Surface facilities, pipelines and midstream

What comes out of a Tamarack Lake field well is not saleable oil. It is a hot, frothy mixture of oil, gas, salty water and a little sand, at a pressure of a hundred psi or more. Before it can be sold, the gas must be separated and sent to a processing plant, the water removed and disposed of, the oil treated until it meets pipeline or rail specifications and every stream measured accurately, because royalties, taxes and partners' shares depend on the numbers. Sofia spends as much time on the surface equipment as on the wells. This lesson follows the fluids from the wellhead to the sales point.

The battery: separating oil, gas and water

Production from one or more wells flows to a tank battery, the facility where it is separated, treated, measured and stored. Many Bakken pads have their own battery serving the four to eight wells drilled there. Each well's production may be routed through its own separator and meters, or periodically through a test separator so that it can be measured on its own, with the totals allocated back to the wells.

The first piece of equipment is the separator, a horizontal or vertical steel vessel in which the mixture slows down so that gas can rise out of the liquid and water can settle below the oil. A two-phase separator splits gas from liquid; a three-phase separator also draws off free water. The vessel is sized to hold the liquid long enough for the phases to separate, typically a few minutes, and to keep the gas velocity low enough that liquid droplets fall out of it. A mist extractor near the gas outlet catches fine droplets. Separators often operate in stages at decreasing pressure, which keeps more of the lighter hydrocarbons in the oil and increases the volume of stock-tank oil.

Oil and water often leave the separator as an emulsion, tiny water droplets suspended in oil, stabilized by natural surfactants. A heater treater warms the emulsion, which lowers the oil's viscosity and helps droplets merge, and gives it time to settle; chemical demulsifiers help further. The goal is pipeline-quality oil, usually with less than 0.5 percent water and sediment. Treated oil goes to stock tanks, where vapor recovery units capture the gas that flashes off as the oil reaches atmospheric pressure. Oil is then pumped into a pipeline through a custody-transfer meter or loaded onto trucks.

Gas handling and processing

Gas from the separators is compressed and sent through gathering pipelines to a gas processing plant. Raw gas contains water vapor, which can form hydrates and corrode pipelines, so it is dehydrated, often by contact with glycol. Sour gas contains hydrogen sulfide, which is removed with amine solutions and converted to elemental sulfur. Carbon dioxide may also be removed. Heavier hydrocarbons such as ethane, propane, butane and pentanes plus are extracted, because they are worth more as natural gas liquids than as fuel and because they must be removed for the gas to meet pipeline specifications for heating value and dew point. The remaining dry gas, mostly methane, goes into transmission pipelines.

In the early years of the Bakken boom, oil wells were drilled faster than gas pipelines could be built, and in 2011 to 2014 about a third of the state's gas was flared. the Industrial Commission responded with gas capture targets in 2014, requiring operators to submit gas capture plans before drilling and restricting production from wells that miss the targets. By June 2026, the state reported capturing 95.5 percent of its gas, with about 160 million cubic feet a day still flared, mostly from new wells awaiting connection. Federal rules also limit venting and require leak detection at many facilities.

# Battery check: separator retention time, solution gas and capture (oilfield units)
oil, water = 2600.0, 1400.0     # bbl/d of new production
liquid_volume = 8.0             # bbl held in the separator at normal level
retention = liquid_volume / ((oil + water) / 1440)
print(f"Liquid retention time: {retention:.1f} min (design minimum 4 min) -> {'OK' if retention >= 4 else 'too small'}")

gor = 1500.0                    # scf of gas per bbl of oil
gas = oil * gor / 1000          # Mcf/d
print(f"Solution gas: {gas:,.0f} Mcf/d")
for captured in (0.70, 0.955, 0.99):
    flared = gas * (1 - captured)
    co2_flared = flared * 1000 * 0.0192 * 2.75 / 1000      # metric t/d: 0.0192 kg CH4 per scf, 2.75 kg CO2 per kg CH4 burned
    print(f"  capture {captured:6.1%}: flare {flared:6.0f} Mcf/d, about {co2_flared:4.1f} t/d of CO2 from combustion")
boe = oil + gas / 6
print(f"Total new production: {boe:,.0f} BOE/d")

Liquid retention time: 2.9 min (design minimum 4 min) -> too small
Solution gas: 3,900 Mcf/d
  capture  70.0%: flare   1170 Mcf/d, about 61.8 t/d of CO2 from combustion
  capture  95.5%: flare    176 Mcf/d, about  9.3 t/d of CO2 from combustion
  capture  99.0%: flare     39 Mcf/d, about  2.1 t/d of CO2 from combustion
Total new production: 3,250 BOE/d

Produced water

In many fields, water is the largest fluid stream. Produced water is often several times saltier than seawater and carries dissolved metals, hydrocarbons and sometimes naturally occurring radioactive material. It is separated, treated to remove oil and solids and then injected into deep disposal wells or reused in waterfloods and fracturing. Disposal wells inject into porous formations far below groundwater, isolated by thick seals, and the regulator limits their injection pressure so that they do not fracture the rock or trigger earthquakes. Pipelines that carry produced water must be monitored as carefully as oil lines, because brine spills can sterilize soil for years.

