Surface Production

Introduce

Is found in shallow reservoirs, seeps of crude oil or gas may naturally develop, and some oil could simply be collected from seepage or tar ponds. Historically, we know of tales of eternal fires where oil and gas seeps would ignite and burn. One example 1000 B.C. is the site where the famous oracle of Delphi would be built, and 500 B.C. Chinese were using natural gas to boil water.
But it was not until 1859 that "Colonel" Edwin Drake drilled the first successful oil well, for the sole purpose of finding oil.
The Drake Well was located in the middle of quiet farm country in north-western Pennsylvania, and began the international search for and industrial use of petroleum. Photo: Drake Well Museum Collection, Titusville, PA



These wells were shallow by modern standards, often less than 50 meters, but could give quite large production. In the picture from the Tarr Farm, Oil Creek Valley, the Phillips well on the right was flowing initially at 4000 barrels per day in October 1861, and the Woodford well on the left came in at 1500 barrels per day in July, 1862. The oil was collected in the wooden tank in the foreground. Note the many different sized barrels in the background. At this time, barrel size was not yet standardized, which made terms like "Oil is selling at $5 per barrel" very confusing (today a barrel is 159 liters, see units at the back). But even in those days, overproduction was an issue to be avoided. When the “Empire well” was completed in September 1861, it gave 3,000 barrels per day, flooding the market, and the price of oil plummeted to 10 cents a barrel.
Soon, oil had replaced most other fuels for mobile use. The automobile industry developed at the end of the 19th century, and quickly adopted the fuel. Gasoline engines were essential for designing successful aircraft. Ships driven by oil could move up to twice as fast as their coal fired counterparts, a vital military advantage. Gas was burned off or left in the ground. Despite attempts at gas transportation as far back as 1821, it was not until after the World War II that welding techniques, pipe rolling, and metallurgical advances allowed for the construction of reliable long distance pipelines, resulting in a natural gas industry boom. At the same time the petrochemical industry with its new plastic materials quickly increased production. Even now gas production is gaining market share as LNG provides an economical way of transporting the gas from even the remotest sites.
With oil prices of 50 dollars per barrel or more, even more difficult to access sources become economically interesting. Such sources include tar sands in Venezuela and Canada as well as oil shales. Synthetic diesel (syndiesel) from natural gas and biological sources (biodiesel, ethanol) have also become commercially viable. These sources may eventually more than triple the potential reserves of hydrocabon fuels.

Process overview

The following figure gives a simplified overview of the typical oil and gas production process




Today oil and gas is produced in almost every part of the world, from small 100 barrel a day small private wells, to large bore 4000 barrel a day wells; In shallow 20 meters deep reservoirs to 3000 meter deep wells in more than 2000 meters water depth; In 10.000 dollar onshore wells to 10 billion dollar offshore developments.
Despite this range many parts of the process is quite similar in principle. At the left side, we find the wellheads. They feed into production and test manifolds. In a distributed production system this would be called the gathering system. The remainder of the figure is the actual process, often called the Gas Oil Separation Plant (GOSP). While there are oil or gas only installations, more often the wellstream will consist of a full range of hydrocarbons from gas (methane, butane, propane etc.), condensates (medium density hydro-carbons) to crude oil. With this well flow we will also get a variety of non wanted components such as water, carbon dioxide, salts, sulfur and sand. The purpose of the GOSP is to process the well flow into clean marketable products: oil, natural gas or condensates. Also included are a number of utility systems, not part of the actual process, but providing energy, water, air or some other utility to the plant.


Facilities



Onshore

Onshore production is economically viable from a few tens of barrels a day upwards. Oil and gas is produced from several million wells world-wide. In particular, a gas gathering network can become very large, with production from hundreds of wells, several hundred kilometers/miles apart, feeding through a gathering network into a processing plant. The picture shows a well equipped with a sucker rod pump (donkey pump) often associated with onshore oil production. However, as we shall see later, there are many other ways of extracting oil from a non-free flowing well For the smallest reservoirs, oil is simply collected in a holding tank and collected at regular intervals by tanker truck or railcar to be processed at a refinery.
But onshore wells in oil rich areas are also high capacity wells with thousands of barrels per day, connected to a 1.000.000 barrel a day gas oil separation plant (GOSP). Product is sent from the plant by pipeline or tankers. The production may come from many different license owners. Metering and logging of individual wellstreams into the gathering network are important tasks.
Recently, very heavy crude, tar sands and oil shales have become economically extractible with higher prices and new technology. Heavy crude may need heating and diluent to be extracted, sands have lost their volatile compounds and are strip mined or could be extracted with steam. It must be further processed to


separate bitumen from the sand. These unconventional of reserves may contain more than double the hydrocarbons found in conventional reservoirs.


