Unconventional gas presents unique challenges to natural gas gathering and processing companies. Many of these plays are in areas where there is little or no gas-handling infrastructure, thereby requiring heavy grassroots investment. High initial production rates, extreme decline rates, unpredictable well interference effects and unusual gas composition require that special attention be paid to the design of the pipeline, compression, measurement, dehydration, sweetening, gathering and processing systems associated with these plays.

The success or failure of these investments will largely determine the success or failure of these companies in future years. A proper understanding of the challenges and risks of designing surface facilities for unconventional plays is essential for maximizing profitability.

Most unconventional gas fields are in areas in which there has been little or no gas production or development, or in areas where existing facilities sized for conventional gas production are greatly undersized for the characteristically high unconventional gas production. Therefore, design of the gathering, compression, measurement, treating, dehydration, sweetening and processing facilities are typically grassroots projects and extremely capital intensive.

These systems will likely have an operational life of 20 to 80 years. In order to achieve the greatest cash flows from these systems, they must be designed to be flexible, modular and uniform and utilize the best of modern control technology. These traits will allow the systems to remain profitable during times of changing production rates, well locations, product compositions and commodity pricing.

A natural gas gathering system typically follows one of three main styles in its initial development: linear, nodal or circular. The main factors in determining which style to use are desired wellhead pressures, well spacing pattern and gas composition. In actual practice, gathering systems often evolve into a combination of two or three of these design types.

The selected style of the gathering system will be dictated by many diverse requirements and conditions. These can include geographic considerations, environmental regulations, field development plans, legal and contractual requirements and any number of special conditions. The selected style may not remain constant throughout the field’s life, either. Flexibility built into the initial designs reduces the capital expenditure required later in the life of the field.

These problems can be analyzed using gathering system software such as WinFlow, F.A.S.T. Piper and similar programs. When combined with a well-drilling schedule, pipe sizes can be reviewed for various stages of a field’s development. The results of these designs will provide the best compromise in pipe diameter and compression costs.

The accompanying tables present current, approximate costs to lay one mile of pipeline of different diameters. These costs assume the pipelines will be laid across flat, easily trenched farmland.

Compression choices

The major types of compression used in gas gathering systems are screw, reciprocating and centrifugal. Each type has its specific application. The choice of which type of compressor to use depends upon the suction pressure, discharge pressure and production rate of the application.

Screw compressors are the most economical form of compression for applications that require low suction pressures and low to moderate flow rates. The most common form of compression found in gas gathering systems is reciprocating compression, which can be built in either single or multiple stage configurations. This type of compression can handle a wide variety of pressure and flow-rate conditions.

The third type of compression utilized in gas gathering applications is centrifugal compression. Centrifugal compressors are best used for applications with stable large gas flow rates and low to moderate pressure boost.

There are several different types of prime movers used to power compression on midstream systems. The most common types are gas engines, electrical motors, propane engines and diesel engines. The main drivers for the selection of prime movers are the richness of the gas stream and contaminants in that stream, availability of electricity in the local area, environmental permitting issues regarding a facility and the construction schedule.

Spark-ignited natural gas engines are the most common form of prime mover used to power compression. These engines have the advantages of being readily available in a wide range of sizes, possessing the ability to turn down effectively as production decreases to optimize fuel usage, and the gas production can normally be used to power the engine thereby reducing fuel hauling or infrastructure expenses. The disadvantages of this type of engine are environmental permitting requirements associated with it and its high operating expenses.

Engine emission permitting requirements have been getting stricter for the past several decades, and this trend is expected to continue in the future. In many areas it can take between six to eight months to permit a natural gas engine. Once the unit is operational it may need to be tested on a regular schedule to ensure the unit is operating per its permitted emission limits. This time delay for installation of compression can be problematic in an unconventional gas play where production rates can vary widely from well to well. Additionally, in play areas where the richness of the gas exceeds approximately 1,200 Btu per cubic foot, it may be difficult to find gas engines that are capable of using the produced gas as fuel.

The preferred solution for avoiding environmental permitting issues regarding compression is to use electric motors. Electrical motors have the advantage of being able to be installed without a rigorous permitting process, have better run times and provide lower operating costs than gas engines.

These significant advantages are offset by some significant disadvantages. In many areas where unconventional gas is being developed, there is not sufficient electrical power infrastructure. Additionally, electrical motors have the disadvantage that they do not turn down well compared to gas engines, and electrical expenses to run the motors in a declining field may be prohibitive.

