Natural gas compressors are a necessary part of almost every oilfield operation. For natural gas wells, compression is used to boost wellhead flowing pressure to pipeline intake pressure. In addition, compressor equipment is part of a system of separators, de-sanders, heaters (or coolers), dehydrators, expanders and/or sulfur recovery stages that treat the gas and make it suitable for pipeline intake. Most compressor suppliers configure their equipment into skid-mounted "packages" that may contain some or all of the above components in addition to a prime mover (engine) that drives the compressor.

What to do if you have gas

Oil wells often produce natural gas contemporaneously with the oil (and water). This gas must be disposed of. Usually, the method used depends on the volume of gas and the availability of a gas pipeline. Traditionally, small amounts of field gas have been flared to get rid of them, but flaring has recently become unpopular. It is perceived by the public to be wasteful and/or contributing to global warming. Many countries are moving to discontinue the practice of flaring. Most operators are curtailing flaring voluntarily.

So what is done with the associated gas? There are several options:

• Treat it, compress it and send it to a nearby gas pipeline;
• Convert it to a petroleum liquid and pump it into the oil flowline;
• Use it to power field equipment, such as compressors, heaters, pumps etc.;
• Re-inject it into the formation to help maintain reservoir pressure;
• Use it as a solvent to reduce the oil viscosity; or
• Use it in artificial lift (gas lift) systems.

Most, if not all, of these schemes require compression. The choice of which technique to use is largely a question of economics. Liquefaction, while proved technically feasible since the early part of the 20th Century, suffered from inefficiency and was cost-prohibitive unless volumes were high enough to achieve economy of scale.

As one can imagine, the need for compression is driven by several broad and dynamic variables:

• Current, and forecast, commodity prices;
• Volume of produced gas (gas rate);
• Volume of recoverable gas reserves;
• Proximity to gas transmission infrastructure;
• Treatment costs;
• Wellhead pressure;
• Opportunities for field consumption (onsite disposal); and
• Opportunities for cost-effective gas-gathering schemes to boost volumes.

These enter into the decision on the type, capacity and horsepower of the compressor and its associated "package" components. Over the life of the well or field these drivers can change dramatically.

Compressor types

Compressors fall into three major categories depending on the way they work:

• Positive displacement compressors;
• Dynamic type compressors; and
• Thermal type compressors.

Positive displacement compressors can be either reciprocating (most common) or rotary. Reciprocating compressors work like a car or truck engine, using pistons to compress the gas. An alternative reciprocating design uses a moving diaphragm to compress the gas, much like the human diaphragm compresses the lungs to expel air. Several designs of piston-type compressors are marketed: single stage, multistage, integral gas-engine driven, separable and balanced/opposed piston. Rotary compressors include straight lobe, helical lobe (or screw), sliding vane and liquid ring.

Dynamic compressors include radial flow (centrifugal) and axial flow types. There is also a mixed-flow type dynamic compressor. Dynamic compressors are characterized by a rotating impeller or bladed rotor that accelerates the gas as it passes through the unit, these are often called "blowers."
Thermal compressors use ejectors, in which a high-pressure steam (or gas) jet "entrains" the intake gas and moves it to a diffuser, where its velocity is converted to pressure.

Because the physics and thermodynamics of each type vary widely, compressors are usually classified according to two parameters: intake flow volume and discharge pressure. At the low end of the spectrum are diaphragm compressors which operate best when intake volume is below 10 cubic feet per minute at atmospheric conditions (acfm) and when discharge pressure is below about 200 psi. For highest discharge pressure applications, from 5,000 psi up to 50,000-100,000 psi, with corresponding intake volumes from 2,000 acfm down to 10 acfm, multistage reciprocating compressors are desirable. For high intake volumes up to 700,000 acfm, axial compressors are recommended, but discharge pressure is limited to around 80 psi. To get high discharge-pressure and high volume performance, centrifugal multistage compressors have the widest range, being capable of delivering 200,000 acfm of gas at 70 psi or 80 acfm of gas at 10,000 psi (Figure 1).