Offshore

Offshore, depending on size and water depth, a whole range of different structures are used. In the last few years, we have seen pure sea bottom installations with multiphase piping to shore and no offshore topside structure at all. Replacing outlying wellhead towers, deviation drilling is used to reach different parts of the reservoir from a few wellhead cluster locations. Some of the common offshore structures are:
Shallow water complex, characterized by a several independent platformsw with different parts of the process and utilities linked with gangway bridges. Individual platforms will be described as Wellhead Platform, Riser Platform, Processing Platform, Accommodations Platform and Power Generation Platform. The picture shows the Ekofisk Field Centre by Phillips petroleum. Typically found in water depths up to 100 meters. Photo: Conoco Phillips Gravity Base. Enormous concrete fixed structures placed on the bottom, typically with oil storage cells in the “skirt” that rests on the sea bottom. The large deck receives all parts of the process and utilities in large modules. Typical for 80s and 90s large fields in 100 to 500 water depth. The concrete was poured at an at shore location, with enough air in the storage cells to keep the structure floating until tow out and lowering onto the seabed. The picture shows the world’s largest GBS platform, the Troll A during construction



Compliant towers are much like fixed platforms. They consist of a narrow tower, attached to a foundation on the seafloor and extending up to the platform. This tower is flexible, as opposed to the relatively rigid legs of a fixed platform. This flexibility allows it to operate in much deeper water, as it can 'absorb' much of the pressure exerted on it by the wind and sea. Compliant towers are used between 500 and 1000 meters water depth.
Floating production, where all topside systems are located on a floating structure with dry or subsea wells. Some floaters are:
FPSO: Floating Production, Storage and Offloading.
Typically a tanker type hull or barge with wellheads on a turret that the ship can rotate freely around (to point into wind, waves or current). The turret has wire rope and chain connections to several anchors (position mooring - POSMOR), or it can be dynamically positioned using thrusters (dynamic positioning – DYNPOS). Water depths 200 to 2000 meters. Common with subsea wells. The main process is placed on the deck, while the hull is used for storage and offloading to a shuttle tanker. May also be used with pipeline transport.
A Tension Leg Platform (TLP) consists of a structure held in place by vertical tendons connected to the sea floor by pile-secured templates. The structure is held in a fixed position by tensioned tendons, which provide for use of the TLP in a broad water depth range up to about 2000m. Limited vertical motion. The tendons are constructed as hollow high tensile strength steel pipes that carry the spare buoyancy of the structure and ensure limited vertical motion. A variant is Seastar platforms which are



miniature floating tension leg platforms, much like the semi submersible type, with tensioned tendons. SPAR: The SPAR consists of a single tall floating cylinder hull, supporting a fixed deck. The cylinder however does not extend all the way to the seafloor, but instead is tethered to the bottom by a series of cables and lines. The large cylinder serves to stabilize the platform in the water, and allows for movement to absorb the force of potential hurricanes. Spars can be quite large and are used for water depths from 300 and up to 3000 meters. SPAR is not an acronym, but refers to its likeness with a ship’s spar. Spars can support dry completion wells, but is more often used with subsea wells.
Subsea production systems are wells located on the sea floor, as opposed to at the surface. Like in a floating production system, the petroleum is extracted at the seafloor, and then can be 'tied-back' to an already existing production platform or even an onshore facility, limited by horizontal distance or “offset”. The well is drilled by a moveable rig and the extracted oil and natural gas is transported by
undersea pipeline and riser to a processing facility. This allows one strategically placed production platform to service many wells over a reasonably large area.
Subsea systems are typically in use at depths of 7,000 feet or more, and do not have the ability to drill, only to extract and transport. Drilling and completeion is performed from a surface rig. Horizontal offsets up to 250 kilometers, 150 miles are currently possible.




Main Process Sections

We will go through each section in detail in the following chapters. The summary below is an introductory short overview of each section


Wellheads

The wellhead sits on top of the actual oil or gas well leading down to the reservoir. A wellhead may also be an injection well, used to inject water or gas back into the reservoir to maintain pressure and levels to maximize production. Once a natural gas or oil well is drilled, and it has been verified that commercially viable quantities of natural gas are present for extraction, the well must be 'completed' to allow for the flow of petroleum or natural gas out of the formation and up to the surface. This process includes strengthening the well hole with casing, evaluating the pressure and temperature of the formation, and then installing the proper equipment to ensure an efficient flow of natural gas out of the well. The well flow is controlled with a choke.
We differentiate between dry completion with is either onshore or on the deck of an offshore structure, and Subsea completions below the surface. The wellhead structure, often called a Christmas tree, must allow for a number of operations relating to production and well workover. Well workover refers to various technologies for maintaining the well and improving its production capacity.


