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Gas Gathering, Measurement, and ProcessingAn overview of the upstream, midstream, and downstream segments of our industry

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University of North Texas Institute of Petroleum Accounting

Gas Gathering, Measurement, and Processing

Jim Tallant Exigent Information Solutions, LLC

Littleton, Colorado

Introduction

The oil and gas industry in North America is typically divided into three segments: Upstream, Midstream and Downstream. The Upstream segment of the industry involves finding and producing oil and gas; the Midstream segment involves transporting, processing and marketing oil and gas; and the Downstream segment encompasses refineries for liquid products, and the local distribution company (LDC), petrochemical companies or commercial end users, among others, for natural gas. This paper will discuss the Midstream segment with respect to natural gas.

Midstream infrastructure links supply with demand and connects energy producers with energy consumers. In North America, the Midstream segment includes more than 170,000 miles of pipelines, and the world’s most technologically advanced infrastructure. The sector can include but is not limited to the following:

Gas gathering, treating, processing and fractionation Natural gas pipelines NGL Product pipelines Natural gas and product storage Natural gas and NGL Marketing

The midstream industry has gone through major structural changes over

the years. Today, midstream assets are most often operated as profit centers, and held in many different ownership structures, including integrated midstream companies, midsized specialty midstream companies, and small start-up midstream companies, often using the corporate tax structures of Master Limited Partnerships (MLPs) and Limited Liability Companies (LLCs).

The ‘shale boom,’ which has brought the tremendous success of unconventional oil and gas plays, has encouraged hydrocarbon production in areas that were heretofore considered uneconomic. As these shale plays are driving growth in drilling activity across North America, low gas prices are causing producers to focus on rich gas plays (i.e., high in natural gas liquid (NGL) content). For rich gas production to be profitable, NGLs must

2 Petroluem Accounting and Financial Management

be recovered, processed and transported to market. These new rich gas resource plays are located in areas isolated from existing midstream infrastructure and markets, and are driving demand for new midstream assets and infrastructure.

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Figure 1 U. S. Shale Plays

Demand for Midstream Infrastructure driven by shale and liquids-rich plays Source: Energy Information Administration

4 Petroleum Accounting and Financial Management

History of Midstream

Before 1980 the major oil companies, large independents, interstate pipelines and petrochemical companies owned most midstream assets. Major oil companies built midstream facilities to bring their production to market and to supply their refineries and petrochemical plants. Heavily regulated interstate pipelines not only owned the interstate pipelines, but also owned gas gathering and processing assets which enabled them to expand their rate bases and secure supplies. At the time, energy markets were heavily regulated and midstream assets functioned more as cost centers and less as profit centers. This ‘artificial’ market environment created years of supply and demand imbalances along with the associated pricing distortions. Finally, in 1978, Congress enacted the Natural Gas Policy Act (NGPA), intended to deregulate well head gas prices. The Federal Energy Regulatory Commission (FERC) was charged with implementing the NGPA.

By the 1980s, independent midstream companies serving third parties began to enter the market. Independent gatherers and processors, intrastate pipelines, and NGL logistics companies were expanding, fueled by price deregulation and greater crude oil and natural gas availability. The poor business conditions in the mid-to-late-1980s for the energy industry gave rise to midstream asset sales and consolidation in the early 1990s. Major oil companies and large independents sold their midstream assets as their production declined and they shifted focus to more lucrative offshore and international projects.

In 1992, the most significant change in the gas industry happened when the FERC passed Order No. 636, and Interstate pipelines became transporters instead of merchants. Order No. 636 prohibited interstate pipelines from owning any of the gas in their systems, and effectively took interstate pipelines completely out of the merchant role they had historically held. This created a dilemma – producers were without their purchasers and distribution companies were without their typical city gate seller. Pipelines, who use to schedule their own gas takes, had to develop a business process to fill their pipelines and maintain the operations of their systems while deliveries of gas into their systems were in the control of shippers, their new customers (usually producers and marketers). Tariffs implementing Order No. 636 went into effect in the fall of 1993 and called for shippers to schedule gas through a nomination process and balance their deliveries with downstream redeliveries; whereas in the past, pipeline purchasers bought an entire well’s production, and the producer had to wait for its revenue check to determine volume.

