Surface Production Facilities

Separating and Treating Produced Oil and Gas

The evolution of today’s surface production facilities actually began several thousand years ago. Seepages of asphaltic bitumen in Mesopotamia around 3000 B.C. were the raw material for a “petroleum” industry that flourished for about 3,000 years. It primarily produced a mastic and caulk used in construction. The production system was crude and involved merely the recovery of hydrocarbons in jars and casks. In time, surface facilities for this production involved a crude type of distillation. This evolution is better illustrated in the next few sections.

Storing the Oil

Early oil pioneers concentrated on finding likely drilling sites for exploration and on completing oil wells on those locations. Sumps (pits) were dug on these leases to serve as surface reservoirs for production. Any gas produced with the oil was vented into the atmosphere. Sump separation systems had difficulties as surface water, dirt and other debris ran into these sumps.

By 1861, larger wooden tanks replaced many of the on-site sumps as the loss of oil can be reduced to a minimum from a flowing well by providing a flow tank connected to the casing head. Gas and oil can be separated in the flow tank, the oil being drawn off into receiving tanks and the gas escaping into the air.

These were replaced with bolted-iron tanks by 1867. Most of these tanks were open at the top, allowing rain and debris to enter, so it wasn’t long until wooden “roofs” were placed over them.

The Need for Separation

Early on, it was recognized that the gas associated with the oil could be captured to serve as fuel for the drilling engines and, by removing the gas from the vicinity of the wells, safety could be increased. As a result, the first “separator” was invented around 1863. Separators usually were mounted on top of storage tanks and were, in essence, a barrel rigged so the liquid ran out the bottom into the storage tank below through a trap that kept the gas out. A gas line was connected to a bung on the upper part to move the gas where it was needed. Without realizing it, these early oil producers had, through necessity, reinitiated the centuries-old evolution of surface production facilities.

Improvements Come Quickly

As pressures increased, bolted-iron tanks replaced barrels as separators. As they grew in size, it was necessary to move the separator from the top of the storage tank to the ground and to apply some form of level control to keep the gas from flowing out the liquid outlet.

By 1904, separators were available with level controls and working pressures as high as 150 psi. Experience indicated that oil recovery was higher when a separator preceded the tank than when the oil was allowed to flow directly into the tank. Therefore, separators became standard surface equipment for gas recovery and for increasing oil-recovery efficiency.

From 1904 until the early 1950s, more sophisticated controls, designs, and improved construction materials highlighted the evolution of separators. Horizontal, dual-barrel separators were developed and tested in the late 1940s to handle a growing need for high-gas-flow/low-liquid-flow separation.

The size of separators changed dramatically when large gas transmission lines were constructed; offshore leases were opened for development; and discoveries of larger, higher-pressure gas reserves occurred. The typical single-stage vertical separator suitable for separating “casinghead” gas from oil was no longer viable. Horizontal, single-barrel separators were developed because they were more efficient at high flow rates. Up to three stages of separation became common to stabilize the hydrocarbon liquids produced from high-pressure wells.

Knocking Out the Water

In many early production systems, the separation of water was accomplished in the oil tank. The separated water was disposed of by merely opening a valve on the bottom periodically to drain off the water, which was allowed to run into the nearest ditch.

Three phase separators were used as higher-pressure wells were drilled. This is a pressure vessel with a liquid retention time that was long enough to allow the water and oil to separate. An internal weir or baffle arrangement was positioned so that water can be drawn from the bottom, oil from the side, and gas from the top. The free water separation method functioned very well as long as the oil and water did not emulsify so much that gravity separation alone was unsatisfactory.

Around 1900, a “hay tank” containing excelsior was placed between the 3 phase separator and the oil tank. This provided surface area for small droplets of emulsified water in the oil to coalesce into large enough drops, separate by gravity, and then be removed. It was found that heat, certain chemicals, and/or turbulence at the proper point also helped break down these emulsions. This led to the development of a single compact unit called a vertical heater-treater.