Manifolds/gathering
Onshore, the individual well streams are brought into the main production facilities over a network of gathering pipelines and manifold systems. The purpose of these is to allow set up of production “well sets” so that for a given production level, the best reservoir utilization, well flow composition (gas, oil, waster) etc. can be selected from the available wells. For gas gathering systems, it is common to meter the individual gathering lines into the manifold as shown on the illustration. For multiphase (combination of gas, oil and water) flows, the high cost of multiphase flow meters often lead to the use of software flow rate estimators that use well test data to calculate the actual flow.
Offshore, the dry completion wells on the main field centre feed directly into production manifolds, while outlying wellhead towers and subsea installations feed via multiphase pipelines back to the production risers. Risers are the system that allow a pipeline to “rise” up to the topside structure. For floating or structures, this involves a way to take up weight and movement. For heavy crude and in arctic areas, diluents and heating may be needed to reduce viscosity and allow flow.






Separation

Some wells have pure gas production which can be taken directly to gas treatment and/or compression. More often, the well gives a combination of gas, oil and water and various contaminants which must be separated and processed. The production separators come in many forms and designs, with the classical variant being the gravity separator.






In gravity separation the well flow is fed into a horizontal vessel. The retention period is typically 5 minutes, allowing the gas to bubble out, water to settle at the bottom and oil to be taken out in the middle. The pressure is often reduced in several stages (high pressure separator, low pressure separator etc.) to allow controlled separation of volatile components. A sudden pressure reduction might allow flash vaporization leading to instabilities and safety hazards. Photo: JL Bryan Oilfield Equipment

Gas compression

Gas from a pure natural gas wellhead might have sufficient pressure to feed directly into a pipeline transport system. Gas from separators has generally lost so much pressure that it must be recompressed to be transported. Turbine compressors gain their energy by using up a small proportion of the natural gas that they compress. The turbine itself serves to operate a centrifugal compressor, which contains a type of fan that compresses and pumps the natural gas through the pipeline.
Some compressor stations are operated by using an electric motor to turn the same type of centrifugal compressor. This type of compression does not require the use of any of the natural gas from the pipe; however it does require a reliable source of electricity nearby. The compression includes a large section of associated equipment such as scrubbers (removing liquid droplets) and heat exchangers, lube oil treatment etc.
Whatever the source of the natural gas, once separated from crude oil (if present) it commonly exists in mixtures with other hydrocarbons; principally ethane, propane, butane, and pentanes. In addition, raw natural gas contains water vapor, hydrogen sulfide (H2S), carbon dioxide, helium, nitrogen, and other compounds. Natural gas processing consists of separating all of the various hydrocarbons and
fluids from the pure natural gas, to produce what is known as 'pipeline quality' dry natural gas. Major transportation pipelines usually impose restrictions on the make






up of the natural gas that is allowed into the pipeline. That means that before the natural gas can be transported it must be purified. Associated hydrocarbons, known as 'natural gas liquids' (NGL) ar used as raw materials for oil refineries or petrochemical plants, and as sources of energy.


Metering, storage and export
Most plants do not allow local gas storage, but oil is often stored before loading on a vessel, such as a shuttle tanker taking the oil to a larger tanker terminal, or direct to crude carrier. Offshore production facilities without a direct pipeline connection generally rely on crude storage in the base or hull, to allow a shuttle tanker to offload about once a week. A larger production complex generally has an associated tank farm terminal allowing the storage of different grades of crude to take up changes in demand, delays in transport etc.
Metering stations allow operators to monitor and manage the natural gas and oil exported from the production installation. These metering stations employ specialized meters to measure the natural gas or oil as it flows through the pipeline, without impeding its movement.
This metered volume represents a transfer of ownership from a producer to a customer

(or another division within the company) and is therefore called Custody Transfer Metering. It forms the basis for invoicing sold product and also for production taxes and revenue sharing between partners and accuracy requirements are often set by governmental authorities.
Typically the metering installation consists of a number of meter runs so that one meter will not have to handle the full capacity range, and associated prover loops so that the meter accuracy can be tested and calibrated at regular intervals. Pipelines can measure anywhere from 6 to 48 inches in diameter. In order to ensure the efficient and safe operation of the pipelines, operators routinely inspect their pipelines for corrosion and defects. This is done through the use of sophisticated pieces of equipment known as pigs. Pigs are intelligent robotic devices that are propelled down pipelines to evaluate the interior of the pipe. Pigs can test pipe thickness, and roundness, check for signs of corrosion, detect minute leaks, and any other defect along the interior of the pipeline that may either impede the flow of gas, or pose a potential safety risk for the operation of the pipeline. Sending a pig down a pipeline is fittingly known as 'pigging' the pipeline.

The export facility must contain equipment to safely insert and retrieve pigs form the pipeline as well as depressurization, referred to as pig launchers and pig receivers Loading on tankers involve loading systems, ranging from tanker jetties to sophisticated single point mooring and loading systems that allow the tanker to dock and load product even in bad weather.

Utility systems
Utility systems are systems which does not handle the hydrocarbon process flow, but provides some utility to the main process safety or residents. Depending on the location of the installation, many such functions may be available from nearby infrastructure (e.g. electricity). But many remote installations must be fully self sustainable and thus must generate their own power, water etc.

Source :

Håvard Devold

© 2006 ABB ATPA Oil and Gas