A third type of prime mover that could be used is the spark-ignition engine. The advantages of these engines are that they are able to operate in areas with rich gas and no electrical infrastructure, are available in a wide range of horsepower and are able to turn down effectively as production decreases. The disadvantage of these types of engines is the expense of the fuel and the logistics of the shipping and storage of the fuel to compressor locations.

Gas treatment

Unconventional gas plays differ little from conventional gas plays in technologies to remove water from a gas stream to meet sales gas specifications. However, the contaminants found in unconventional gas do present difficulties for the typical processes of water removal such as triethylene glycol (TEG) units, molecular sieve dehydration systems and ethylene glycol injection systems. The choice of which system to utilize depends on either the method used for processing the gas or the gas sales specification for water of the transmission pipeline.

The main process used to remove water in unconventional gas plays is TEG. If the unconventional gas is being processed for natural gas liquid (NGL) removal then other dehydration processes must be used. If the gas is being dehydrated by a refrigeration plant or Joule- Thompson (JT) cryogenic plant below its dew point, either methanol injection or ethylene glycol injection is used to supplement TEG unit and prevent freezing problems in the liquid-removal plant. If the gas is being cryogenically treated to remove NGL, a molecular-sieve plant is used to dehydrate the gas to levels that will allow cryogenic processing without freezing.

Almost all unconventional gas will require some sort of NGL extraction process. The common NGL extraction processes include JT plants, medium-temperature refrigeration plants, low-temperature refrigeration plants and turbo expander-based cryogenic plants.

Gas processing options

If the primary requirement for processing a natural gas stream is to meet a certain hydrocarbon dew point specification, the processes most likely chosen are either a JT expansion plant or a medium-temperature refrigeration plant. A JT plant utilizes the cooling achieved via a pressure drop across a control valve to extract NGLs from a natural gas stream. These types of units are most commonly found on well locations for wells flowing less than 10 million cubic feet (MMcf) per day and for relatively low-Btu gas.

The primary advantage to these units is that they are inexpensive to purchase and install, and they are simple to operate. The disadvantages are their liquid-extraction efficiencies are low, and their cost of operation could be quite high if compression is needed to increase the pressure of the gas either prior to or past the plant.

Medium-temperature refrigeration units are typically used if the production rates are greater than 10 MMcf per day or if the gas is very rich in hydrocarbons. These units are designed to chill the gas to approximately 0°F with very little pressure drop using a water/Freon or water/propane refrigeration scheme. These units are often equipped with electrical motor-driven refrigeration compression to save weight and simplify operations. Hydrocarbon dew points of 10°F to 40°F can be achieved with these processes, and both units are available typically on short notice.

If maximizing the economics from extraction of NGLs is the primary driver for the installation of a processing facility, then either a low-temperature refrigeration unit or a turbo-expander plant will be installed. The choice between the two processing technologies depends on the composition of the gas and the local infrastructure.

Most low-temperature refrigeration units use propane for the refrigeration medium. These units are less available than the medium-temperature units and may need to be custom designed and built for a specific application. These units can typically provide hydrocarbon dew points of -20°F to -40°F. Lead times for such units can be four to six months. The advantage of this type of facility is its ease of operations and low-fuel consumption due to the minor pressure drop required by the process. A significant disadvantage of these units is they are not as efficient at recovering ethane and propane as a turbo-expander facility. A turbo-expander facility utilizes an isentropic expansion of the gas to reduce the temperature of the gas to between -130°F and -160°F. This allows an expanderbased plant to recover the majority of ethane within a gas stream. However, the expansion does mean that additional compression is usually required to meet sales gas transmission-line pressure.

Ethane extraction

The choice between plant processes often takes into consideration whether there is an ethane pipeline available in the vicinity. In the Barnett and Eagle Ford shales and the Piceance basin unconventional gas plays, turbo-expander plants were installed to be able to extract ethane and maximize the economics of the plant. However in the Bakken play, mechanical refrigeration plants have been installed despite the richness of the gas due to the lack of a market for ethane in the region.

Numerous projects are being contemplated in the Marcellus to bring an ethane outlet to the region so that cryogenic plants can be installed to maximize the profitability of those facilities.

Engineers and executives need to follow a disciplined approach to the design and construction of their assets and contracts in order to maximize the returns from the economic investments made in unconventional gas plays. The following concepts should be considered when developing in grassroots projects for these plays:

  1. Modularization of designs
  2. Standardization of equipment
  3. Design flexibility
  4. Preventative maintenance programs
  5. Leasing of equipment
  6. Utilization of technology to minimize costs and maximize profitability
  7. Mitigating risks via contracts

Midstream systems have traditionally been designed to operate at or near capacity for years at a time. This was possible due to the shallow decline rates on conventional wells, expansion of local producing fields and expanding into adjacent fields. This situation was economically very beneficial to midstream companies since high utilization rates of their equipment maximized the rates of return for the facilities involved.

