Reservoir Engineering

Reservoir Engineering | Basic Concepts in Reservoir Engineering

Reservoir engineering plays a crucial role in the oil and gas industry, enabling the efficient extraction of hydrocarbons from underground reservoirs. In this article, we will explore the fundamental concepts of reservoir engineering, from the definition of reservoir engineering to the challenges it faces and future trends in the field.


In the oil and gas sector, reservoir engineering is the branch of petroleum engineering that focuses on optimizing the production of hydrocarbons from subsurface reservoirs. It involves the application of scientific and engineering principles to understand reservoir behavior, estimate reserves, and develop strategies for efficient hydrocarbon recovery.

What is Reservoir Engineering?

Reservoir engineering encompasses various aspects of reservoir characterization, fluid flow behavior, and production optimization. It involves studying the properties of reservoir fluids and rocks, analyzing drive mechanisms, evaluating reservoir performance, and implementing enhanced oil recovery (EOR) techniques. Reservoir engineers work closely with geologists, geophysicists, and production engineers to maximize reservoir productivity.

Engineering Objectives

Reservoir engineering seeks to economically optimize the development and production of hydrocarbon reservoirs. This requires answers to three questions:

  • How much hydrocarbon does the reservoir contain?
  • How much of it can be recovered?
  • How fast can it be recovered?

The answers to these questions give, respectively, the hydrocarbon in place, the reserves, and the rate of production. The determination of these three quantities is the heart of reservoir engineering.

Calculation of Oil and Gas in Place

Hydrocarbon in place is a fixed quantity that has developed through geological time. It may be estimated using volumetric or material balance methods. The volumetric calculation of hydrocarbon in place requires knowing the areal extent of the reservoir, its average net thickness and porosity, the hydrocarbon saturation, and the hydrocarbon formation volume factor (i.e., the volume that one unit volume of hydrocarbon at surface pressure and temperature occupies at reservoir conditions). It is a static method that does not depend on the dynamic behavior of the reservoir, that is, the pressure response to production. The equations for calculating the initial hydrocarbon in place (for two-phase oil/water and gas/water reservoirs, respectively) are

Initial oil in place (N),

N= C\ \dfrac{A\ h\ \phi \ (1-S_{wi})}{B_{oi}} ………… (1)

and Initial gas in place (G),

N= C \ \dfrac{A\ h\ \phi \ (1-S_{wi})}{B_{gi}} ………… (2)

where subscripts og, and w refer to oil, gas, and water, and

A = area of oil or gas reservoir.

h = average net thickness.

ϕ = average porosity, fraction.

Swi = average initial water saturation in the oil or gas zone.

Bo = oil formation volume factor, \tfrac{RB}{STB}.

Bg = gas formation volume factor, \tfrac{RB}{SCF}.

C is a constant whose value depends on the units in use, e.g.:

  • For N in STB, A in acres and h in ft, C = 7758
  • For G in SCF, A in acres and h in ft, C = 43560

The average quantities of hϕ, and S are normally determined from isopach maps constructed from geological, petrophysical, and log data.

The material balance method depends on the dynamic behavior of the reservoir. It requires accurate production and fluid properties data. Theoretically, the initial hydrocarbon in place (IHIP) determined by the material balance method should always be equal to or less than that determined volumetrically.

Estimation of Reserves

Reserves, unlike Initial Hydrocarbons in Place, are not invariant. Rather, they are affected by the production method planned for the reservoir. The most significant factor in determining the production method and hence the reserves is economics. The current oil price structure, the time value of investment capital, and the tax environment will determine how much oil can be economically recovered. Other factors that influence reserves are well location and spacing, production rates, and the drive mechanism of the reservoir.

Oil production can be said to take place in two phases: the primary recovery, and improved recovery. During the primary recovery phase, hydrocarbons are produced using only the natural energy contained in the reservoir. This primary recovery phase may be supplemented or followed by an improved recovery phase, in which energy is added to the reservoir by injecting water, gas or a combination of the two; or the addition of energy may involve more complex enhanced oil recovery (EOR) methods, such as miscible gas injection, chemical injection or thermal processes.

In the reservoir’s primary recovery phase, several sources of internal energy may contribute to fluid production. The five basic natural drive mechanisms drive mechanisms are

  • expansion drive
  • solution gas drive
  • gas cap drive
  • natural water drive
  • gravity drainage

In most cases, a combination of mechanisms is acting; we refer to this as a combination drive.

