(E&P) Exploration, Drilling, and Oil Production—Part 2


The extraction of petroleum is the process by which usable petroleum is drawn out from beneath the earth’s surface location.

Primary subsurface production methods include cold production (horizontal and multilateral wells, waterflood, and cold heavy oil production with sand) and thermal production (cyclic steam stimulation, steam flood, and steam-assisted gravity drainage).

Crude oil production is defined as the quantities of oil extracted from the ground after the removal of inert matter or impurities. It includes crude oil, natural gas liquids (NGLs), and additives. ... NGLs are the liquid or liquefied hydrocarbons produced in the manufacture, purification, and stabilization of natural gas.

Petroleum production engineering covers the widest scope of engineering/ operations in the petroleum industry. It starts with the selection, design, and installation of the well completion and ends with the delivery of the useful fluids (i.e., oil and natural gas) to the customer. Between the two ends lie a large number of engineering activities and operations. For example, the design and installation of the well tubing and surface flowline, the workover operations w'hich keep the well at its best producing conditions, the selection and design of the oil/ gas production method and the design, installation, and operation of the surface separation and treatment facilities are all the responsibility of the petroleum production engineer.

The economics of most of the above-mentioned operations have to be evaluated before they are executed. In some cases, several technically viable alternatives would exist for executing a particular operation. In such cases, the decision to select one alternative over the others would be based entirely on economic evaluation of the various alternatives.

Following the introduction of each major production operation, economic-based decisions are presented. Applications and case studies illustrating the economic analysis in this strategic phase of the oil operations are given, with examples of the economic evaluation of some operations.

Over millions of years, layer after layer of sediment and other plants and bacteria were formed. As they became buried ever deeper, heat and pressure began to rise. The amount of pressure and the degree of heat, along with the type of biomass, determined whether the material became oil or natural gas.

The seven steps of oil and natural gas extraction are summarized as follows:

  • • Preparing the Rig Site.
  • • Drilling.
  • • Cementing and Testing. ...
  • • Well Completion. ...
  • • Fracking. ...
  • • Production and Fracking Fluid Recycling. ...
  • • Well Abandonment and Land Restoration.


Oil production methods are classified into the following categories:

a. PR: Reservoir drive comes from a number of natural mechanisms. These include:

  • • Natural water displacing oil downward into the well
  • • Expansion of the associated petroleum gas at the top of the reservoir
  • • Expansion of the associated gas initially dissolved in the crude oil
  • • Gravity drainage resulting from the movement of oil within the reservoir from the upper to the lower parts where the wells are located. Recovery factor during the primary recovery stage is typically 5-1

b. SR: It is the stage where there is insufficient underground pressure to force the oil to the surface. After natural reservoir drive diminishes, secondary recovery methods are applied. These rely on supplying external energy to the reservoir by injecting fluids to increase reservoir pressure, hence increasing or replacing the natural reservoir drive with an artificial drive.

To summarize, one can say that Secondary recovery techniques increase the reservoir’s pressure by water injection, gas reinjection, and gas.

c. ER: It is identified by increasing the mobility of the oil. Enhanced oil recovery methods (TEOR) are tertiary recovery techniques that heat the

ER. steam is injected into many oil fields where the oil is thick and heavy. Source

FIGURE 14.1 ER. steam is injected into many oil fields where the oil is thick and heavy. Source: en.vvikipedia.org > wiki > Extraction_of_petroleum

oil, reducing its viscosity, and making it easier to extract. Steam injection is the most common form of TEOR, and it is often done with a cogeneration plant (Figure 14.1).

By production method we refer to the way in which the well fluids are delivered to the surface. Ideally, wells should be produced to deliver the fluids to the surface with a wellhead pressure sufficient to force the fluid flow through all surface facilities. There are two ways in which a well may be produced; these are described here.


