The Production Cycle of a Field

Tue, 01/22/2013 - 14:14


Pemex’s current internal structure means that, before a field begins production, it has already passed through the hands of the exploration and development departments. The exploration stage involves searching for hydrocarbons through different technical methods, which help to determine the location size, and type of hydrocarbons located in a given area. Once this data has been collected, exploration and appraisal wells are drilled to determine the extent of the reservoir. If the discovery is deemed to be commercially viable, then it is passed on to the development division.

Pemex’s development division, is tasked with preparing projects for production, requiring an evaluation of the best way to ensure long-term efficient production and maximum recovery, and confirming the extent of the reserves discovered. It also involves the design and construction of the field’s infrastructure. The exact production plan is then created. In an ideal world, this will take into account the whole life of the project, envisioning the best way to produce from the reservoir according to Pemex’s needs.

It is understood that not every eventuality over the life of a field can be planned for, and that to a certain extent, the production plan has to be dynamic. However, the development division was created with the specific purpose of reducing the number of variables that have the potential to adversely affect production, and ensure that as many scenarios as possible have been planned for. When little regard is shown for the development phase of a project, the results can be a production plan that is reactionary, which naturally impacts the sustainability of a particular project.

The production phase of a project is generally broken down into three stages: primary recovery, secondary recovery, and tertiary recovery. These stages are natural divisions, and reflect the changing conditions that occur at the different stages during the life of a producing field. Each of the three stages requires a different set of techniques and technologies to maximise extraction, while ensuring sustainable exploitation. These techniques have been developed by the global oil and gas industry based on years of experience in dealing with the different stages of production. In the following boxes, you will find a more detailed explanation of each of these phases, and examples of the technologies and methods used in each phase.


Primary recovery relies on the natural energy of the reservoir in question in order to drive production. This is caused by the expansion of reservoir fluids, moving into the space created by the drilling of the well. Because the wellbore has a lower pressure than the reservoir rock, the oil flows into it, and to the surface. This pressure is usually created by one of two processes, known as water drive and gas drive.

Water drive is where the oil in the reservoir is pushed into the wellbore by an active aquifer, generally below the hydrocarbons. Water is compressible to a small degree, and as hydrocarbons in the reservoir are depleted, the water compressed by the hydrocarbons will expand a little, maintaining the pressure to continue production. If the aquifer is active, meaning that water is constantly flowing into it to some degree, then pressure can be maintained consistently until the amount of water in the reservoir reaches the well. At this stage, primary recovery has ended and new techniques will be required to continue production.

Gas drive is broken down into two sub-categories: solution gas drive and gas cap drive. In a well driven by solution gas drive, the gas creating the pressure in the reservoir is present in the oil solution, due to internal reservoir pressure. As the oil is extracted from the well, the drop in pressure causes the gas to separate from the solution, forming a gas cap, which increases pressure on the reservoir. With gas cap drive, the unproduced reservoir already has a gas cap on top, which expands with the depletion of the reserves. With these types of gas drive, the production is steady until the gas cap expands to the point where the well will eventually produce predominantly gas.

The key to primary production is that the reservoir pressure is higher than the pressure in the wellbore. This can be increased through the use of artificial lift systems, which are still considered to be a primary recovery technology.

The factors that influence the amount of oil produced by primary recovery vary wildly depending on several factors: the type of drive pushing the oil out of the well, the viscosity of the oil being produced, and the permeability of the reservoir in question. Generally, primary production accounts for between 5% and 20% of original oil in place.


As primary recovery progresses, the pressure of the well drops. Once the pressure drops below the point where it is sufficient to bring oil to the surface, secondary recovery methods are applied to maintain reservoir pressure to a level at which oil will continue to flow, and displace hydrocarbons in the direction of the wellbore. This flow of energy into the reservoir replaces the natural drive of the reservoir with artificial drive. Common secondary recovery tools are water injection, natural gas injection, and gas lift.

Water injection is used to both increase pressure and sweep unproduced oil towards the production wells. Injection wells are drilled, and water is pumped into the reservoir. A common source for the water used is produced water, which reduces the chance of damaging the formation as a result of incompatible fluids. This also solves the problem of disposing of produced water. However, the volumes of produced water are never sufficient to replace the combined production volume of oil, gas and water, and so additional water must be provided. Seawater can also be used for injection, but only after it has been filtered, deoxygenated and biocides have been used. Water from other aquifers can also be used, as can river water.

As its name suggests, natural gas injection involves the insertion of natural gas into the reservoir, typically at fields that contain both crude oil and gas. Associated gas from the well can be collected and stored during the primary recovery phase, and can be particularly useful in wells that produce heavy oil, because the gas dissolves into the oil again under pressure, lowering its viscosity and aiding its production. As well as re-using produced gas from the reservoir, other gases can be used, such as nitrogen or carbon dioxide. However, using produced gas for secondary recovery can be an excellent strategy to remove the need for gas flaring.

Gas lift should not be confused with gas injection: while injection involves the insertion of gas into the reservoir, gas lift is a technique to lower the pressure by injection of gas into the tubing-casing annulus. The injected gas aerates the fluid, thereby reducing its density, to the point where the pressure differential is enough to enable the oil to be recovered. Generally, at the end of secondary recovery, between 35% and 45% of the original oil has been recovered, when added to the amount retrieved by primary recovery.


Tertiary recovery, also known as enhanced oil recovery, is the final stage in the life of a producing reservoir. As well as maintaining reservoir pressure, the aim of the third stage of recovery is to alter the properties of the oil remaining in the reservoir in order to make it easier to extract. The main techniques used are chemical flooding, thermal recovery, and miscible displacement.

Chemical flooding involves injecting chemicals into the reservoir in order to help free trapped oil. Micellar polymer flooding involves pumping a polymer into the well to reduce the interfacial and capillary forces between oil and water, triggering an increase in oil production. Another type of chemical flooding uses alkalines such as sodium hydroxide or sodium carbonate, which forms surfactants in the reservoir, reducing the interfacial tension and again, increasing oil production.

Thermal recovery techniques heat the oil in the reservoir, improving its viscosity and making it easier to produce; methods include cyclic steam injection and steam flooding. Cyclic steam injection, or ‘huff and puff’, works by injecting steam into a well for a period of time in order to heat the oil, leaving it to sit in the well for a period, and then producing from the same well. This is repeated once production has slowed. Steam flooding or steam drive is very similar to the secondary recovery technique of water flooding, with the added advantage that, as well as displacing the oil in the reservoir, the steam also heats the oil and improves its viscosity.

Miscible displacement, or gas injection, is the most common enhanced oil recovery technique, in which miscible gases are injected into the reservoir to restore well pressure and improve the viscosity of the oil. Gases used include carbon dioxide, nitrogen, and natural gas, although the fluid most commonly used for miscible displacement is carbon dioxide, due to the fact that it reduces viscosity in the reservoir and is less expensive than other alternatives.

Other tertiary recovery techniques also exist, including microbial injection and combustion. Enhanced oil recovery is not suitable for all fields, and involves much higher costs than primary or secondary recovery, but improving the ultimate recovery factor at fields has become a priority for many operators trying their best to improve the profitability of their assets.