Prediction of Performance Potential

Production rate, like reserves, is a function of the reservoir development strategy. Primarily, it depends on the number and location of wells, the flow potential of each well, the capacity of the surface facilities, and market demand. The number of wells and their locations influence the production rate and the uniformity of the drainage pattern in the reservoir, and thus ultimate recovery. The productive potential of a well is a function of the permeability, thickness, pressure, and homogeneity of the reservoir rock. The greater the permeability, thickness, and degree of homogeneity, the higher the well potential. The flow rate is also a strong function of the drilling and completion practices. Mud invasion or restricted flow at the wellbore that is caused by an inadequate number of perforations or plugging will reduce the well’s overall potential.

Improved Recovery (Secondary and Enhanced Oil Recovery)

The improved recovery phase is primarily applicable to oil reservoirs. During this phase of production we are concerned with some type of artificial fluid injection rather than natural drive mechanisms. Thus, we talk about water injection or water flooding, miscible flooding, steam injection, surfactant injection, and the like. A common practice is to initiate the supplemental production phase with simple water or gas injection, which is commonly referred to as secondary recovery although it may be begun very early in the life of the reservoir. The water injection may then be followed with some type of miscible, chemical or thermal processes, which is known as enhanced oil recovery (EOR).

Recovery during the primary and secondary phases of a reservoir’s life seldom exceeds 50% of the original oil in place, so the potential recovery using EOR techniques is vast. Figure 1 presents a reservoir engineering functions diagram that summarizes the recovery techniques we have discussed.

Enhanced Oil Recovery (EOR) Techniques

Enhanced Oil Recovery (EOR) techniques are advanced methods employed by reservoir engineers to increase the amount of oil recovered from reservoirs beyond what can be achieved through primary and secondary recovery methods. These techniques are crucial for maximizing hydrocarbon extraction and improving overall reservoir performance. In this section, we will explore some of the commonly used EOR techniques.

  1. Water Flooding: Water flooding is a widely used EOR technique that involves injecting water into the reservoir to displace the oil towards production wells. The injected water helps maintain reservoir pressure and sweep the remaining oil towards the production wells, enhancing recovery rates.
  2. Gas Injection: Gas injection methods, such as gas flooding or gas injection, involve injecting gases, such as natural gas or carbon dioxide (CO2), into the reservoir. These gases help reduce the viscosity of the oil, increase reservoir pressure, and displace the oil towards production wells. Gas injection techniques are effective in reservoirs with high oil viscosity or in those where gas can be readily sourced.
  3. Chemical Flooding: Chemical flooding techniques involve the injection of chemicals into the reservoir to improve oil recovery. Surfactants, polymers, and alkalis are commonly used chemicals in this process. Surfactants help reduce interfacial tension between oil and water, polymers increase the viscosity of the injected fluid for better sweep efficiency, and alkalis aid in improving the mobility of the oil.
  4. Thermal Methods: Thermal EOR techniques utilize heat to improve oil recovery. Steam injection, the most common thermal method, involves injecting steam into the reservoir to heat the oil, reduce its viscosity, and improve its flow characteristics. Other thermal methods include in-situ combustion, where oxygen is injected to ignite the oil and create a combustion front that displaces the oil towards production wells.
  5. Microbial EOR: Microbial EOR techniques utilize microorganisms to enhance oil recovery. These microorganisms produce byproducts that help reduce the viscosity of the oil, increase reservoir permeability, and improve sweep efficiency. Microbial EOR is a promising technique, but further research is being conducted to optimize its effectiveness.
  6. Miscible Flooding: Miscible flooding techniques involve injecting fluids that mix and dissolve with the reservoir oil, resulting in the creation of a miscible displacement front. Common miscible fluids used are hydrocarbon gases, such as propane or butane, and CO2. Miscible flooding techniques are effective in reservoirs with favorable fluid properties.

It is important to note that the selection of an appropriate EOR technique depends on several factors, including reservoir characteristics, fluid properties, economic considerations, and environmental factors. Reservoir engineers conduct detailed reservoir studies and simulations to determine the most suitable EOR technique for a particular reservoir.

By employing EOR techniques, reservoir engineers can significantly increase the recovery factor of oil reservoirs, leading to improved resource utilization and enhanced production economics.

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FIGURE 1 Reservoir engineering functions diagram

All of these functions are integrated in order to arrive at a plan for the development of the reservoir.

Selection of the Best Development Plan in Reservoir Engineering

As we mentioned, the objective of reservoir engineering is the economic optimization of hydrocarbon recovery, which means we need methods for calculating production rate versus time for various recovery schemes and cost scenarios. The important considerations will be the number of wells and their locations, the surface facility capacities, the offshore platform locations (if needed), and the feasibility of employing EOR methods. Models are available to the reservoir engineer to allow the calculation of recovery for a variety of situations. These models fall into two categories: the tank-type (zero-dimensional) approach and the numerical model (or reservoir simulation) approach).

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