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In the new era, producers have become shippers, and are required to ‘nominate’ transportation quantities before the first day of the month. The nomination is due before the first MCF of gas flowed for the month, and thus the producer / shipper do not know how much a particular well will produce during the month. After the production month, gas is allocated on a proportionate basis, usually based on nominations. Transporters / interstate pipelines deliver the quantities nominated by the producer / shipper at the downstream delivery point. The difference between actual, allocated gas volumes delivered to the pipeline, and downstream volumes redelivered at the delivery point becomes a pipeline imbalance, and is either settled by a ‘cash out’ (payment to the pipeline or producer using a predetermined price) or by volume balancing (the overage / shortage to be made up the next month on the pipeline).

By the mid-1990s, midstream had developed into a profit center in processing, marketing and trading in an unregulated environment, as midstream experienced returns exceeding the regulated cost-based returns of the utilities and interstate pipelines. The attractiveness of the midstream sector combined with a growing economy created robust demand for midstream companies and assets in the mid to late 1990s. Electric utilities, diversified energy companies, and energy marketers were the primary acquirers of midstream companies and assets. Then, in the late 1990s, there was a sudden availability of midstream assets on the market as majors and large diversified energy companies decided to monetize their mature assets with the goal of redeploying proceeds from the sale into higher-return, upstream investments. During this time the midstream industry began to significantly expand. Most majors spun off midstream assets into new entities, which were able to use the Master Limited Partnership (MLP) investment vehicle. MLPs are able to take advantage of a tax structure which enables them to provide investors higher rates of return than those of energy corporations. To provide investors with even better returns, MLPs began to focus on growth, making large acquisitions and raising distributions accordingly.

Modern Era

Gas can theoretically be sold by a producer at any point between the wellhead and the burner tip, but activities beyond the production area are still part of a separate business, the midstream marketing business. Participants in the midstream marketing business aggregate quantities and provide many other services which were historically provided by interstate pipelines when they were merchants.


Today, the midstream industry includes major oil companies, large independent midstream companies, energy merchants, petrochemical companies, and smaller entrepreneurial midstream companies. Some have upstream assets, some are focused strictly on processing, others are more integrated, and many are funded by the MLP investment vehicle. The sector continues to aggressively change, and many small companies are rapidly building midstream assets, holding them for a short period of time, and selling the assets to larger midstream players for significant returns. Other companies and outside investors are taking advantage of this situation by acquiring these midstream assets, while a few industry companies are deciding their midstream holdings are not core to their long-term futures and spinning them off. It is a very exciting time to be in the midstream business!

Overview of Industry:

Transporting natural gas from the wellhead to the end user is a multi-step process and involves infrastructure from the wellhead to interstate pipelines to the local distribution company (LDC). Gas And Oil Gathering, Gas Treating, And Gas Processing. Gas Gathering

Natural gas gathering and processing infrastructure receives raw gas from producers at the wellhead, processes it to meet the specifications of pipeline quality gas, and delivers it into the pipeline grid. The natural gas gathering system begins in the field, with the production of raw natural gas, which is often treated in the field (separation and dehydration), compressed and sent to a processing plant. Gas is usually gathered by several small diameter pipelines which move the gas to larger gathering lines, and in turn to a processing plant. Gathering lines are generally less than eight inches in diameter, usually located in rural producing areas and operate under low pressure. Most states do not regulate these lines. The raw gas stream consists mostly of methane, but also contains other hydrocarbons such as ethane, propane and butane, referred to collectively as Natural Gas Liquids (NGLs). It can also contain carbon dioxide, nitrogen, helium, hydrogen sulphide and water. Natural gas is commonly dehydrated near the point of production or during the gas separation or sweetening process at a gas processing facility. The gas then travels from the production area to a processing plant to remove NGLs and non-hydrocarbon constituents, and is raised to the level of pipeline quality gas. Once the gas has been processed in a gas plant, it is compressed and transported in much larger pipelines known as transmission lines, which can be up to 48 inches or more in

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diameter. These pipelines operate at higher pressures and when they cross state lines, they are regulated by the Federal Energy Regulatory Commission (FERC). The interstate pipelines move the residue gas to market hubs, local distribution companies (LDCs), commercial users, chemical plants, or to underground storage reservoirs. Gas Measurement

The gas must be measured at a myriad of points along the midstream processing chain. The most common meter used to measure gas is the orifice meter. Orifice meters measure the pressure drop across the orifice plate, called the differential pressure. This variable, along with other variables of the flowing gas, are used to determine of volume of gas flow. The components of an orifice meter are a meter tube (meter run), orifice plate, orifice holder, pressure taps, and a recording device (Electronic Flow Computer (EFM) or a chart recorder).


