeline specifications (≤ 0.5% BS&W) and is sent to the clean oil stock tanks to await disposition. Water is forwarded to the water treatment area for further cleaning before disposition. Gas from the treater is sent to the Vapour Recovery Unit (“VRU”) where it is compressed and delivered into a gas gathering system that will transport the gas to a gas plant for further processing.

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Topic 5: Disposition of Products The student will learn about the Vapour Recovery Unit in the battery gas disposition system. Objective 15:

GAS DISPOSITION Vapour Recovery Systems When the treated oil is put into the stock tank at near atmospheric pressure, some liquid of the lighter hydrocarbons flash to gas (vapourize). The gas that was in solution (commonly referred to as “flash gas” or “stock tank vapour”) was for many years vented to the atmosphere. Government regulatory agencies now require that flash gas be recovered by means of a vapour recovery unit (“VRU”) for environmental and economic reasons. A vapour recovery unit consists of a small scrubber (two phase separator) and a compressor. At a given pressure, approximately one ounce of gas pressure, the compressor will start. It will shut off automatically at approximately 1/4 ounce of pressure. Liquids recovered in the scrubber are periodically removed and returned to the stock tank. The compressed gas is delivered into a gas gathering system. Gas cannot be stored on the surface once it is produced. Because gas produced at a battery will be at a relatively low pressure, it is routed to a gas gathering system where the gas pressure will be boosted by a compressor to allow it to flow into a gas processing plant. The raw gas volume recovered from the VRU is metered and recorded for comparison against the inlet gas volume received at the gas plant or transfer point. If there is no market for the gas, it may be injected back into the reservoir through a gas injection system and used for pressure maintenance in the reservoir. Gas returned to a reservoir is considered to be “creditable gas”. In other words, the gas is used for credit against the allowable for the well. If there is no gas gathering system or gas injection system to accept the gas, then it used to be sent to a flare where it will be burned. In Alberta, the AER will no longer allow flaring of unwanted gas except where it is uneconomic to conserve. Even so the AER may impose severe restrictions in the form of a reduced permitted oil production rate. Normally, the gas must be sold, injected into an enhanced recovery project, injected into a storage reservoir or used in some creative manner. 32 Copyright  2013, 14 Canadian Association of Petroleum Production Accounting

The student will learn about methods for treating produced water before it can be injected into the ground. Objective 16:

PRODUCED WATER TREATMENT The water removed from the bottom of the treater may contain a small amount of oil, usually less than 1% and will contain dissolved salts and chemical compounds that may be hazardous to the environment. This water must be treated before it can be disposed of. If untreated water were to make its way into surface water or ground water formations, it could be hundreds or thousands of years until all the contaminating water flushed its way through the aquifer. Major treating facilities handle large volumes of oil and water. It is important to remove all oil from the water phase before it is pumped to disposal facilities for two reasons:  Even if as little as 1% of the water volume is oil, we have the opportunity to recover a significant additional volume of oil. Oil recovered from the water phase can be retreated and sold as a revenue product.  If the oil is not recovered from the water before the water is disposed of, and instead injected into the ground along with the water, the oil can have an adverse effect on disposal wells, pumps and other equipment by gumming them and clogging them up. Various pieces of equipment are used to do this final treatment of the water phase. Some are listed below: Skimmers – The water / oil mixture is put into a very large tank which gives us a very long retention time, and allows gravity a longer time to work its magic. A rotating boom skims the oil from the surface into a trough along the top of the tank (Figure 11).

Figure 11

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Water is continuously received into the skimmer tank from the treater and the skimmer operates continuously. The oil skimmed off the top is collected in a “slop oil” tank. The slop oil will be returned to the heater treater for reprocessing. . Aerated Skimmers – An aerated skimmers (“sparger tank”) can also be used. Air bubbles are passed up through the tank from the bottom, which literally lifts the oil droplets to the surface. This vessel (Figure 12) accomplishes the final water treatment much quicker than by normal gravity settling in a non-aerated skimmer tank. A rotating boom collects the oil at the surface into a trough, which flows into a slop oil tank. The recovered oil is returned to the heater treater for reprocessing.

Figure 12

Filters – The water is passed through a filter (Figure 13) normally filled with sand.

Figure 13

The sand filter traps the oil droplets in the space between the sand particles. The filter is periodically backwashed to clean the filter. Unlike the skimmers, this is a batch process, where the unit is on service cycle, then backwash, then service, etc. 34 Copyright  2013, 14 Canadian Association of Petroleum Production Accounting

The backwash water is collected in a slop oil tank, and at a convenient time, is sent to the heater treater. Coalescers - A coalescer is similar to a filter with the exception that it is filled with fibers upon which the oil coalesces. Coalescers must also be back washed periodically to remove the collected oil. In many cases, the fibrous matter cannot be backwashed and must be removed and sent for disposal. (Figure 14).

Figure 14

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The student will learn the difference between water injection and water disposal wells. Objective 17:

WATER DISPOSITION Salt Water Disposal Wells Upon application to the AER, permission may be granted to dispose produced water into a formation that, in the AER’s opinion, is environmentally safe. Salt water disposal wells are used for disposing produced water. In order to minimize the impact on potential oil bearing areas, the salt water disposal wells are located as far away from the reservoir as possible. Thus, water disposal wells are usually remote from the treating batteries. At a salt water disposal well, produced volumes are pumped into a formation that is highly permeable and contains fluids that are compatible with the water being disposed, with little regard for injection rates or pressures. The water tanks and pumping equipment are usually located at the salt water disposal facility and not at the central treating battery. Water Injection Wells Water injection wells provide a more desirable alternative for disposal of produced water. At a water injection well, water is injected back into the reservoir from where it was produced in order to maintain the reservoir pressure, which in turn drives out additional oil from the formation. Water injection is also called secondary recovery, water flooding or enhanced oil recovery (EOR). If the water is returned to an approved water injection scheme, water credits are granted by the AER. Creditable water reduces any water related penalty (reduction) to the permitted allowable production rate for the producing wells. Unlike water being pumped into an aquifer simply to get rid of it, water pumped into a reservoir as part of a waterflood is injected under very carefully controlled conditions. It is pumped into a reservoir slowly at carefully monitored and controlled surface pressure to avoid fracturing the formation or distorting the pattern of flood banks. Generally, one cubic metre of water is injected for every cubic metre of emulsion production from the reservoir. The volumes are converted to reservoir conditions by the reservoir engineer. Water injection is occasionally used on small fields with fewer than fifty wells, but usually is reserved for larger unitized projects. Injection projects usually consist of a number of injection wells arranged in patterns. Waterflooding is discussed more fully in Module 1.6 Recovery Processes 36 Copyright  2013, 14 Canadian Association of Petroleum Production Accounting

