Introduction

The role of a production engineer is to maximize oil and gas production in a cost-effective manner. Familiarization and understanding of oil and gas production systems are essential to the engineers. A complete oil or gas production system consists of a reservoir, well, flowline, separators, pumps, and transportation pipelines. The reservoir supplies wellbore with crude oil or gas. The well provides a path for the production fluid to flow from bottom hole to surface and offers a means to control the fluid production rate. The flowline leads the produced fluid to separators. The separators remove gas and water from the crude oil. Pumps and compressors are used to transport oil and gas through pipelines to sales point.

Reservoir

Hydrocarbon accumulation in geological traps can be classified as reservoir, field, and pool. Depending on the initial reservoir condition in the phase diagram, hydrocarbon accumulations are classified as oil, gas condensate, and gas reservoirs. An oil that is at a pressure above its bubble-point pressure is called an “undersaturated oil” because it can dissolve more gas at the given temperature. An oil that is at its bubble-point pressure is called a “saturated oil” because it can dissolve no more gas at the given temperature. Single phase flow prevails in an undersaturated oil reservoir, whereas two phase flow exists in a saturated oil reservoir.

Wells in the same reservoir can fall into categories of oil, condensate, and gas wells depending on the producing GOR. Gas wells are wells with producing GOR being greater than 100,000 scf/stb; condensate wells are those with producing GOR being less than 100,000 scf/stb but greater than 5,000 scf/stb; wells with producing GOR being less than 5,000 scf/stb are classified as oil wells.

Oil reservoirs can be classified on the basis of boundary type, which determines driving mechanism, and which are as follows: water-drive reservoir, gas-cap drive reservoir, and dissolved-gas drive reservoir.

In water-drive reservoirs, the oil zone is connected by a continuous path to the surface groundwater system (aquifer). The pressure caused by the “column’ of water to the surface forces the oil (and gas) to the top of the reservoir against the impermeable barrier that restricts the oil and gas. This pressure will force the oil and gas toward the wellbore. With the same oil production, reservoir pressure will be maintained longer when there is an active water drive. Edge-water drive reservoir is the most preferable type of reservoir compared to bottom-water drive. The reservoir pressure can remain at its initial value above bubble-point pressure so that single-phase liquid flow exists in the reservoir for maximum well productivity. A steady-state flow condition can prevail in a edge-water drive reservoir for a long time before water breakthrough into the well. Bottom-water drive reservoir is less preferable because of water-coning problems that can affect oil production economics due to water treatment and disposal issues.

In a gas-cap drive reservoir, gas-cap drive is the drive mechanism where the gas in the reservoir has come out of solution and rises to the top of the reservoir to form a gas cap. Thus, the oil below the gas cap can be produced. If the gas in the gas cap is taken out of the reservoir early in

the production process the reservoir pressure will decrease rapidly. Sometimes an oil reservoir is subjected to both water and gas-cap drive.

A dissolved-gas drive reservoir is also called a “solution-gas drive reservoir” and “volumetric reservoir”. The oil reservoir has a fixed oil volume surrounded by no flow boundaries (faults or pinch-outs). Dissolved-gas drive is the drive mechanism where the reservoir gas is held in solution in the oil (and water). Compared to the water and gas-drive reservoirs, expansion of solution (dissolved) gas in the oil provides a weak driving mechanism in a volumetric reservoir. In the regions where the oil pressure drops to below the bubble-point pressure, gas escapes from the oil and oil-gas two-phase flow exists. To improve oil recovery in the solution-gas reservoir, early pressure maintenance is usually preferred.

Well

Oil and gas wells are drilled like an upside-down telescope. The large-diameter borehole section is at the top of the well. Each section is cased to the surface, or a liner is placed in the well that laps over the last casing in the well. Each casing or liner is cemented into the well. A typical flowing oil well, defined as a well producing solely because of the natural pressure of the reservoir. It is composed of casings, tubing, packers, down-hole chokes, wellhead, Christmas tree, and surface chokes.

The “wellhead” is defined as the surface equipment set below the master valve, it includes casing heads and a tubing head. The casing head is threaded onto the surface casing. A “casing head” is a mechanical assembly used for hanging a casing string. Depending on casing programs in well drilling, several casing heads can be installed during well construction. The casing head has a bowl that supports the casing hanger. This casing hanger is threaded onto the top of the production casing. As in the case of the production tubing, the production casing is landed in tension so that the casing hanger actually supports the production casing. In a similar manner, the intermediate casing are supported by their respective casing hangers. All of these casing head arrangements are supported by the surface casing, which is in compression and cemented to the surface. A well completed with three casing strings has two casing heads. The uppermost casing head supports the production casing. The lowermost casing head sits on the surface casing.

The equipment at the top of the producing wellhead is called a “Christmas tree” and it is used to control flow. The “Christmas tree” is installed above the tubing head. An “adaptor” is a piece of equipment used to join the two. The “Christmas tree” may have one flow outlet or two flow outlets. The master valve is installed below the tee or cross. A Christmas tree consists of a main valve, wing valves, and a needle valve. These valves are used for closing the well when needed. At the top of the tee structure, there is a pressure gauge that indicates the pressure in the tubing. The wing valves and their gauges allow access to the annulus spaces.