Figure 2 Orifice Meter with an Electronic Flow Computer

Courtesy of COPAS Gas Accounting Manual

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An orifice meter is called an ‘Inferential Meter,’ meaning that characteristics of the gas flow are measured in order to ‘Infer’ the volume of flow. Thus natural gas measurement is perpetually imperfect, since there is always some degree of uncertainty associated with it. Although volume calculations are based on science, we can never know the exact quantity of natural gas flowing through a meter. Processing

After the raw gas has been produced and gathered, it must be processed to remove liquid hydrocarbons and impurities. Gas processing involves two main operations: 1) extraction of NGLs from the gas stream; and 2) fractionation of NGLs into their separate ‘Purity’ forms. Additional processing may be required to treat and condition the natural gas and the NGLs to remove CO2, H2S, nitrogen, etc. Once the NGLs have been removed from the gas stream, they become feedstock or end products in the distribution chain, and include ethane (C2), propane (C3), butane (C4) and pentanes (C5). For the most part, NGLs are generally used by refineries, petrochemical plants, the agriculture industry, and NGL distributors.

Processing a raw gas stream for delivery to interstate transmission pipelines can involve a range of technologies, depending on the chemical content of the gas stream, location of the hydrocarbons and other factors. In some cases, dehydration is sufficient to move the gas down the pipeline, while in other cases, the gas must undergo significant processing. The most common treatment of natural gas is removal of excess water vapor, which is necessary to prevent formation of hydrates and freezing in interstate pipeline transmission systems. The gas processing industry uses a variety of processes to treat natural gas and extract natural gas liquids from the gas stream. The two most important extraction processes are the absorption and cryogenic expander processes. Together, these processes account for an estimated 90% of natural gas processing. If the raw gas stream includes hydrogen sulfide or carbon dioxide, the gas plant must treat both the natural gas and the NGLs to remove these contaminants. This process is called “sweetening” the gas. There are many methods that can be used, most of which rely on chemical reactions, physical solution, or adsorption. The most common chemical processes are based on contact with amine solutions. These solutions react with the acid gas compounds to form other compounds which can be safely removed. Adsorption processes involve the removal of unwanted components by passing the gas or liquid through a bed of solid material that has been designed or treated to selectively extract carbon dioxide, hydrogen sulfide, or other contaminants. The sour gas


effluent from a sweetening unit must be further treated, either for disposal or for recovery of sulfur.

Once the gas has been sweetened, most gas processing facilities are designed to recover NGLs and then deliver pipeline quality residue gas to interstate pipelines at the tailgate of the plant. This involves three main processes: 1) removal of impurities; 2) removal of water; and 3) separation of NGLs from the gas stream.

The typical gas plant process includes dehydration, mechanical refrigeration, turbo-cryogenic expansion, recompression and distillation columns designed to recover and remove all NGLs from the raw gas stream. Most plants will process the gas such that all NGL products from propane and heavier (C3+) will be separated into a pressurized NGL product stream (typically known as Y Grade) which can be transported via pipeline, truck or rail to fractionation facilities. By separating the NGLs from the raw gas stream, the plant operator is able to deliver Y Grade to another facility for further processing, and deliver pipeline quality gas to the interstate pipelines at the tailgate of the plant. Usually, the process uses mechanical refrigeration to lower the temperature of the gas to approximately 30 degrees Fahrenheit, then uses a turbo-cryogenic process to expand the gas from high pressure to low pressure. This cools the gas to about minus 125 degrees Fahrenheit, thus causing all the propane and heavier components to ‘fall’ out of the gas stream as NGLs. At the end of the process, the gas is recompressed into the interstate pipeline for transport as pipeline quality gas. Depending on gas composition, the gas processing plant may also include additional treating to remove carbon dioxide, helium, or nitrogen.