The student will learn about the two most common ways to move oil from an oil battery onto an oil transmission pipeline. The student will be introduced to a LACT unit. Objective 18:

OIL DISPOSITION The two most common ways to move clean oil from the stock tank onto the oil transmission pipeline are by truck and by connecting pipeline. Transfer of oil to market by truck requires a tank truck to pick up clean oil and deliver it to a terminal located on a feeder pipeline. Bad weather conditions or spring time road weight restrictions can cause wells to be shut-in due to either insufficient storage capacity in the stock tank and / or bad roads that make it difficult, if not impossible, to get a tank truck on the lease. Transfer of oil to an oil transmission pipeline by connecting pipeline is by far the more common method. It involves the least human intervention, and is generally more economical in the long run. The disposition of oil through pipelines can even be automated to run 24 hours a day with the addition of a Lease Automatic Custody Transfer (LACT) Unit at the battery. A lease automatic custody transfer unit is used to automatically move oil from battery’s storage tanks into the oil transmission pipeline. The LACT unit is usually owned by the pipeline company and resides on the pipeline company’s lease, directly adjacent to the battery lease. It is fully automatic and is intended to run unattended for weeks at a time. The custody transfer component of the name is derived from the fact that at the LACT unit, custody of the oil is transferred from the battery operator to the pipeline operator. The ownership of the oil also changes as the oil passes through the LACT unit. Parties taking oil in kind at the battery outlet (oil companies, the Crown in Alberta and some freehold owners) sell their oil to another group of companies (collectively called “Shippers”) as the oil passes through the LACT unit. Shippers own the oil on the oil transmission pipeline. The metered battery disposition volume from the LACT is used as the basis for oil sales revenue. As the size of treating and storage facilities increases, so does the complexity of metering and transferring crude oil to the pipelines that carry it to refineries. Each pipeline will also have strict contract requirements on the metering, volume, and composition of the oil as it enters the pipeline. A LACT unit also analyzes the oil transferred from a producing lease to a pipeline for BS&W content. If the oil is off spec, the LACT unit will either shut down or, if equipped, a three-way valve will route the off spec oil to an emulsion tank until spec oil is reached and can be shipped. 37 Copyright 2013,14 Canadian Association of Petroleum Production Accounting

A LACT unit is composed of several components (Figure 16).

Figure 16

1) A high/low level sensor on the tank - signals the pump to start or shut off. 2) A pump - moves oil from the clean oil tank to the feeder pipeline. 3) A BS&W monitor - continuously measures the BS&W content of the oil moving towards the pipeline. 4) A 3-way diverting valve - accepts signals from the BS&W monitor and decides where the fluid will flow. If the BS&W is less than or equal to the contract water specification, then the oil passes through the valve to the pipeline. If the BS&W content exceeds contract water specifications, then the oil is returned to the battery emulsion tank for re-treating. 5) A precise liquid meter - meters volumes delivered for sale. The meter is usually a positive displacement (P.D.) meter that contains provisions for correcting the recorded volume for the expansion of oil due to pressure and temperature variations. 6) An automatic sampler - collects a sample of a few drops for every tenth of a cubic metre that flows into the pipeline. 38 Copyright  2013, 14 Canadian Association of Petroleum Production Accounting

7) A sample container - stores the fluid samples until they are picked up and analyzed by a representative of the pipeline company, usually monthly. 8) Check valve - keeps oil from flowing from the pipeline back to the battery when the LACT pump is off (Figure 17).

Figure 17

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Objective 19:

The student will be introduced to a battery flow schematic.

SUMMARY OF OIL BATTERY OPERATIONS Equilibrium in Treating Facilities When a major treating facility is operating normally, it develops equilibrium whereby the tank levels stay within well-defined limits, the treaters hold liquid at stable levels and produce oil with nearly constant water cut. Pumps operate at regular intervals, and other equipment performs predictably. As long as the battery stays in equilibrium, a major facility can often operate with minimum operator observation and intervention. However, a sudden change in operating conditions such as an equipment failure, a surge in inlet fluid flow rate, or a major adjustment in operating conditions can upset this equilibrium. For the next several hours, close attention and manual operation must be performed on the system to regain equilibrium. By carefully selecting and installing the pieces of equipment used in the facility, operators can minimize the difficulty of reaching equilibrium and regaining equilibrium after an upset. Sample Oil Battery Flow Schematic Each battery is a custom design for the specific requirements of the wells that it serves. Two adjacent batteries in the same field may have different configurations and equipment, although basically each is handling the same oil, water, and gas. Even the equipment may be different. The batteries will contain equipment for routing flow (inlet header), separating and treating vessels for the group and test trains, liquid and gas meters, tankage and disposal facilities. Figures 18 and 19 show the schematic flow for two different oil batteries with LACT facilities.

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Figure 18

Figure 19

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Topic 6: Field Operations - Measurement

Objective 20:

The student will be introduced to various classifications of meters.