As can be seen, the intake volume and discharge pressures are reciprocal, meaning that the more pressure needed, the less volume can be delivered. This is what makes compressor selection so complex. Engineers have to consider both current wellhead/pipeline conditions and future expected conditions to ensure the compressor they select will do the job for a reasonable, and economically profitable, time.

How to choose?

Some of the considerations the engineers must take into account include:
Centrifugal advantages
• Lower installed first cost where pressure and volume conditions are favorable
• Lower maintenance expense
• Greater continuity of service and dependability
• Less operating attention
• Greater volume capacity per unit of plot area
• Adaptability to high-speed low maintenance-cost drivers
• No pulsation effect
• Fewer moving parts
Reciprocal advantages
• Greater flexibility in capacity and pressure ranges
• Higher efficiency and lower power cost
• Higher discharge pressures
• Capability to handle smaller volumes
• Less sensitive to changes in gas composition and density

The bottom line

Usually, compressors are rated by horsepower. The production engineer must determine the amount of compressor horsepower needed to compress a certain volume of gas from some intake conditions to a given discharge pressure. In commercial applications (meaning not those associated with re-injection or using field gas to power equipment), the decision is driven by the gas contract. Producers sign a contract with pipeline companies to supply a given volume of certain quality gas at pipeline pressure for a specific time at a specific price. For example, a producer may contract to supply 1 MMcf of dry gas per day (MMcfg/d) at 5,000 psi for 2 years for US $4.00 per 1,000 cf.

Note the price the producer gets is not the price published in the newspaper. Those prices are usually statements of the "Futures" price on the New York Commodity Exchange and are pegged to a certain gathering point, the one most commonly referenced is the "Henry Hub." The hub is physically located near Erath, La. Another price less-commonly heard is the "City Gate" price. This can vary widely depending on transmission costs. During a recent gas shortage, Henry Hub gas was priced below $3.00 per thousand cubic feet but prices at the Chicago City Gate varied between $30 and $40 per thousand. The difference was caused by a severe shortage of pipeline capacity into the Chicago market area. Recently, it has been proposed to measure gas by its heating capacity rather than its volume, hence you might hear a price given as $X per million btu. This injects a certain element of quality into the mix, because it values the gas for its capacity to do work (e.g convert itself to energy). Poor quality gas delivers fewer btu per 1,000 cf than high quality gas.

Once the contract terms are known, the engineer works backwards to determine the compressor horsepower needed to meet the terms of the contract. With a fixed delivery requirement and a variable supply (because of reservoir decline) the job is complex.

For example, suppose a well produces gas at 5,000 psi wellhead pressure. The pipeline operates at 4,000 psi. So in this case no compression is needed at all, in fact the pressure must be bled down to 4,000 psi before the pipeline will accept the gas. After a year or so, the reservoir pressure has declined and the wellhead pressure is predicted to fall below 4,000 psi. Now the engineer must plan to install a compressor to maintain the gas at pipeline pressure to meet the terms of the contract. But what size should be specified? The present requirement is small, only needing to raise the gas pressure a few psi to match the pipeline. But in the near future, as the reservoir continues its decline, the compression requirements will go up. A longer-term solution is required.

Some solutions

A practical solution is to package compressors in horsepower "units" and add them as needed to maintain contract pressure and volume. Another solution is to establish gas gathering units that combine the production from several wells to keep up the volume and allow installation of a single large compressor station instead of several small wellhead stations. Another (less likely) idea might be to renegotiate the terms of the contract.

Because of the wide variety of options, a large domestic rental fleet has emerged. Producers can now rent the compressor horsepower they need on an ad hoc basis and add or subtract units as required. Moreover, most rental companies include service and maintenance as part of the deal. And rental companies are only too happy to add enhancements, such as dehydrators, cooling stages, heaters, etc., at a price of course.

Interestingly, the rental business is largely confined to the Western hemisphere. It is hypothesized that because of regional import/export restrictions and red-tape overseas that moving compressor units from field to field (or country to country) is difficult and costly. Also, there is a cultural distrust of the rental business in many countries. Many overseas operators want to own their assets so they can control them. And rental companies are often reluctant to operate in countries that might decide to confiscate or restrict their fleet at any time and prevent units from being exported. Nevertheless, the rental business is here to stay.