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Figure 3 Natural Gas Processing Schematic1

Source: Coalbed Methane: Recovery & Utilization in North Western San Juan, Colorado 1 http://www.ems.psu.edu/~elsworth/courses/egee580/2010/Final%20Reports/CBM_Report.pdf


Fractionation

A Fractionation facility will take the ‘Y Grade’ as feedstock, and ‘fractionate’ it into separate products. NGLs are fractionated by boiling the lighter products from the heavier products, using a sequence of towers in which temperatures and pressures are controlled such that that the boiling point will be reached by only one NGL in each tower. Fractionating towers are usually named for the overhead or product which flows out the top of the column. For example, the product flowing out of the top of a deethanizer column is ethane. The deethanizer is the first step in the fractionating process, where only the ethane is allowed to boil and escape through the top of the tower and the propane and heavier components fall to the bottom of the tower and are sent to the next tower, the debutanizer. The next step is to process propane, which has the next-highest boiling point, and is heated and boiled out the top of the column. The next step in the fractionating sequence is to separate the butane, then the pentane and heavier components. Once the propane and heavier components come out the top of the tower as a gas, they are cooled so that they condense back to liquid form and are piped to inventory tanks before being transported to market. The NGLs involved in this process are:

Ethane – a hydrocarbon with a molecular structure of two carbon atoms (C2), and is produced primarily from natural gas processing plants. It is used in the petrochemical industry to make polyethylene, a building block for many plastics. The economics of ethane extraction are driven by its value as a petrochemical feedstock versus the value of its heating content, if left in the gas stream. The process of leaving the ethane in the gas stream is called ‘ethane rejection.’

Propane – a hydrocarbon with a molecular structure of three

carbon atoms (C3). The primary end-use applications for propane are as a home heating fuel and as a vehicle fuel. The other main use for propane is petrochemical feedstock in the manufacture of polyethylene and other chemicals. Since propane supplies from gas plants are extracted in conjunction with ethane, it is often transported as an ethane/propane mix.

Butane – a hydrocarbon with a molecular structure of four

carbon atoms (C4). Its principal uses are to provide needed volatility for motor gasoline. Another main use for butane is to isomerize it to produce iso-butane, which is used by refineries for the production of alkylate, a vital ingredient of

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high-octane motor gasoline. Butane is also used either alone or in mixtures with propane; as a feedstock for the manufacture of ethylene and butadiene, a key ingredient of synthetic rubber.

Iso-butane – the chemical isomer of butane, is fractionated

from “field grade” butanes or derived by isomerization of normal butane and produced as a separate product, principally for the manufacture of alkylate.

Natural gasoline – also known as pentane plus, is a mixture of

light hydrocarbons with molecular structures of five or more carbon atoms (C5+). It is primarily used by refineries in gasoline blending, but has a lower economic value than gasoline due to its lower octane value and higher vapor pressure. The use of pentanes plus in producing gasoline has also been affected by the increased use of ethanol. As higher quantities of ethanol are blended into gasoline, lower quantities of pentanes plus are needed. It is also used as a chemical feedstock and is increasingly in demand as a diluent for the rising production of heavy oil in Canada.


Figure 4 Gas Processing Plants in the U.S.

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Gas Processing Accounting We have thus far discussed how gas is gathered, measured, processed, and fractionated into usable products and residue

gas. Next, we will cover discuss how the revenue accountant needs to ‘allocate’ and ‘settle’ with the producers for their gas which was transferred to the gatherer / processor. The diagram below depicts the process under discussion:

Figure 5 Flowchart of Midstream Operations and Flows


While the gas gatherer / processor took possession of the hydrocarbons at the wellhead (or a similar custody transfer point), that same gatherer / processor may not necessarily have taken title to the hydrocarbons at the custody transfer point. All of the arrangements between the producer and gatherer / processor from this point forward are governed by the gas purchase agreement, gas gathering or processing agreement, or a similar legal instrument. The gas accountant must read and be familiar with these legal instruments to provide a fair and equitable settlement and payment to the producer, or invoice to the producer for services rendered. The gas accountant must process the gas gathering, allocation and settlement accounting information for settlement and payment to producers in accordance with the Gas Processors of America (GPA) standards for measurement, as well as COPAS and petroleum accounting requirements for revenue accounting. Allocation Concepts and Terminology

To discuss gas plant or gas processing allocation methodology, several terms must be defined:

Attribute – a characteristic of a measurement point. For example, a wellhead meter has a metered volume, stated in MCF, as one of its attributes. The Btu factor (heating value) from a sample taken at the same wellhead meter is also an attribute of that measurement point.