A well is said to be produced naturally if it only utilizes the naturally stored energy, i.e., reservoir pressure, to lift the fluids to the surface. Most wells start their lives with natural flow. With time, the reservoir energy (pressure) is depleted, resulting in reduced production rates or reduced wellhead pressure or both. When this occurs, artificial lift may be implemented.


Steam is injected into many oil fields where the oil is thicker and heavier than normal crude oil.

Artificial lift refers to the use of external means to help lift the well fluids from the bottom of the well to the surface. Essentially, artificial lifting enables well production at lower bottom-hole pressures. It may be applied on a flowing well to increase its production in order either to meet market demands or to make the project economics more attractive. Artificial lifting is mostly applied, however, to wells which otherwise would not produce at all or would produce below the economic limit of operation.


After a well has been drilled, it must be completed before oil and gas production can begin. The first step in this process is installing casing pipe in the well.

Oil and gas wells usually require four concentric strings of pipe: conductor pipe, surface casing, intermediate casing, and production casing. The production casing or oil string is the final casing for most wells. The production casing completely seals off the producing formation from water aquifers.

The production casing runs to the bottom of the hole or stops just above the production zone. Usually, the casing runs to the bottom of the hole. In this situation the casing and cement seal off the reservoir and prevent fluids from leaving. In this case the casing must be perforated to allow liquids to flow into the well. This is a perforated completion. Most wells are completed by using a perforated completion. Perforating is the process of piercing the casing wall and the cement behind it to provide openings through which formation fluids may enter the wellbore.


While safety and cost are of prime importance in selecting and designing a well completion, the engineer has to consider the following factors in finalizing his completion design:

  • • The type of reservoir and drive mechanisms
  • • The rock and fluid properties
  • • The need for artificial lift
  • • Future needs for stimulation and workover
  • • Future needs for enhanced recovery methods

Normally, the technical factors are first considered to determine possible completion designs; then, the economic aspects are considered to select the most economical design.


After cementing the production casing, the completion crew runs a final string of pipe called the tubing. The well fluids flow from the reservoir to the surface through the tubing. Tubing is smaller in diameter than casing—the outside diameter ranges from about 1 to 4-1/2 inches.

A packer is a ring made of metal and rubber that fits around the tubing. It provides a secure seal between everything above and below where it is set. It keeps well fluids and pressure away from the casing above it. Since the packer seals off the space between the tubing and the casing, it forces the formation fluids into and up the tubing.


The starting point in a completion design is determination of the production tubing (conduit) size. This is extremely important as it affects the entire drilling program and the cost of the project.

To determine the size of the tubing, the engineer has to conduct what is known as well performance analysis. This analysis requires the study of two relationships:

  • • The first one describes the flow' of fluids from the formation into the wellbore; it is called the inflow performance relation (IPR). The IPR is represented, normally, as the relationship between the bottomhole flowing pressure (Pwf) and the flow' (production) rate (q). Depending on the type of reservoir and the driving mechanism, the IPR may be linear or nonlinear, as illustrated in Figure 13.1. When the IPR is linear, it can be represented with what is called the productivity index (PI), w'hich is the inverse of the slope of the IPR.
  • • The second relationship describes the relation between the flow rate of fluids and the pressure drop in the production tubing. It is called the outflow performance or the tubing multiphase flow' performance. Several multiphase flow correlations exist for determining the relationship between flowrate and pressure drop in a well tubing. For a fixed wellhead pressure, the relationship between Pwf and q is as illustrated in Figure 14.2.

The interaction of the two relationships w'ould provide several solutions, as showrn in Figure 14.3. That is, several tubing sizes could be used, but each would yield a different production rate. Normally, higher production rates are obtained using larger tubing sizes; this means higher drilling and completion costs. The final selection of the tubing size should, therefore, be based on economic analysis of the various alternatives, as illustrated in Example 14.4.

Inflow performance relations (IPR)

FIGURE 14.2 Inflow performance relations (IPR).