Take a look at the alternatives:

Purchase Pros
• Good for long-term use where requirements are well known
• Can be built to precise specifications (customized)
• If conditions do not vary significantly, purchase could be lowest cost.
• Owner is 100% in control and can use, modify or dispose of the unit at will.
Lease Pros
• Allows CAPEX to be paid from revenue generated from production
• Some customization is possible
• Lower cost than renting
• Cost spread out over time
• At the end of the lease period, the lessee owns the unit.
Rent Pros
• Units built to typical oilfield specs available from stock
• Short-term rentals favor pilot projects
• Rent is treated as OPEX for tax purposes
• CAPEX freed up for core business
• Flexibility to add/swap units
• Improved cash flow
• Performance-based contracts
• Lower risk
• Rental company is responsible for maintenance

Power packs

Compressors can be powered by electricity, gasoline, diesel, or steam. The most convenient power source is a natural gas-aspirated internal combustion engine. Field gas is essentially free and is not taxed. Often the exhaust of the engine can itself be compressed and injected into the reservoir to help maintain pressure or into a safe disposal zone. Most compressor package suppliers can provide any type of power pack the customer wants. Often, practical considerations such as maintenance and spare parts inventories suggest advantages of sticking with a single engine supplier. About 90% are driven by natural gas engines whose major suppliers include Caterpillar, Cummins and Waukesha. Key performance indicators that may influence a decision include CO2 emissions, fuel economy and reliability.

Performance and participants

Compressor output can be adjusted by varying its speed, over a limited range. Running it faster can boost volume throughput. Cooling compressed gas between stages of a multi-stage compressor can boost efficiency. About 90% of large compressor packages (2,000 + hp) are controlled by Programmable Logic Controller (PLC) units. Smaller units are controlled by so-called Millennium Panels. Natural gas compressor builders are Ariel, which provides most reciprocating compressors, Dresser-Rand, Gardner-Denver, GE-Gemini and Cooper. There are hundreds of compressor manufacturers, but relatively few that supply the natural gas market. The largest suppliers are Hanover, with 6,000 units totaling more than 3.6 million hp, and Universal Compression with about 3.0 million hp. Together they comprise about 70% of the North American market.

Problems

In most gas field operations, if a problem occurs, the service representative can take some time to diagnose the problem with the well shut-in. However, in an oil field, the operator is unwilling to shut-in the well because it may not come back on production when the master valve is reopened. Also most operators will not tolerate the lost oil production while a solution is found to the associated gas compressor problem. Short-term flaring, even to allow for repairs is frowned upon, so suppliers must be prepared to swap out a reconditioned unit while they diagnose and repair the problem. Most compressor package providers equip their units with instrumentation that, in the simplest cases, provides automatic shut-down in the event of an emergency. Recently, some suppliers are adding "black boxes" similar to those found on commercial aircraft that monitor and record critical operational parameters so problems can be analyzed to determine the cause. Most frequently, the problem is found to be in the well or reservoir, however. On modern units, minimal supervision coupled with scheduled maintenance will keep the unit operating for at least the life of the contract.

Future considerations

High prices are stimulating developments in the compressor business. With a viable cash crop of natural gas, operators are interested in monetizing as much of it as is economically feasible. For example, Syntroleum Corp. recently made great strides developing a practical and economical liquefaction unit. Major compression suppliers hold that their clients are most interested in availability, reliability and low fuel and maintenance costs. Accordingly instrumentation such as real-time monitoring and telemetry have found it difficult to gain traction. Even today, many units only can boast some sort of emergency shut-down device. Some also have an automatic dial paging system so the regional maintenance technician will be advised when a unit shuts down. To protect their assets, suppliers of rental units usually insist on handling their own maintenance, and these technicians are using increasingly sophisticated tools to ensure their units keep running. Such methods as periodic spectrographic analysis of crankcase oil similar to that performed by large over-the-road haulers has been effective in predicting problems before a unit fails, thus avoiding an emergency and its associated costly repairs.

Like any business, the ultimate driver is the dollar. Providers who consistently satisfy their customers' needs at a fair price will succeed, because with rising energy demand the market has no place to go but up.

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