Plant Attributes – a characteristic of a measurement point

within the ‘Plant Fence,’ and typically includes such items as residue sales MMBtu and production gallons by component.

Derived Attributes – a characteristic that can be calculated

from other attributes to become an attribute for the measurement point. For example theoretical wellhead gallons by component, calculated as the product of wellhead MCF times gallons per thousand cubic feet (GPM) by component becomes an attribute of that measurement point.

Measurement Point – defined as any distinct point along the

flow of gas where an attribute or attributes can be measured by some means. A measurement point would include a mechanical meter, an electronic flow measurement (EFM) meter or a turbine meter. Both volumetric data and

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compositional data (gas analysis) can be measured at these types of measurement points.

Primary Gathering System -- the first gathering system or

allocation group to which a meter or measurement point is connected or related. Primary gathering systems are commonly referred to as field gathering or satellite gathering systems.

Secondary Gathering System -- the gathering system or

allocation group to which a primary gathering system is connected or related. Secondary gathering systems are commonly referred to as main lines, trunk lines, or inlet streams. At least one, but usually more than one, primary gathering system is associated with a secondary gathering system.

Settlement meter -- any meter on which an allocation,

settlement and payment to a producer is made. A settlement meter is a meter to which physical products are allocated and dollar amounts are paid to one or more producers.

Information meter – any meter which has its attributes

allocated to settlement meters or which provide management information. A downstream check meter, a fuel meter or a plant inlet meter are examples of Information meters.

The gas plant Allocation is designed to achieve two primary objectives: 1) physical molecular allocation, and 2) contract settlement. The purpose of the Physical Allocation objective is to achieve a fair allocation of gas plant attributes based upon the physical flow of gas and the physical attributes of the measurement points. In actuality the design of the allocation will follow the reverse flow of the gas, that is, the allocation starts at the plant’s tailgate and works backwards to the wellhead (more on this below).

The Contract Settlement objective is to pay, or settle, with each producer in accordance with the contract terms and obligations for each of the custody transfer measurement points. Satisfying the objective of a Physical Allocation should be independent of the Contract Settlement objective. A ‘fair’ allocation of gas plant residue and liquids can only be accomplished if the allocation is based upon the physical flow of gas, regardless of any of the contract terms and obligations. The logical extension of this statement is that any contract term or obligation that does


not follow the Physical Allocation becomes a Contract Settlement adjustment. In short, the objective of a Physical Allocation is independent of the Contract Settlement objective, yet the Physical Allocation is the starting point for calculating the adjustments necessary to satisfy the Contract Settlement objective. If the Physical Allocation objective is not met, then it is virtually impossible for the Contract Settlement objective to be met.

The concepts above are best illustrated through a simple example. Assume that gas from two wells, operated by different producers, flows through individual wellhead meters and is compressed before flowing to the inlet of a gas plant for processing. Each well flows the same volume of gas and the compressor burns 10% of each of the wellhead volumes as fuel. The first producer has a contract that provides for a fixed field fuel rate of 6% of the producer’s wellhead volume. If this contract term is improperly reflected in the physical allocation, then the second producer, who does not have a contract with a fixed field fuel rate, will receive an unfair allocation of more than 10% of the second producer’s wellhead volume. In effect, the total compressor fuel has been allocated, but the contract terms of the first producer have affected the allocation to the second producer. If the Physical Allocation objective had been followed in the allocation, then both producers would have shared in the actual compressor fuel equally. In other words both producers would have had 10% of their wellhead volume allocated as compressor fuel (remember, the Physical Allocation objective is independent of the Contract Settlement objective). Subsequent to the physical allocation, the first producer would get an adjustment equal to 4% of the wellhead volume, calculated as the 10% actual fuel rate minus the 6% contract fixed fuel rate (the Physical Allocation is the starting point for calculating the Contract Settlement adjustments).

The example above also brings up another point about the Physical Allocation objective. If an ‘unfair’ allocation occurs at the beginning of the gas flow, then all subsequent allocations will also be unfair. In the example above, if theoretical gallons were calculated on the basis of the wellhead volume reduced for an unfair allocation of compressor fuel and theoretical gallons were used to allocate production gallons, then the first producer would receive an allocation of more gallons than entitled to and the second producer, without the fixed field fuel contract clause, would receive an allocation of fewer gallons than entitled to. Subsequent allocations of plant fuel and residue gas would also be unfair to the second producer.