As oil fields became unitized in the 1920s, a move to centralize treating systems that handled several wells gained in popularity, resulting in higher production rates per treater. This led to the development of horizontal heater-treaters. In offshore environments, many operators have elected to use heat exchangers upstream of the treater to eliminate safety hazards associated with standard heater-treater fire tubes.

Managing Produced Water and Salt Water

State laws regulating discharges began to appear as early as 1909 in Oklahoma, but they weren’t aggressively enforced until more stringent regulations were passed in the 1950s. Even so, most states continued to allow surface discharges to freshwater streams until well into the 1960s.

Until the early 1950s, the most common means of saltwater disposal in areas such as West Texas and Oklahoma were evaporation ponds. Water was typically routed through a string of earthen pits with baffles and skimmers to the pond. However, it is probable that much of the water leaving these ponds seeped through the bottom rather than evaporating into the atmosphere. Many cases of ground water contamination occurred around the retention and evaporation ponds.

Sometime during the 1920s, producers hit upon the idea of injecting the unwanted saltwater into older, abandoned wells or into dry holes for disposal. Experience quickly indicated that it was necessary to further treat the water to remove solids and free oil.

With the advent of production from the Middle East, where high levels of dissolved salts were found to exist in the produced water, crude-oil purchasers insisted that “desalting” be carried out in the field. To accomplish this, the produced water is diluted with fresh, or low-salinity, water prior to treating the emulsion in a process commonly called “washing.” This enables a lower outlet salt content in the crude, since the salinity in the residual water is lowered. Often, a two-stage system of dilution followed by treating is required to meet the lower-salt-content mandates.

Handling Produced Water Offshore

As late as the mid-1960s, produced water from offshore three-phase separators was routed directly overboard. In other installations, water was first routed to a precipitator or skim tank before flowing overboard for disposal. In the Gulf of Mexico during the late 1960s, the corrugated-plate interceptor (CPI) using plate-coalescence technology first came into general use for separating small water droplets.

The CPI was quickly followed by the development of gas flotation units. The first units used offshore were adaptations of dissolved-gas flotation units used in refineries and chemical plants. However, they did not perform satisfactorily.

During the next decade, the 1970s, dispersed-gas flotation units, first mechanical and then hydraulic designs, were introduced offshore in the Gulf of Mexico and in the thermal-flood regions of California. They were adaptations of units used in the mining industry for ore benefication.

In the 1980s, hydrocyclones were introduced to separate oil from produced water. Hydrocyclones had been used a decade earlier for separating and cleaning solids from produced water, but it had been thought that they could not work effectively to separate two liquid phases with very little difference in density. The first oilfield use of hydrocyclones was in the Bass Straits in Australia, followed by the North Sea and the Gulf of Mexico.

Natural Gas Processing

The commercialization of natural gas wells with higher pressures made the development of processing facilities for them a necessity. These wells have a large pressure drop between the wellhead and the high-pressure separator, which led to the design and manufacture of low-temperature separation units (LTSs).

In an LTS unit, the gas expands across a valve in a manner that produces a specific temperature. The hydrates formed by this expansion fall into a liquid bath maintained at a temperature that melts the hydrates and keeps them from plugging the unit. The LTS unit’s exit temperature is kept below the minimum pipeline temperature so no liquid will form in the line. Due to the low temperature of separation, additional natural gas liquids (NGLs) are recovered, and the gas heating value is reduced to meet marketable standards.

Since LTS units are difficult to operate and only work effectively when the surface wellhead pressures and temperatures are within specific ranges, a more desirable high pressure gas well hook-up evolved during the 1950s. This hook-up uses a line heater to ensure that the temperature downstream of the choke is always above the hydrate point, and it uses one or two stages of separation to stabilize the condensate before it flows to a tank.

Dehydrating The Gas

Gas dehydration at, or near, the production site usually is considered mandatory. “In the early days of the petroleum business when the value of gas was less, it was common to use gas heaters to keep the flowing temperature above the hydrate formation point in a gathering system. Initially, gas dehydration was accomplished by the use of solid desiccants, which became available in the 1920s. These were large, expensive units and were used only where large quantities of gas were involved, particularly at the inlet end of a transmission line.