“Surface choke” is a piece of equipment used to control the flow rate. In most flowing wells, the oil production rate is altered by adjusting the choke size. The choke causes back-pressure in the line. The back-pressure increases the bottom-hole flowing pressure, so it decreases the pressure drop form the reservoir to the wellbore. Thus, increasing the back-pressure in the wellbore decreases the flow rate from the reservoir. In some wells, chokes are installed in the lower section of tubing strings. This choke arrangement reduces well-head pressure and enhances oil production rate as a result of gas expansion in the tubing string. For gas wells, use of down-hole

chokes minimizes the gas hydrate problem in the well stream. A major disadvantage of using down-hole chokes is that replacing a choke is costly.

Certain procedures must be followed to open or close a well. Before opening, check all the surface equipment such as safety valves, fittings, and so on. The burner of a line heater must be lit before the well is opened. This is necessary because the pressure drop across a choke cools the fluid and may cause gas hydrates or paraffin to deposit out. A gas burner keeps the involved fluid hot. Fluid from the well is carried through a coil of piping. The choke is installed in the heater. Well fluid is heated both before and after it flows through the choke. The upstream heating helps melt any solids that may be present in the producing fluid. The downstream heating prevents hydrates and paraffins form forming at the choke.

Separator

The fluids produced from oil wells are normally complex mixtures of hundreds of different compounds. A typical oil well stream is a high-velocity, turbulent, constantly expanding mixture of gases and hydrocarbon liquids, intimately mixed with water vapor, free water, and sometimes solids. The well stream should be processed as soon as possible after bringing them to the surface. Separators are used for the purpose. Three types of separators are generally available from manufacturers: horizontal, vertical, and spherical separators. Horizontal separators are further classified into two categories: single tube and double tube. Each type of separator has specific advantages and limitations. Selection of separator type is based on several factors including characteristics of production steam to be treated, floor space availability at the facility site, transportation, and cost.

Horizontal separators are usually the first choice because of their low costs. Horizontal separators are almost widely used for high-GOR well streams, foaming well streams, or liquid-from-liquid separation. They have much greater gas-liquid interface because of a large, long, baffled gas-separation section. Horizontal separators are easier to skid-mount and service and require less piping for field connections. The liquid-level control placement is more critical in a horizontal separator than in a vertical separator because of limited surge space.

Vertical separators are often used to treat low to intermediate GOR well streams and streams with relatively large slugs of liquid. They handle grater slugs of liquid without carryover to the gas outlet, and the action of the liquid-level control is not as critical. Vertical separators occupy less floor space, which is important for facility sites such as those on offshore platforms where space is limited. Because of the large vertical distance between the liquid level and the gas outlet, the chance for liquid to re-vaporize into the gas phase is limited. However, because of the natural upward flow of gas in a vertical separator against the falling droplets of liquid, adequate separator diameter is required. Vertical separators are more-costly to fabricate and ship in skid-mounted assemblies.

Spherical separators offer an inexpensive and compact means of separation arrangement. Because of their compact configurations, these types of separators have a very limited surge space and liquid-settling section. Also, the placement and action of the liquid-level control in this type of separator is more critical.Pump

After separation, oil is transported through pipelines to the sales point. Reciprocating piston pumps are used to provide mechanical energy required for the transportation. There are two types of piston strokes, the single-action piston stroke and the double-action piston stroke. The double-action stroke is used for duplex (two pistons) pumps. The single-action stroke is used for pumps with three pistons or greater.

Gas Compressor

Compressors are used for providing gas pressure required to transport gas with pipelines and to lift oil in gas-lift operations. The compressors used in today’s natural gas production industry fall into two distinct types: reciprocating and rotary compressors. Reciprocating compressors are most commonly used in the natural gas industry. They are built for practically all pressures and volumetric capacities. Reciprocating compressors have more moving parts and, therefore, lower mechanical efficiencies than rotary compressors. A typical reciprocating compressor can deliver a volumetric gas flow rate up to 30,000 cubic feet per minute (cfm) at a discharge pressure up to 10,000 psig.

Rotary compressors are divided into two classes: the centrifugal compressor and the rotary blower. A centrifugal compressor consists of a housing with flow passages, a rotating shaft on which the impeller is mounted, bearings, and seals to prevent gas from escaping along the shaft. Its efficiency is high and lubrication oil consumption and maintenance costs are low. Typically, the volume is more than 100,000 cfm and discharge pressure is up to 100 psig.

Pipelines

The first pipeline was built in the Unites States in 1859 to transport crude oil. Through the one and half century of pipeline operating practice, the petroleum industry has proven that pipelines are by far the most economical means of large-scale overland transportation for crude oil, natural gas, and their products. Transporting petroleum fluids with pipelines is a continuous and reliable operation.

The pipelines are sized to handle the expected pressure and fluid flow. To ensure desired flow rate of product, pipeline size varies significantly from project to project. To contain the pressures, wall thicknesses of the pipelines range from 3/8 inch to 1 ½ inch.

Safety Control System

The purpose of safety is to protect personnel, the environment, and the facility. The major objective of the safety system is to prevent the release of hydrocarbons from the process and to minimize the adverse effect of such releases if they occur. This can be achieved by the following:

1. Preventing undesirable events2. Shutting-in the process3. Recovering released fluids4. Preventing ignitionThe modes of safety system operation include:1. Automatic monitoring by sensors2. Automatic protective action

3. Emergency shutdown

Protection concepts and safety analysis are based on undesirable events, which includes:1. Overpressure2. Leak3. Liquid overflow4. Gas blow-by5. Underpressure6. Excess temperature