As indicated previously, the purpose of the Physical Allocation objective is to achieve a fair allocation of gas plant attributes based upon the

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physical flow of gas and the physical attributes of the measurement points. In actuality the design of the allocation will follow the reverse of the gas flow. In other words, the allocation should start at the tailgate of the plant and work backwards to the wellhead, as follows:

Figure 6 Allocation Flow vs. Gas Flow from Wellhead to Gas Plant

Allocation Flow is Opposite of Gas Flow from Well to Gas Plant

The term ‘fair allocation’ is used in the Physical Allocation objective instead of ‘accurate allocation.’ This is because the measurement of gas is not precise, as noted above. For example, a volume chart from a mechanical meter integrated by different individuals on different integration machines will typically result in different measured volumes of gas. Even the re-integration of a chart by the same person on the same machine will typically result in different measured volumes. Although plant operators are installing electronic flow meters (EFMs), it has not been proven that EFM’s are any more precise than integrated charts from mechanical meters. The accuracy of an allocation is also affected by the composition of a measurement point. In most cases, a sample of a stream of gas at the wellhead is taken and analyzed every six months, called a gas analysis. The composition of the gas stream is supposed to be a representative sample of the gas stream and is used in the allocation scheme until replaced by a later representative sample. The actual composition of a gas stream is constantly changing, although the change is typically only slight over a short period of time. Continuous samplers may achieve greater precision than periodic representative samples, but the primary benefit of continuous samplers is the real-time data available to a plant operator. Furthermore, continuous samplers are quite expensive and therefore only used in applications with large flows of gas. As a result of the inaccuracies inherent in the measurement and composition of gas streams, it is not possible to achieve an absolutely precise allocation.

Wellhead Tailgate

Gas Flow

Allocation Flow


Allocation Methodology

The first step a gas plant allocation is to allocate plant attributes (residue MMBtu and production gallons) to each inlet stream based upon the attributes (volume and composition) of each of the Measurement Points representing the inlet streams. For example, if a Plant has four inlet streams

a) NGL Gallons are allocated to the four inlet streams on the basis of theoretical content gallons. Theoretical content gallons are calculated as measured MCF volume at the Measurement Point times the weighted average gallons per MCF (GPM) by component for samples of gas taken and analyzed at the Measurement Point during the month. b) Residue Gas is allocated to the four inlet streams on the

basis of a calculation of theoretical residue. Theoretical residue is calculated as follows:

i) Measured volume at the inlet meter, minus ii) Allocated plant fuel, minus iii) Allocated NGL gallon equivalents (commonly

referred to as "shrink")

The purpose of the first level of allocation is to isolate plant gains or losses by inlet stream. This allocation level allows for the proper allocation of other plant attributes to each of the inlet streams. For example, if inlet compression exists only on one of the inlet streams, then all of the inlet compression fuel can be allocated to the one inlet stream that requires compression to enter the plant.

The second level of allocation is to allocate the attributes (residue mmbtu and production gallons) previously allocated to inlet streams to the various Secondary Gathering Systems associated with each inlet stream. The purpose of the second level of allocation is to isolate system gains or losses, product attributes and field compression fuel by those settlement points that actually contributed the hydrocarbons, added to the gain or loss, and consumed the fuel.

Plant Attributes which have been allocated to Secondary Gathering

Systems are then allocated to each of the related Primary Gathering Systems. The use of common delivery points in an allocation isolates any gain or loss and compression fuel between the settlement points behind the common delivery point to only those settlement points. For example, if one

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field gathering system has a 10% loss between the settlement points and the common delivery point, then only those settlement points behind the common delivery point would be affected by the 10% loss. The allocation to a field gathering system will be based upon either: the attributes (volume and composition) of a common delivery point for the field gathering system, or the sum of the attributes (volume and composition) of settlement meters associated with the field gathering system. The choice is dependent upon whether or not measurement exists for a common delivery point into the inlet stream.

a) Most Secondary Gathering Systems have at least two or

more Primary Gathering Systems (though this is not always the case). All of the measurement points associated with each inlet stream are separated into groups of measured locations when a physical meter exists.

b) Allocation percentages to the metered Primary Gathering Systems are calculated on the basis of the relationship of the measured Primary Gathering System attributes to the downstream inlet Measurement Point attributes.