Outflow (vertical flow) performance

FIGURE 14.3 Outflow (vertical flow) performance.

IPR and outflow performance for different production rate

FIGURE 14.4 IPR and outflow performance for different production rate.

14.9 WORKOVER OPERATIONS Example 14.1 (Another Case Study)

During field operations, the manager in charge is considering the purchase and the installation of a new pump that will deliver crude oil at a faster rate than the existing one.

The purchase and the installation of the new pump will require an immediate layout of $15,000. This pump, however, will recover the costs by the end of 1 year.

The relevant cash flows for the case as shown in Table 14.1.

If the oil company requires 10% minimum annual rate of return on money invested, which alternative should be chosen?


The present worth method is applied in solving this problem (see Chapter 6). Calculate the present worth for both alternatives, where:

Present worth = Present values of cash flows, discounted at 10%-Initial capital Investment

a. For the new pump: P.V. = (190,000)/1.1 = $172,727

b. For the old pump: P.V. = (95,000)/1.1 + (95,000)/(1.1)2

Based on the above results, keep the old pump. It gives higher Present Value.

TABLE 14.1

Data for Example 14.1





Install new (larger pump)




Operate existing (old pump)




TABLE 14.2

Data for Example 14.2


Net Present

Example 14.2 (Case Study)

The XYZ oil production company was offered a lease deal for oil wells on which the primary reserves are close to exhaustion. The major condition of the deal is to carry out secondary recovery operation using water-flood at the end of the 5 years. No immediate payment by the XYZ Company is required. The relevant cash flows are estimated as given in Table 14.2

Example 14.3 (Case Study: Economic Evaluation of a Gas Lift)

Economic evaluation of a gas lift well: Perform an economic analysis of placing a well on gas lift given the following data:

Well depth = 8,000 ft

Reservoir pressure (PR) = 2,400 psi and decreases 100 psi for each 200,000 bbl of oil recovery

Productivity index = 4 BPD/psi (initially) and then changes as 0.00143 PR Wellhead pressure = 120 psi (constant)

Injection gas pressure = 900 psi (from a central station)

Tubing size = 2.5 in Oil price = $80.00/bbl Injection cost = S0.5/MSCF Production cost = $2.5/bbl Maintenance cost = $1.0/bbl Pulling the well = 600,000 New equipment = 415,000


Based on the data given in Table 14.3, calculations are carried out as presented in Table 14.4

The payout period (P.O.P.) is calculated using the average annual cash flow over the 5 years period:

P.O.P = Depreciable Capital Investment/Average Annual Cash Flow The return on investment, on the other hand, is = 500%

TABLE 14.3

Comparison of Natural Flow and Gas Lift Wells


Average Rate, BPD

Increased Production

Injection Gas, MMSCF/year

Natural Flow

Gas Lift

Avg. Rate, BPD

Yearly bbl































TABLE 14.4

Results of Calculations for Placing the Wells on Gas Lift


Annual Gross Revenue x 10b

Injection Costs ($)

(Product.4- Maint. Costs) x 10b

Annual Net Revenue x10b

Net Cash x106

































Example 14.4 (Case Study: Orit Mynde-Tullow Oil and Gas Industry)

Source T4 Case Study - May 2014 Oil and gas case - CIMA www.cimaglobal.com > Documents > CBC > Case-Study

This Case Study Fits Chapter 14.

May 2014. (CIMA Global Business Challenge)

This case study is concerned only with upstream operations within the oil and gas industry. Most large international oil and gas companies are known as being "integrated" because they combine upstream activities (oil and gas exploration and extraction), midstream (transportation and the refining process), and downstream operations (distribution and retailing of oil and gas products).

Industry Background

This case study is concerned only with upstream operations within the oil and gas industry. The oil and gas industry comprises a variety of types of company including the following:

• Operating companies—these hold the exploration and production licenses and operate production facilities. Most of these are the large multinational companies which are household names.