Most production and treating vessels at a battery will be equipped with a meter to record the volumes entering or exiting that vessel. It is almost impossible to accurately measure two-phase flow, i.e. gas and liquid flowing in the same stream. To get around this difficulty, gas is separated from liquids and then the individual streams can be measured. Meters can be broadly classified as gas meters and liquid meters. These types can be further broken down into direct measurement (positive displacement) and inferential meters. Direct measurement means just that. You directly measure the volume. It is equivalent to filling, emptying and counting a number of shot glasses of a fluid. Inferential measurement determines the volumes indirectly. Inferential measurement relies on measuring some other attribute and then indirectly calculating the volume. These two measurement types can be illustrated by the following example. Given a rain barrel almost full of water, how could you measure the volumes? One way would be with a measuring cup. Filling, emptying and counting the number of cups of fluid in the barrel would give you the total volume. This is an example of positive displacement. A second way to determine the volume is with a metre stick. Measure the diameter of the barrel and the depth of the water with the metre stick. Determine the radius of the tank by dividing the diameter by two. From geometry, you can calculate the volume in the tank based on the formula for determining the volume in a cylinder: Volume of water in barrel = (pi × radius squared) × height By using the formula you have not really measured the volume directly, instead you measured things such as radius and height from which you inferred (calculated) the volume in the tank. The most common meter types and applications where you would typically find them are listed in the table below.

Positive Displacement (PD) Inferential

Gas Measurement Roots Meter Compressor / lease fuel measurement Orifice Meter Gas Production / sales gas

Liquid Measurement Floco Meter Oil production / Oil sales. Oil / emulsion tests. Turbine Meter Water

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Objective 21:

The student will be introduced to an orifice meter.

INFERENTIAL GAS MEASUREMENT Gas meters are the source of group gas production and test gas volumes needed each month by the production accountant. The most common gas measurement device is an orifice meter. It is an inferential measurement device. A gas chart records the static and differential pressures as the gas flows past an obstruction (an orifice plate) in the flow line. A thermocouple is normally inserted into the pipeline just downstream of the orifice meter to measure the temperature of the gas. The gas temperature is also recorded on the gas chart. Gas charts are integrated (read) by trained personnel. They convert the chart recorder pen pressure tracings into gas volumes. Please refer to Figure 20 - Gas Orifice Run.

Figure 20

Sample gas charts are shown in Figures 21 and 22. Gas charts come in a variety of pressure ranges. A clock drives the gas chart. Both 7 day and 24 hour chart formats are common. The 7 day format is more common for a group gas production or for continuously measured gas wells. The 24 hour chart is more common for well tests. 43 Copyright 2013,14 Canadian Association of Petroleum Production Accounting

Figures 21 and 22

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Objective 20:

The student will learn about a gas positive displacement meter.

DIRECT GAS MEASUREMENT The most common direct gas measurement device is a positive displacement meter. The Roots meter was the first device used to directly measure gas volumes. As such, the word “Roots” has been adopted into the oil and gas industry language as meaning “any device that directly measures gas volumes”. There are many other devices and many other manufacturers of direct measuring gas meters, but we will describe the Roots meter (Figure 23).

Figure 23

The Roots meter consists of an elliptical chamber with two paddles inside it. The ends of the paddles are built so that they are always touching each other and the case in such a manner as to prevent gas from escaping around them. As gas enters the meter, the paddles rotate until one of the paddles is vertical. At that time, the ends of vertical paddle seal against the case – top and bottom. The other paddle is horizontal. One end seals against the housing, while the other seals against the vertical paddle. At this time, the chamber formed by the vertical paddle becomes the fixed known volume and the counter is incremented. As more gas enters the meter, the gas that was in the fixed volume spills out of the meter and the other paddle will fill with the gas to form the next fixed volume. 45 Copyright 2013,14 Canadian Association of Petroleum Production Accounting

Objective 23:

The student will learn about a liquid positive displacement meter.

DIRECT LIQUID MEASUREMENT The positive displacement meter is the most commonly used measuring device for metering oil, emulsions, condensate and natural gas liquids. A positive displacement (PD) meter works by moving fluid through a mechanical seal arrangement into unique segments within the meter of a known volume. A mechanical counter records the number of segments filled and discharged. A liquid positive displacement meter works in much the same way as a revolving door with a queue of people going through the door. Every time a person goes through the door the counter increments by one. The operation of this meter type can be paraphrased as: fill, empty and count. As with the gas positive displacement meter terminology, the brand name “Floco” has been adopted into the oil and gas industry language as meaning “any device that directly measures liquid volumes. Please refer to Figure 24.

Figure 24

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Advantages:  Direct reading  Stand alone, no power requirement  Economical  Low pressure drop. Disadvantages:  Wear on mechanical parts  Expensive to repair  Does not tolerate gas flow. PD meters are typically used any time that you need extremely accurate liquid measurement. At a battery lease, this would be any time you meter emulsion or oil. You would find PD meters on the oil lines on the treater, on the emulsion lines from the test separators and in the LACT unit. FLOCO meters are often fitted with a small proportional sampler that allows a few droplets of fluid to be captured in a sample jug every time the meter clicks a hundredth of a cubic meter of fluid. This sample can then be put through a centrifuge test to determine the water cut (BS&W).

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Objective 24:

The student will learn about an inferential liquid meter.

INFERENTIAL LIQUID MEASUREMENT The turbine meter is the most commonly used measuring device for metering water. A turbine meter is also used in many applications where volumes of hydrocarbon liquid are required to be measured, but where that accuracy is not as critical – that is, not custody transfer and no money issues. In a turbine meter, a spinning turbine is inserted into the meter (Figure 25).

Figure 25

A small magnet is placed on one of the blades. The fluid volume is measured by counting the number of pulses generated by the meter impeller blades as they pass a magnetic pickup. This produces an electronic impulse, which is picked up by a totalizer. The more fluid that goes through the meter, the faster the turbine spins, and the faster the totalizer count increases. The frequency of the rotational speed is converted to a volume based on a mathematical formula. Advantages:   

Simple to repair Few mechanical parts No seals to wear or leak

Disadvantages:   

Small bearings do not tolerate sand High pressure drop Requires electric power access for totalizer.