The third level of the allocation is to allocate the attributes (residue

mmbtu and production gallons) previously allocated to the field gathering systems to each of the settlement points associated with the field gathering system on the basis of the attributes (volume and composition) of each settlement point. Plant Attributes which have been allocated to each of the Primary Gathering Systems are allocated to the Measurement Points –either Information meters or Settlement meters – related to each Primary Gathering System.

Plant Attributes which have been allocated to each Measurement Point

can then be further allocated to each related Settlement Point on the basis of allocation percentages as follows:

a) Property Allocation Percentage - allocation percentages to

multiple properties behind a common Measurement Point are determined based upon well test data (for example, a common delivery point (CDP) may have several wells behind it).

b) Contract Allocation Percentage - allocation percentages to multiple contracts associated with a common property are determined based upon ownership percentage.


Residue gas allocated to Settlement Points is reduced by an allocable share of residue gas returned to the field for lease use. Plant Attributes which have been allocated to Settlement Points are then priced out in accordance with contract terms.

Needless to say, this type of ‘fair’ allocation requires a tremendous amount of data and a tremendous amount of number crunching. Over the years, some allocation systems allocate plant attributes (residue mmbtu and production gallons) to each meter and contract on the basis of aggregate attributes (volume and composition) for the "pay meter" or settlement points associated with each contract. Sometimes, this is known as a “Super Plant” allocation. Here, plant gains or losses, field fuel, and gathering system gains or losses are shared equally by all settlement points, regardless of the physical flow of gas. This means that if your gas is 1/2 mile from the gas plant, and is feeding directly into the plant trunkline inlet, you will be allocated the same amount of field fuel, loss and unaccounted for gas as a well which is 50 miles from the plant, and has three levels of field gathering systems and associated compression to pass through. Also, plant attributes that need to be specifically allocated to a separate source of gas are being shared equally by all settlement points. As mentioned, field compression fuel is being shared equally by all settlement points, even if some settlement points are not physically compressed before entering the plant. Plant gains or losses and gathering system gains or losses are being shared equally by all settlement points.

Gas Contracts

There are numerous contracts utilized in the midstream industry. Some of the most common are:

Gas gathering contracts, Gas processing contracts, NGL fractionation contracts, Product purchase contracts, and

These agreements set forth obligations, pricing, and risks between the producer, processor, transporter, buyer and seller. Gas Gathering Contracts

Gas gathering contracts are usually fixed term, fee-based agreements. In this way, the midstream gathering system operator has little risk or exposure to commodity price fluctuations. The risk is further abated

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because the producer is usually not under an obligation to deliver a minimum quantity of gas to the gatherer. The gatherer usually agrees to accept product at the wellhead, and re-deliver the product back to the producer at a certain point. In most cases, the gas gathering agreement is part of a processing agreement, so that the redelivery point is the tailgate of the gas plant. Gas Processing Contracts

Natural gas is typically processed under several different contracts: Fee Based Contracts

In fixed-fee contracts, the producer pays the plant a flat fee based upon the volume of gas or NGLs that flow through their systems. In these types of contracts, the producer carries all the risk of commodity exposure since the processor doesn’t take any of the products as compensation for processing the gas. These contracts usually have penalties for high field pressure, high levels of impurities in the product and other attributes which have negative effects on the processor. Percent-of-Proceeds Contracts

The midstream operator gathers and processes gas on behalf of producers. The processor sells the resulting residue gas and NGLs at market prices and remits to the producer an agreed upon percentage of the proceeds based on a contractual. For example, contract would pay the producer 80% of the proceeds from the sale of natural gas and NGLs, and the remaining 20% would be retained by the processing plant operator as a fee for processing the gas. Both parties share the processing margin risk in POP contracts because the total revenues to be divided are dependent on the price of products sold. In a POP contract, most processors try to negotiate economic loss provisions to minimize margin exposure, while producers try to gain flexibility by negotiating the right to bypass processing and rejecting ethane from the NGL stream.


Percent-of-Index Contracts.

Here, the gas processor purchases the gas at a percentage discount to a specified index price or a specified index price less a fixed amount (often called trans and frac fee (T&F)). The processor gathers, processes and delivers the gas to pipelines where the processor resells the natural gas at the index price. Under the percentage discount, gross margin increases when the price of natural gas increases and decreases when the price of natural gas decreases. Keep-Whole Contracts

Keep-whole contracts require the processor to process the gas, and then return enough processed gas to the producer to equal the total BTUs of raw gas delivered at the plant’s inlet. The processor bears the risk of the processing margin, and the producer is allowed to monetize gas without incurring the expense of processing the gas. Fractionation Contracts.