  • • Drilling companies—these are contracted to undertake specialist drilling work and which own and maintain their own mobile drilling rigs and usually operate globally.
  • • Major contractors—these are companies which provide outsourced operational and maintenance services to the large operating companies.
  • • Floating production, storage, and offloading vessels (FPSO's)—these companies operate and maintain floating production, storage, and offloading facilities and look like ships but are positioned at oil and gas production sites for years at a time.
  • • Service companies—these outsourcers provide a range of specialist support services including test drilling, divers, and even catering services for off-shore drilling facilities.
  • • Licenses—all companies operating in the exploration and production (E&P) sector need to have a license to operate each oil and gas field.
  • • Each country around the world owns the mineral rights to all gas and oil below ground or under the sea within its territorial waters. The country which owns the mineral rights will wish to take a share in the profits derived from any oil or gas produced. This generates enormous revenues for these mineral rich countries.
  • • When an E&P company has identified by survey work a potential site (but before any drilling has commenced) it needs to apply for a license.
  • • Fields into production its awareness and track record in respect of environmental issues he company's financial capacity in respect of the investment required to bring the oil and gas field into production. When an E&P company has identified by survey work a potential site (but before any drilling has commenced) it needs to apply for a license.

Licensing [1]

Operation is on the Go

  • • Once a location has been identified and licenses obtained, then an offshore installation is setup. Oil and gas off-shore installations are industrial "towns" at sea, carrying the people and equipment required to access the oil and gas reserves hundreds or even thousands of meters below the seabed. YJ uses outsourced drilling teams and outsourced service personnel for these off-shore installations. YJ hires mobile drilling platforms and FPSOs as the cost of owning drilling platforms is too prohibitive.
  • • Oil and gas fields can be classified according to the reasons for drilling and the type of well that is established.
  • • "Test" or "Exploration wells" are defined as wells which are drilled purely for information gathering purposes in a new area to establish whether survey information has accurately identified a potential new oil and gas reserve. Test wells are also used to assess the characteristics of a proven oil or gas reserve, in order to establish how best to bring the oil and gas into production.
  • • "Production wells" are defined as wells which are drilled primarily for the production of oil or gas, once the oil or gas reserve has been assessed and the size of the oil or gas reserve proved and the safest and most effective method for getting the oil or gas to the surface has been determined.


This case study is concerned only with upstream operations within the oil and gas industry. This case study gives an example of a real world project. It illustrates many steps that take place in the oil and gas industry, e.g.. licensing. Oil and gas fields can be classified according to the reasons for drilling and the type of well that is established.

“Test” or “Exploration wells” are defined as wells which are drilled purely for information gathering purposes in a new area to establish whether survey information has accurately identified a potential new oil and gas reserve. Test wells are also used to assess the characteristics of a proven oil or gas reserve, in order to establish how best to bring the oil and gas into production.

The case study was presented to applicants as a sort of examination to answer.

  • [1] Licensing is conducted in differing ways in different areas of the world andthere are a variety of alternative types of license that can be applied for. • An E&P company could simply apply for a license to drill to identifywhether an oil and gas field exists and to establish the size of it before selling the rights to another company to then apply for a production license. • Alternatively an E&P company could apply for a production license,which allows it to drill and take the oil and gas fields into production.Licenses can be sold on to other companies but this is subject to approvalby the government that had issued the license. • The most commonly used form of licensing is through a "Production-Sharing Agreement" (PSA) license. A PSA license is where the government will take an agreed negotiated percentage share in the profitsgenerated by the production of oil and gas, i.e., revenues from the saleof oil and gas less the amortized cost of drilling, any royalty taxes (seebelow) and all of the production costs. Test Drilling Once an oil and gas field has been test drilled to determine the proven size of oiland gas reserves, production drilling can commence. The time taken from identification of a potential oil and gas field to the start of oil being produced normallyvaries between 1 and 3 year.
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