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The student will learn about the meter proving process and how a meter factor is determined. Objective 25:

METER PROVING Even the best meter (no matter how well it is designed, installed and maintained) does not always measure exactly the amount flowing through it. Each has a particular margin of error, as a result of design limitations or from wear and tear on mechanical parts. Determining the meter’s accuracy, or “proving” the meter, is a very important job in the oil industry. Revenue and royalty payments are based on metered volumes. Each meter must be periodically checked or proved to determine its margin of error, i.e. the differences between what the meter registered and the actual true volume flowing through the meter. Regulations for the calibration of meters falls under the jurisdiction of the AER for non-custody transfer meters and under Measurement Canada for custody transfer meters. Proving a meter in theory is a simple process. You compare the registered volume with a known volume. A proven meter is placed in series with the meter to be calibrated through a series of fittings in the piping. You make a run of a few cubic metres of fluid through the meter and then compare the reading from the proven meter with the reading from the meter to be calibrated. The ratio of the calibrated meter to the test meter is known as the meter factor. Meter factors are calculated to at least four decimal places. Several runs are made during the meter proving tests until the meter factors from the tests are sufficiently close. You need to get 3 consecutive tests where the meter factors are within 0.0005 of each other. We use the average meter factor from the three successful runs as the final meter factor. Results of the meter proving test are recorded on a meter proving report which should be filed in the battery production files. By regulation, this meter factor must be stamped onto a metal tag that is attached to the meter. In meters where large volumes are being measured (in a major pipeline or in a refinery), meter factor accuracy of 0.0005 results in a material error. For these large volume meter situations, a formula is often used in conjunction with the meter factor to account for fluid density and temperature correction issues.

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Topic 7: Calculation of Net Fluid Volumes Objective 26: The student will be shown how to calculate the net oil and water

volume given opening and closing meter volumes, water cut and meter factor. CALCULATION OF NET OIL AND WATER VOLUMES The calculation of net oil and water volumes, given a pair of meter readings a meter factor and a water cut, is a four-step process: 1. Determine the difference of the meter readings; this is the gross uncorrected metered volume. 2. Determine the corrected volume from the product of the uncorrected volume and the meter factor. 3. Use the water cut to determine the water volume from the product of the corrected volume and the water cut converted to a decimal fraction. 4. Determine the net oil from the difference of the corrected volume and the water volume.

Example Given the following information, calculate the net oil and water volumes: Opening Meter Reading Closing Meter Reading

18,642.75 m3 19,557.22 m3

Meter Factor = 1.0024 Water Cut = 0.3 % BS&W Calculate the net oil and water volume Step 1 – Calculate the Gross Uncorrected Metered Volume Uncorrected volume = Closing Reading – Opening Reading = 19,557.22 – 18,642.75 m3 = 914.47 m3 Step 2 – Correct for meter factor = Gross metered volume * Meter Factor = 914.47 × 1.0024 = 916.66 m3

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Step 3 – Calculate the Water = Corrected metered volume * Water Cut % / 100 = 916.66 × (0.3 / 100) = 2.75 m3 Water Step 4 – Calculate the Oil = Corrected metered volume – Calculated Water Volume = 916.66 - 2.75 = 913.91 m3 Oil Step 5 – Report the Oil and Water Volumes Oil = 913.9 m3 Water = 2.8 m3

NOTE 1: In Directive 017, the AER specified that all calculations must be determined to a minimum of two decimal places and then rounded to one decimal place for monthly reporting. Most companies internally calculate volumes to two or more decimal places, but Petrinex will only accept one decimal place. Volumes MUST be rounded to one decimal place when reporting. For purposes of your exam, ensure that you read the instructions given in the question before performing any calculations.

NOTE 2: As meters are used, wear is incurred and so a meter may not necessarily be accurate. To counteract this, it is calibrated, or proven, and a meter factor is developed, that when applied to a measurement, the result will be correct. We discussed this procedure in the previous objective.

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The student will be introduced to prorating production at a multiwell oil proration battery. Objective 27:

PRORATION In a proration multiple well battery, production from each of the wells is periodically isolated from each of the other wells for a minimum twenty-two (22) hour period so that its oil, gas and water production can be determined accurately (a “well test”). Production from each well is isolated at the inlet header. The operation of an inlet header was discussed in more detail in a previous objective. The estimated monthly production for the battery is determined by summing the results of well tests for all the wells during the month. During the month, the battery operator records receipts into the battery from sources other than wells that are connected via the gathering system. The operator measures the battery’s closing inventory at month end. This closing inventory becomes next month’s opening inventory. There is usually a small amount of water mixed with the oil that is delivered to the pipeline. The operator of the pipeline system that receives deliveries of oil from the battery advises the battery operator of the volume of oil and water they received during the month. The water disposal /injection facility operator reports the amount of water received into their facility during the month. The gas gathering system (“GGS”) operator reports the gas volume received onto their GGS during the month from the battery. Given all of the above, the battery operator calculates the monthly actual battery production using the relationship: Production = Closing Inventory + Dispositions – Opening Inventory – Receipts or P = CI + D – OI – R The battery’s monthly proration factor is determined as follows: Proration Factor = Actual Production Estimated Production The proration factor is reported to five decimal places.