In North Dakota, most produced water from the Bakken is injected into the Dakota Group sandstones (also called the Inyan Kara) through saltwater disposal wells permitted by the Industrial Commission. Bakken water is extremely salty, often over 200,000 milligrams per liter of dissolved solids, and brine spills from gathering lines are one of the state's main environmental enforcement issues.

Pipelines and markets

Pipelines are the cheapest and safest way to move large volumes of oil and gas over land. Gathering lines collect production from wells and batteries; feeder lines carry it to larger systems; transmission pipelines, up to 1,200 mm (48 inches) in diameter, carry it hundreds or thousands of kilometers to refineries, export terminals and cities. Pumps or compressors along the route keep the fluid moving. Pipelines are made of steel with corrosion-resistant coatings and cathodic protection, buried below frost depth, and monitored by pressure and flow measurements, inline inspection tools called pigs and aerial patrols. Midstream companies also own storage tanks and caverns, rail terminals, fractionation plants that split natural gas liquids and liquefied natural gas (LNG) export facilities.

The Williston Basin is far from the big refining centers, so North Dakota oil moves by pipeline to Cushing, Oklahoma, to the Midwest and to the Gulf Coast, and in the early boom years a large share went by rail. The Dakota Access Pipeline, which began operating in 2017 and can carry more than 700,000 barrels a day toward Illinois, sharply reduced rail shipments. Interstate pipeline safety is regulated by the federal Pipeline and Hazardous Materials Safety Administration, and gathering lines in North Dakota by the Industrial Commission and other state agencies.

Prices are set at trading hubs. In North America the main crude benchmark is West Texas Intermediate (WTI) at Cushing; producers receive WTI minus a differential that reflects transport cost and crude quality. Gas prices are set at hubs such as Henry Hub in Louisiana and AECO in Alberta. Light, sweet crude commands a premium over heavy, sour crude because it yields more gasoline and diesel with less refining. Engineers include these differentials and transport tariffs in every economic evaluation, as Lesson 10 shows.

Measurement and allocation

Every volume that leaves a battery is money, so measurement is regulated as carefully as safety. Custody-transfer meters, where ownership changes hands, must meet strict accuracy standards and be proved regularly against a calibrated reference. Oil is measured by turbine or Coriolis meters or by gauging tanks, and corrected to standard temperature and pressure. Gas is measured by orifice, ultrasonic or Coriolis meters, with its composition analyzed to calculate heating value. Water is measured too, because regulators track how much is produced and where it goes.

In North Dakota, operators report production for every well and facility to the Industrial Commission each month, and the state uses the reports to collect production taxes and track flaring. Where several wells share equipment, production is allocated back to each well from well tests or individual meters, and the allocation method matters to royalty owners, who are paid on each well's share. Federal and tribal leases have additional measurement rules from the Bureau of Land Management, including standards for meter accuracy and site security.

Measurement errors are not small matters. A 1 percent bias on a battery producing 1,000 barrels a day amounts to more than 3,600 barrels a year, worth a quarter of a million dollars at typical prices, and every royalty owner and partner is affected. Engineers therefore audit meters, compare battery totals with sales volumes and investigate any imbalance. Good measurement also underpins emissions reporting, because vented and flared volumes, fuel gas and leaks must all be quantified.

Facility safety and integrity

Surface facilities hold flammable fluids under pressure, often near homes and roads. Every pressure vessel is designed and inspected to a recognized code and fitted with pressure-relief valves that open before the vessel can be overpressured. Shutdown valves close automatically if pressure, level or temperature goes outside safe limits, and flame arrestors and proper spacing reduce fire risk. Sour facilities add hydrogen sulfide detectors, alarms and breathing apparatus. Pipelines are tested at pressures well above their operating pressure before use, and their integrity is managed through corrosion monitoring, inline inspection and repair programs. Many serious incidents in the industry have started with a small leak or a bypassed safety system, which is why management of change, the formal review of any modification, is a core part of facilities engineering.

Facilities engineers also plan for the whole life of a site. A battery sized for the first year's flush production can be too large once rates decline, wasting fuel and making separators hard to control, so many operators use modular, skid-mounted equipment that can be moved to new pads as old ones decline. Consolidating several small batteries into one larger site cuts operating costs, emissions and the number of tanks and flares to inspect. When a battery is finally decommissioned, its equipment is removed, its soil is tested and the site is reclaimed with the wells it served, as Lesson 11 describes.