Unfortunately, unconventional gas plays are different and the economics risks are much greater. Due to high initial production and decline rates in unconventional gas wells, the production rate through the facilities can vary greatly especially once drilling in an area is suspended. In order to maximize the rate of return for these facilities a modular design approach must be used.

A modular approach allows companies to increase or decrease their capacity in an area in incremental phases. Instead of trying to capture economies of scale with larger equipment and facilities as was done in conventional field development, numerous smaller equipment packages or trains should be used to be able to maximize turndown efficiency. A good rule of thumb to use in unconventional gas designs is to rate the individual train at between one-fifth and one-seventh of the total designed throughput for the facility.

The fixed assets of the facility and the layout of the facility should also be designed to accommodate the addition or removal of equipment from that facility in an orderly fashion. Aspects of facility design that makes this possible are the sizing and valve configuration of the header system, proper sizing of pipe racks, having adequate equipment spacing to be able to move equipment easily, strategic location of power lines and junction boxes and additional tags in facility controls.

Standardized design advantages

A key component of making the modular facility design functional and economic is that the individual pieces of equipment must be standardized to as high a degree as is reasonably possible. The more similar compression packages, amine sweetening systems and NGL processing plants are to one another, the easier it is to add or remove capacity as necessary and to optimize operations at the facility level.

Production, compression, treating and processing equipment has an operating life typically between 20 and 60 years. The typical life of an application for this equipment is between two and 10 years. A company can save significant capital over its life if it adopts a fleet-type mentality toward its equipment. The more a company can redistribute its existing assets to serve new growth areas, the less capital intensive its budgets and the more efficient its operations.

A great deal of fuel, chemical, electrical and maintenance expenses have been wasted over the years in the industry due to operation of equipment that was oversized for its application. Additionally, operating expenses will be minimized through reducing both spare parts inventory and training expenses.

sThe development of unconventional gas plays are difficult to predict. The compositions of the gas, the wellhead pressures required, and the level of contaminants all can change quickly as a drilling program moves into new areas of the play. The Barnett, the Eagle Ford and the Marcellus are all examples of plays whose compositions vary drastically with drilling locations.

The system designer should ensure that the equipment purchased can accommodate these potential changes and that flexibility is built into their design. This flexibility not only is beneficial for the initial application for this equipment but it also helps insure that this equipment is suitable for redeployment in other future applications. The cost of designing extra flexibility is normally not particularly onerous when the equipment is first purchased.

The modularization of facilities, standardization of equipment and purposeful design of flexible equipment are practices that try to mitigate the potential economic hazard of having idle equipment that generates no revenue. These practices are generally best implemented by large companies that operate in multiple basins and plays and that can move equipment from one operating area to another as needed.

For smaller companies whose asset base does not readily facilitate this strategy or for specialized circumstances, the use of lease equipment can avoid poor equipment investments. Most of the major pieces of midstream equipment such as compression, processing plants and amine units are available for lease from numerous vendors. These vendors can provide not only equipment but operational services as well. In general, if a company cannot foresee use of the equipment for longer than four years, it is economically best to lease the equipment from a vendor.

In years when prices are low, margins are also low, and companies have the lowest operating costs are the ones that survive to enjoy the next upswing in prices. A key to maintaining low operating costs is the proper application of technology in our business.

The best engineering and operations work cannot mitigate all of the risks faced by midstream companies in unconventional gas plays. Some assets cannot be designed in a modular fashion economically and cannot be moved to another area if production is not realized. The only way to minimize the risks with these types of assets is contractually.

The costs for laying pipelines, site preparation, foundation work and electrical infrastructure installation can only be mitigated for a midstream company via the contractual agreement with a production company. The temptation for midstream companies is to attempt to have all capital cost risk-mitigated via aid-in-construction, throughput guarantees or financial indemnities. However, this strategy often encourages production companies to build their own midstream infrastructure, which can create a competitor.

The companies that best understand the risks involved with grassroots plays can effectively mitigate those risks through engineering design, and that can craft the more workable contract schemes will be those companies that are able to most greatly profit from unconventional gas developments.

The development of unconventional gas and oil plays has transformed our industry over the past decade, and this transformation will only continue in future years. Companies that best understand the characteristics of these plays understand how to design infrastructure and equipment to mitigate the risks associated with these plays and that can craft contracts with producers that can mitigate the unavoidable capital risks will succeed in this new environment.

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