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Next, each well’s actual production is determined: Actual Well Production = Estimated Production * Proration Factor We will now do an example to illustrate the calculation. The student is advised that this calculation is basic to the production accountant and will be performed several times throughout this course. Opening Battery Inventory Closing Battery Inventory Receipts into the Battery Dispositions from the Battery

= 25.2 m3 = 37.4 m3 = 0.0 m3 = 97.8 m3

Actual Battery Production: P = CI + D – OI – R P = 37.4 + 97.8 – 25.2 – 0.0 P = 110.0 m3 This is the actual total volume of oil that was produced from all of the wells that produced to the battery via the gathering system. We know this, because we got paid for it and the meters used for the measurement are carefully calibrated. Each well’s estimated production as determined from the well tests is as follows: Well

10-20-16-24-W5 12-20-16-24-W5 14-20-16-24-W5 Total

Test Rate m3/d

Production Hours

1.00 2.00 4.00

720 360 240

Estimated Production (m3) 30.0 30.0 40.0 100.0

The monthly proration factor for the battery is: Proration Factor =

actual production estimated production

= 110.0 = 1.10000 100.0

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Each well’s estimated production is multiplied by the battery proration factor to determine the actual (prorated) production for each well. Well

10-20-16-24-W5 12-20-16-24-W5 14-20-16-24-W5 Total

Estimated Production (m3) 30.0 30.0 40.0 100.0

x x x x

1.10000 1.10000 1.10000 1.10000

Actual Production (m3) = = = =

33.0 33.0 44.0 110.0

Note: The preceding calculation is done separately for oil, water and gas.

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Topic 8: Storage The student will learn about battery oil and water tankage requirements and how tank liquid heights are converted to volumes. Objective 28:

OIL AND WATER BATTERY TANKS The clean oil waits in the stock tank for delivery to an oil transmission pipeline. The stock tanks are commonly referred to as the tank battery. The tanks in a tank battery will vary in number and in size, depending upon the daily production of the battery and the frequency of pipeline runs. The introduction of automatic custody transfer units and their acceptance by pipelines and producers has greatly reduced storage requirements. The total storage capacity of a tank battery is usually in the range of three to seven days of production. There are usually two or more tanks in a battery, so that while oil is being run from one tank, the other tank can be filling. Most tanks are made from either bolted or welded steel. Welded steel tank capacities vary from 15 to 500 m3 (90 to 3,000 bbl). Bolted steel tank capacities vary from 20 to 1500 m3 (100 to 9,000 bbl). Before a tank battery is put in service, each tank is “strapped”. To strap a tank, a known volume of fluid will be placed in the tank and it will be gauged to determine the relationship between the height of fluid in a given tank and the volume in the tank. Progressive measurements are taken and a table is prepared showing the volume of fluid in the tank that corresponds with each interval of fluid height in the tank. The point where the pipeline company connects to the lease stock tanks is usually about 30 cm (one foot) above the bottom of the tank. The space below the pipeline outlet provides room for the collection of BS & W. Each tank has a bottom drain that is periodically used to drain off any accumulated BS & W. In some producing areas, tanks must be cleaned frequently due to the collection of paraffin, sand and sediments. These materials cannot be removed through the drain outlet. Therefore, tanks are equipped with a clean out plate called a “manway” through which workmen can enter the tank and shovel out the accumulated trash. The amount of oil in a tank can be determined with a steel measuring line called a gauge tape or through an automated gauge measurement device. When manually gauging, a gauge tape is lowered into the tank through a thief hatch. By comparing the gauge height with the tank table, the volume of fluid in the tank 55 Copyright 2013,14 Canadian Association of Petroleum Production Accounting

can be determined. When gauging the tank, a sample of oil is usually taken from the tank using a thief. The sample may be collected at multiple heights in the tank. Each sample is collected by the thief, which is lowered to the desired location in the tank and then tripped to seal the sample reservoir. The recovered sample is examined to determine the BS & W content, density, and temperature of the oil. The temperature of the sample is measured at the time the sample is recovered. These factors affect the price paid for the oil. The temperature of the oil is important as volume changes with temperature. Oil volumes decrease as temperature decreases. By recording the temperature, and knowing the gravity of the oil, the volume can be corrected to standard conditions of temperature (15 degrees C) and pressure (101.325 kPa).

Water Storage Tanks Storage, treating and disposal of water co-produced with the oil is an important part of the battery operation. Like oil tanks, water storage tanks will be bolted or welded. Facility tank capacity is sized to hold from 3 to 5 days of the expected volume of water recovered at the battery. Water may be disposed at centralized salt-water disposal facilities that may serve several batteries. Therefore, the water storage tanks are not necessarily located at the oil battery. Water tanks can be gauged or if the produced group water production is stored off-site, it will be metered as it comes off the group treater.

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Topic 9: Manually Calculating Storage Tank Volume Objective 29:

The student will learn how tank liquid heights are converted to

volumes. OIL AND WATER BATTERY TANKS The strapping table created when a tank is manufactured and installed is used to determine the volume of liquid in the tank. A strapping table may also be referred to as a “tank table”, “gauge table” (Figure 26). The strapping table usually shows tank volume for each 0.5 cm. change in height (1/4 inch) from the bottom to the top of the tank. The height of oil in a tank can be determined with a steel measuring line called a “gauge tape” or through an automated gauge measurement method. When manually gauging a tank, a gauge tape is lowered into the tank through a thief hatch. By comparing the gauge height with the tank table, the volume of fluid in the tank can be determined. An example of using the Gauge Tables is as follows: An operator is ready to run a tank (transfer its contents to a truck). He measures the height of liquid in the tank prior to transferring and records it as the opening level. After the tank has been run to the truck, he measures the liquid level and records it as the closing level. The readings are as follows: Opening level Closing level

4.35 metres 2.11 metres

To determine the volume of liquid in the tank, he consults the Gauge Table (Table 1). From Page 2 of the Table, he would locate 4.3 metres by reading down the first column. Then he would read across to the column headed 0.05. The volume that he would read is 45.46 m3. This is the Opening Gauge. Similarly, he would go to page 1 of the table to locate the volume for the height 2.11 metres. The value from the table is 22.05 m3 and would be recorded as the Closing Gauge. Hence the volume of fluid shipped is: Open Gauge – Closing Gauge = 45.46 – 22.05 = 23.4 m3 Note that the final volume is rounded to one decimal when reported. Remember also, that a sample would have been taken to determine the density, BS&W and temperature.