These were replaced by wellhead triethylene glycol dehydrators sometime in 1949 as developed by Laurance S. Reid that was both suitable and economical for dehydration of gas to pipeline specifications. The use of these became standard and largely replaced the heater. Ultimately, larger and more efficient glycol units replaced solid-desiccant ones as the primary dehydration method. Today glycol absorption is the routine choice for gas dehydration.

Compressing The Gas

Gas compressors were developed for installation downstream of the separators as line pressures increased above wellhead pressures. As the gas cooled in the line below its dewpoint temperature, liquids formed that hindered the gas flow rate, and separation was required again before the gas was burned.

Once again, necessity triggered advances in technology. “After compression, the gas needed to be cooled with water prior to separation so its dewpoint temperature would be above the temperature in the line,” states facilities designer Ken Arnold. “Thus, the first cooler appeared in 1903 and consisted of an old boiler filled with water with cooling coils running through it.”

Despite some advancements during the next five decades, natural gas transmission lines were hampered by slow speed (i.e., 200 to 400 rev/min) integral or steam- driven compressors. However, the design of high-speed-compressor valves during the early 1950s enabled the direct coupling of standard engines to high-speed-compressor frames operating at 900 to 1,200 rev/min. This development greatly advanced gas-compression technology. Later advances in reciprocating-compressor technology enabled compressor speeds to increase to as much as 1,800 rev/min.

In the late 1960s, turbine-driven centrifugal compressors became available for oilfield service. Although less fuel efficient than engine-driven compressors, turbine-driven centrifugals weigh less and occupy less space per unit of power than their engine-driven counterparts. They have seen increasing use offshore, where large horsepower requirements are necessary, and at remote locations where transportation and installation costs are important.

The Future

In recent years, there has been a considerable amount of research and field testing driven by the need to lower topsides weight and size for deepwater developments and to allow for the possibility of downhole and subsea separation equipment. This research has led to development of “compact separators” that employ centrifugal force to accomplish a gas/liquid separation in a shell of much smaller diameter and length than a standard gravity separator. The number of proprietary compact-separator designs on the market has begun to grow and is expected to expand tremendously during the next decade.

Likewise, multiphase pumping equipment capable of pumping a mixture of gas and liquid was not even considered practical until the mid-1990s. Now the equipment is available, and the key to success for this technology will be in handling high gas-volume fractions and inlets that see a great deal of slugging and surging flow.

Cross-flow-membrane technology for offshore produced-water-treating applications has received a great deal of research. And centrifuges have been installed offshore on difficult-to-treat streams. While both technologies have been highly effective, neither has been used widely thus far due to their high purchase and maintenance costs. However, both are expected to be developed further in the next decade. It should be noted, however, that the future of this evolving technology depends more on its application than its development.

In the past, the slow evolution of advancements in surface-facility equipment allowed design engineers to specify process needs and be certain that the offers of various suppliers would be similar. It was considered beneficial, but not essential, for facilities designers to know how to size and specify equipment.

Today, because of dramatic changes in the range of new technologies available, it is essential that design engineers understand both the benefits and detriments of any newly developed technology. Now, and even more often in the future, process and equipment choices will have to be made before costs are definitely known. Balances between costs and technologies will have to be struck. Depending on the specific application, it may make more sense to use an older, proven technology instead of a newer one because the application does not require a cutting-edge solution. In either case, the costs associated with the facilities may be determinant in deciding whether the field is commercially viable. Whatever the future holds, it is certain that surface production facilities will continue to play a large role in the upstream business of oil and gas.

References

McBeth, R.S.: Oil, New Monarch of Motion, Markets Publishing Corp., New York City (1919) 155–156.
Boling, D.R.: “Oil Storage,” Petroleum Engineering Handbook, SPE, Dallas (1962) Chapter 10.
Cloud, W.F.: Petroleum Production, U. of Oklahoma Press, Norman, OK (1939). Chapter 14, 501–503, 505.
Westcott, H.P.: “Part 7: Compressors of Natural Gas,” Handbook of Natural Gas, Metric Metal Works, Erie, PN (1915) 325.

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