As discussed above, fractionation plants separate raw, mixed NGLs (Y-Grade) into ‘purity’ ethane, propane, iso-butane, normal butane, and natural gasoline. Fractionation agreements are usually fee-based, with adjustments for fuel costs.

As the midstream segment continues to evolve and competition continues to increase, midstream contracts are becoming quite complex; particularly in mature areas where substantial midstream infrastructure exists. Conversely, in the newer production areas, the ‘unconventional’ plays, midstream infrastructure is under great demand, and midstream operators are able achieve high rates of return.

Transportation

Interstate Natural Gas Pipelines

Once the products have been fractionated, they are transported to market. For the residue gas, Interstate Transmission pipelines receive gas from the midstream facilities and deliver gas to end users, local distribution companies, or to other transmission pipelines for further transportation. The Federal Energy Regulatory Commission (“FERC”) is charged with approving the construction and operation of interstate natural gas pipeline facilities which operate as common carriers. This business model results in cash flow stability for the pipelines, as these companies receive a fee for

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handling a producer’s or marketer’s product on their pipeline system. The efficient and effective movement of natural gas from producing regions to consuming regions requires an elaborate transportation system. In many instances, natural gas produced from a particular well will have to travel a great distance to reach its point of use. The transportation system for natural gas consists of a complex network of pipelines, designed to quickly and efficiently transport natural gas from its origin, to areas of high natural gas demand. The interstate pipeline network is a complicated system built to efficiently move the gas to the delivery point. The overall infrastructure demands huge investments in terms of materials, labor, and equipment. Interstate pipelines measure anywhere from 6 to 48 inches in diameter, though usually mainline pipelines are between 16 and 48 inches in diameter. The main gas transmission lines are wide-diameter pipelines (20-42 inches), operating over long distances. Interstate pipelines in North America extend to distances as long as 2000 miles, transporting as much as 12,000 MMcf/d (million cubic feet per day) of gas to states throughout the country. To maintain the flow of gas, compressor stations are installed at intervals of approximately 40-100 miles along the pipeline.

As discussed above, the pipeline companies no longer own the commodities, virtually eliminating commodity price exposure and smoothing out its cash flows. Natural gas pipelines receive stable income from pipeline capacity reservations, independent of actual throughput, largely via “ship-or-pay” contracts. Other product pipeline revenues depend on throughput, but are protected by inflation escalators that act as a hedge. Product Pipelines

Some NGL pipelines carry mixed NGLs to fractionation facilities, while other NGL pipelines transport purity products, from fractionators or storage facilities to end users. In the high growth environment of today, the availability of NGL pipeline capacity is limited; therefore truck and rail are viable options. For example, the Bakken Shale play in North Dakota is an area that faces NGL takeaway constraints via pipeline, so producers in this region extensively use truck and rail services. NGL production is expected to continue to increase in the Bakken, and it projected to reach levels high enough to justify the capital investment required to build additional NGL pipelines.

Conclusion

In conclusion, over the years, the midstream industry has gone through major structural changes, and today is no different. The latest structural change, the ‘shale boom,’ has made many new production areas feasible,


which in turn has created high demand for midstream infrastructure to gather, process and transport the gas and natural gas liquids to market. Thus, the shale plays are driving significant investment in new midstream assets, primarily in the areas of 'rich gas' production. As a result, the midstream industry is booming, and represents one of the bright spots in the North American economy. With the price per MMBtu hovering around $3 in North America and $12 in Europe, this represents a significant advantage not only for the North American consumer, but also for North American manufacturing to compete in the world market with a significant competitive advantage over other parts of the world. There also exists the potential to export LNG to other areas where the price of natural gas is abnormally high. Many are saying that the U. S. may be able to become energy independent in the next few decades. To reach these goals, midstream companies are working closely with producers to meet this demand and provide options for energy, to reach the market. Along with this cooperation, it is hoped that U.S. policy will follow along these lines and allow these resources to be developed in a productive and environmentally responsible manner.

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Gas - exigent-info.com · Gas Gathering, Measurement, and Processing An overview of the upstream, midstream, and downstream segments of our industry Exigent-Info.com eXigent Information