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Figure 26 - Page 1

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Figure 26 - Page 2

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Topic 10: Field Facilities – Gas

The student will learn about gas hydrates and the methods used to control their formation. Objective 30:

GAS HYDRATES

Gas exists within the formation at a very high pressure and temperature. When gas is produced and brought to the surface, the pressure and temperature of the gas effluent stream drops. As the gas stream cools, it can hold less and less liquid in vapour form and condensation occurs. When water vapour condenses as a liquid, hydrate formation can become a serious problem. Hydrates are ice-like crystals, composed of gas and water, which resemble a Slurpee. Hydrates can form at temperatures up to +20 degrees Celsius. If the Slurpee becomes cold enough, it will freeze into a solid which can completely block the gas flow line. Another problem is that hydrates increase corrosion rates within the gas flow lines. If the gas produced from a well contains sufficient quantities of water, equipment must be added at the wellhead to control hydrate formation. Three methods deal with the problem of water condensation and hydrate formation in a gas gathering system. The first method is to heat the gas stream to a temperature above the hydrate formation temperature. The second method is chemical injection of hydrate inhibitors into the gas stream. The third method, known as dehydration, involves removal of water from the gas stream. 1) Heating Heat tracing the gas flow line or use of an indirect heater can be used to heat the gas stream to above the hydrate formation temperature. This suppresses hydrate formation. An indirect heater (Figure 27) is the most widely used type of heater on a gas well. The unit consists of three basic parts: the heater shell, a removable fire tube and burner assembly and a removable coil assembly. The heater shell is usually filled with water, which completely covers the fire tube and coil assembly. Gas moves through the coil assembly. The fire tube heats the water bath and the coil assembly is heated by the water bath.

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Figure 27

2) Inhibitor Injection Some chemicals, such as ammonia, glycol, methanol, and brines, inhibit the formation of hydrates by lowering the freezing temperature of the gas stream. The inhibitor chemical is injected directly into the gas flow line. Inhibitor injection is used when hydrates form intermittently. Use of chemical hydrate inhibitors can be a significant operating cost burden. These chemicals are not normally recovered at the gas processing facility. When hydrates are a persistent problem one of the other two methods is used.

3) Dehydration Dehydration means removal of water. Since hydrates will not form in a gas line where there is no water, dehydration solves hydrate problems. The equipment used is complex and so is not normally used in the field. Dehydrators are normally found at gas plants and are used to condition the sales gas so that heating or inhibitors are not required for the long distances that sales gas must travel.

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The student will learn about two important impurities: carbon dioxide and hydrogen sulphide. Objective 31:

There are five common impurities that may be produced with our gas or oil. These are hydrogen, helium, nitrogen, carbon dioxide and hydrogen sulphide. The two that concern us the most, carbon dioxide (CO2) and hydrogen sulphide (H2S), are discussed in this objective. CARBON DIOXIDE Carbon dioxide reacts with water to form a mild acid (carbonic acid). Our pipelines and vessels are made of steel. Since acid can corrode steel, we have to solve this problem to protect our infrastructure. One solution is to add chemicals called “corrosion inhibitors” to protect the steel. This is an acceptable solution for our internal field operations but the sales gas transmission pipeline companies will not accept this solution. When we use a corrosion inhibitor in our field operations, we must remove it in our processing facility, before it enters the transmission pipeline. The preferred solution, from the gas transmission pipeline operator’s point of view, is for us to remove the water from the gas stream. With this solution there will be no carbonic acid because acid cannot form without water – no water, no acid, no corrosion. The transmission company is willing to tolerate a small amount of CO2 in the sales gas once the water has been removed. Another problem with carbon dioxide is that CO2 in the sales gas stream degrades the value of the gas being sold. CO2 occupies space in the gas transmission pipeline without contributing to the value of the gas being sold. The gas transmission pipeline company has a number of specifications that the sales gas must meet or they will refuse to accept the sales gas into their system. One of those specifications is a minimum heat content. If we leave too much CO2 in the sales gas, our gas will not meet the minimum heat content specification and we will be shut in. HYDROGEN SULPHIDE Hydrogen sulphide is nasty. Not only does it react with water to form a mild acid, it chemically attacks the steel (we use steel pipelines and vessels) directly in a process known as “hydrogen induced cracking”. As the name implies, over time hydrogen induced cracking can cause the steel to crack apart. Hydrogen sulphide has the additional problem of being extremely toxic, it can 62 Copyright  2013, 14 Canadian Association of Petroleum Production Accounting

kill. When H2S is present in a stream, the entire stream is referred to as “sour”. If H2S is not present, the entire stream is referred to as “sweet”. The following list outlines some of the more important characteristics of H2S:    

 

at less than10 ppm (parts per million), or 1/1000 of 1%, our noses can smell H2S (it smells like rotten eggs). at 100 ppm, our sense of smell becomes unreliable as a method of detecting H2S as it will deaden the olfactory nerve (the nerve we smell with) in 3 to 15 minutes. at 200 ppm, we may no longer be able to smell H2S. at 500 ppm, we may experience a loss of our sense of reasoning and balance and may suffer respiratory paralysis in 30 - 45 minutes. We will become unconscious within 15 minutes of continuous exposure to this level of H2S. at 700 ppm, breathing will stop and death may result if not rescued promptly. Artificial resuscitation may be required to restart breathing. at 1000 ppm (1/10 of 1%), we will immediately become unconscious. Permanent brain damage may result unless rescued promptly.

The above figures are approximate. Susceptibility to H2S poisoning varies according to the individual and the circumstances of the exposure. How often do we encounter these levels of H2S in the oil patch? Shallow zones (say to the base of the Cretaceous) usually do not contain H2S. Deeper zones (beginning with the Triassic) often contain H2S. Thus we need to be prepared for the presence of H2S when drilling through, or producing, from these deeper zones. Concentrations of H2S in our producing wells range from a trace (less than 10 parts per million (ppm)) to as high as 75 or 80% (although concentrations at this level are fairly rare). Additional safety precautions are necessary when dealing with fluids containing H2S. An operator producing fluids containing H2S must develop an emergency response plan and nearby residents must be advised of the plan. Field staff must be equipped with emergency respirators and either work in pairs or carry electronic H2S detectors for safety. Because they react with water to form mild acids, CO2 and H2S are individually or collectively referred to as “acid gases”. To solve all the problems related to hydrogen sulphide, we must remove virtually all of it from our raw gas in a special purpose gas plant. The operator of the sales gas transmission pipeline usually has a very low tolerance for gas with H2S. They 63 Copyright 2013,14 Canadian Association of Petroleum Production Accounting

will refuse to accept gas containing more than a trace of it onto their system. The natural gas leaving our gas plants and consumed by end users has no odour. The local distribution company adds a chemical (a sulphur based chemical called a “mercaptan”) to “stench” the gas (make it smell) so that if there is ever a gas leak in our homes, our noses will be able to detect it.

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Objective 32:

The student will learn about the equipment found on a gas well

lease. GAS WELLHEAD AND LEASE EQUIPMENT Produced gas falls into two categories: gas produced from gas reservoirs (nonassociated gas) and gas produced from oil reservoirs (solution gas and associated gas). This section deals with production equipment for wells that produce nonassociated gas. Gas wells produce effluent: a mixture of water, desirable gases (methane, ethane, propane, etc.), undesirable gases (carbon dioxide, nitrogen, hydrogen sulphide, etc.), and heavier hydrocarbons (natural gas liquids). Some gas wells also produce elemental sulphur. The field equipment needed to produce the gas is relatively simple. Equipment for conventional gas wells can be broken down into four categories:    

Wellhead and Lease Equipment Gas Measurement Devices Gas Gathering Systems and Gas Processing Plants.

The wellhead equipment can be kept to a minimum because the oil and gas conservation regulations dictate that all conventional gas wells require 24-hour continuous effluent measurement. In simpler terms, this means that each well must be treated as a single well producing entity, with its own gas meter. Therefore there is no group train / test train, headers, shared treaters or all the complexity of the proration calculations. In most cases, wellhead equipment consists of a wellhead valve assembly to control pressure and flow rate, possibly some separation equipment and possibly some hydrate control equipment. Refer to Figure 28 - Schematic of a Single Well Gas Battery. For most gas wells, the gas flow measurement device and recorder will also be located on the lease.

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Figure 28

Liquids Removal A major production consideration in a gas well is the presence of liquids that are co-produced with the gas. Liquids can be either free water, or natural gas liquids (NGL's). If significant amounts of liquids are produced with the gas, a two phase separator (Figure 29) will be installed at the lease to strip off all free water and/or gas liquids. The separator operates in the same manner as discussed in the section on single well batteries. If the liquids are recovered on the lease they can be collected in a tank and then periodically disposed as the tank becomes full.

Figure 29

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Another reason for a separator at the wellhead is because there are no meters that can accurately determine two phase flow. If two phase flow occurs at the wellhead, it is common practice to install a separator. The resulting separate gas and liquid streams are metered. Once metered, the two streams are normally rejoined into a single line that flows to the gas plant where the liquids will be extracted. The reason that the liquids are usually rejoined with the gas is that it is generally too expensive to install a pressurized tank and then have tank trucks constantly going to and from the lease. In most cases, it is more economical to centrally collect the liquids and water at the gas plant.

Gas Well Product Measurement Determining production on a gas well is relatively simple. According to the Oil and Gas Conservation Regulations, the AER dictates that all conventional gas wells (excluding shallow gas wells) must have continuous 24-hour wellhead effluent measurement. This rule means that effluent from each conventional gas well must be measured and there is therefore no need for test and group equipment. Each well is in effect its own measured single well battery. Note that this refers to conventional gas wells only. Shallow gas wells that are located in Southeastern Alberta and Southwestern Saskatchewan that produce from the Medicine Hat, Milk River and Second White Speckled Shale formations have special production accounting rules and surface equipment requirements that are covered in a later module. If there is no field data capture system in place, gas charts will be used. Gas volumes for these wells are usually recorded on seven-day format gas charts. Liquid volumes recovered at the lease are measured through a liquid meter or are gauged in the stock tank.

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Objective 33:

The student will learn about a gas gathering system.

GAS GATHERING SYSTEM

Gas cannot be stored at the surface once produced. Gas flow rates and volumes are immediately measured at the wellhead. The gas then flows into a gas gathering system. A gas gathering system may consist of a number of flow lines and compressors that are used to transport the gas from the producing leases to a central gas processing facility. The gas gathering system is buried below ground for most of its length. However, from time to time it will be brought above ground at a “riser” site. A riser is required for:  an above ground tie in of another well into the gas gathering system.  a pig sender  a pig receiver  a line heater  a compressor station Because there is a measurement facility at each individual gas well, the individual gas well flow lines may be tied in to the gas gathering system at any point along its length. If gas wells are flowing at a pressure below the inlet pressure of the gas processing plant or the gas pipeline, field compression will be required. If significant liquid volumes are present in a gas gathering system, a scrubber or two-phase separator may be necessary to ensure that no liquids get into any compressors. The separator is placed immediately upstream of the compressor to temporarily remove any liquids, the gas is compressed and the liquids are reinjected back into the GGS downstream of the compressor. Should the gathered gas meet pipeline contract specification without treatment, then it may flow directly into the sales gas transportation system. Otherwise, the gas gathering system will deliver gas to a gas plant for processing.

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Objective 34:

The student will learn about a gas processing plant.

GAS PROCESSING PLANT A gas processing plant may be as simple as a single large dehydration device or as complex as a sour, deep-cut facility. The main purpose of a gas plant is to remove all water, undesirable gases and any hydrocarbons that may drop out as liquids in the downstream sales gas transportation network. The main reason for removing liquids, other than for increased profit, is that when liquids form in a gas pipeline, they tend to gather in the low spots and plug the pipeline. The plug prevents gas from flowing through the pipeline. The companies operating major gas transportation pipeline networks have developed specifications for the quality of gas they will permit to enter their system. These specifications allow them to refuse to accept gas that may harm their system or be detrimental to equipment or people after the gas leaves their system. Wet gas must be processed in a gas plant to meet buyers’ specifications (basically to remove water, any hydrocarbons that may liquify in a gas transmission pipeline, excess carbon dioxide and all hydrogen sulphide). Water can be removed via a dehydrator. Valuable hydrocarbon liquids are removed in a refrigeration plant. Hydrogen sulphide and any carbon dioxide in excess of the buyers’ specifications are removed in an amine plant. Most gas plants use a relatively simple refrigeration process that results in some of the propane (C3) and butane (C4) remaining in the gas phase. If the gas contains a substantial amount of C3 and C4, the gas plants may use a somewhat different process that lets them operate at a much colder temperature to recover much of the ethane (C2) and virtually all of the C3+.

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Objective 35:

The student will learn about common processing units found in a

gas plant.

GAS PLANT FUNCTIONAL UNITS A brief look at the various functional units in a gas plant follows. Inlet Separation – The gas gathering system terminates at the gas plant’s inlet separator. The inlet separator removes free water and liquid hydrocarbons coproduced with the gas. Inlet separation knocks out the majority of the entrained liquids and allows the gas to be further processed. Dehydration – The dehydrator removes any remaining water from the gas. Either liquid desiccant dehydrators or solid desiccant dehydrators are used. Water can be removed by bubbling the gas up through certain liquids such as ethylene glycol (car antifreeze). This process is known as “absorption”. Alternately, water can be removed by passing the gas over beds packed with solids, such as molecular sieves, or silica gel, that also have a great affinity for water. When water collects on the surface of a solid, the process is known as “adsorption”. The substance that removes the water is known as a “desiccant”. Two types of common dehydration equipment are liquid glycol absorbers (Figure 30) and solid desiccant dehydrators (Figure 31). Acid Gas Removal - Removes hydrogen sulfide (H2S) and excess carbon dioxide (CO2). As mentioned in a previous objective, H2S is highly toxic and corrosive. It must be removed from the gas before the gas can be sold. The process is accomplished through contacting the gas with an amine based chemical that has a high affinity for H2S and CO2. The amine solution is circulated through a vessel referred to as the amine tower or the amine contactor. As the gas passes through the amine solution, the amine absorbs the H2S and CO2 from the gas. The result is sweet gas and sour or “rich” amine. The sweet gas carries on through the plant. The rich amine is boiled to drive off the H2S and CO2. The H2S and CO2 then move onto the sulphur plant for further processing.

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Figure 30

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Figure 31

Sulphur Plant - The vapours of the amine regeneration process are H2S and CO2. H2S cannot be released directly to the atmosphere. A sulphur plant converts the H2S into elemental sulphur. The elemental sulphur is usually sold immediately as a liquid or solid. For remote locations where transportation of liquid or solid sulphur is problematic and during periods of weak sulphur prices, sulphur may be stored on site (“poured into a block”). The solid sulphur can be remelted and sold at a later date when circumstances warrant. In the sulphur plant, the H2S is burned with oxygen in a reaction furnace. The resultant gas is reacted with activated alumina in a vessel referred to as a catalyst bed. The products of this process are water and elemental sulphur. Any remaining H2S is incinerated. The CO2 in the acid gas stream is not affected by this process. The CO2 ends up going up the incinerator stack. The water is condensed and disposed.

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Natural Gas Liquids Recovery - Removes and separates hydrocarbon liquids into condensate (pentanes plus), butane and propane products. If a compositional analysis of the raw gas indicates it will not be accepted onto the gas transmission pipeline company’s pipeline because hydrocarbon liquids will form above -10 degrees Celcius, gas liquids extraction towers will be installed in order to produce specification gas. If the raw gas contains only a minor amount of condensate and / or natural gas liquids the refrigeration plant will be relatively small in size and will likely produce two products: condensate and an NGL mix. The NGL mix will be sold to an NGL aggregator who will process the mix in their fractionation plant (specialty plant, different location) to separate the NGL mix into specification propane and butane. If the raw gas contains a larger, but still modest, amount of condensate and / or natural gas liquids the refrigeration plant will be larger in size and will likely produce three products: specification quality (“spec”). condensate, spec butane and spec propane. Each product is sold into its own end user market. If the raw gas contains a substantial amount of condensate and / or natural gas liquids the refrigeration plant will be much more complex in nature. It will operate at a much colder temperature and will produce four products: spec. condensate, spec butane, spec propane and spec ethane. The removal of these products is accomplished through refrigeration. The gas stream is cooled to the temperature necessary to allow the condensation of the individual gas liquids. The condensate, butane, propane and ethane will be stored in separate vessels located at the gas plant until they are sold. Gas plants that operate at colder temperatures to remove ethane from the sales gas are known as "deep cut" facilities. The composition of the raw gas, economics and the transmission pipeline’s specifications dictate the type of equipment that is used at a given gas plant. In some parts of the world it is necessary to liquefy the entire sales gas stream so that it can be put into an ocean going tanker. Liquid natural gas (LNG) is created by cooling the gas to about -190 degrees Celcius. Residue Gas: - The gas remaining after all the above processes is called “residue gas”. A small amount of residue gas is consumed as fuel at the gas plant to provide the energy required to operate the facility. The remaining residue gas is called “sales gas” and is delivered into the gas transportation system for use by consumers.

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LIST OF APPENDICES - PRODUCTION OPERATIONS 1. Oil Production Facility

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Module 1.10 Appendix 1 - For full size printing purposes

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