Learning Objectives

By the end of this lesson, you should be able to:

• name and describe the different reservoir fluids found in a hydrocarbon accumulation;
• identify and explain the roles of the different sectors in the modern oil and gas industry;
• name the products derived from oil and gas production;
• list and explain the roles of the different disciplines within the petroleum and natural gas engineering profession; and
• summarize the current and future challenges in the petroleum and natural gas engineering profession.

Lesson 1 Checklist

Checklist

To Read	Read the Orientation material   Read the Course Syllabus   Read Lesson 1: Introduction to Petroleum and Natural Gas Engineering	Located in the Orientation and Resources module in Canvas Located on the course website Located on the course website
To Do	Introduce yourself to the class in the Personal Introductions Discussion Board   Complete the Academic Integrity & Plagiarism Awareness Quiz   Complete the Orientation Knowledge Quiz	Located in the Orientation and Resources module in Canvas Located in the Orientation and Resources module in Canvas Located in the Orientation and Resources module in Canvas
Note	You must score 100% on the Academic Integrity & Plagiarism Awareness Quiz and the Orientation Knowledge Quiz to unlock the remaining Canvas lesson modules.

Please refer to the Calendar in Canvas for specific time frames and due dates.

Questions?

If you have questions, please feel free to post them to the Course Q&A Discussion Board in Canvas. While you are there, feel free to post your own responses if you, too, are able to help a classmate.

The word “Petroleum” has its origin in the Greek words “petra” for “rock” and “oleum” for “oil”. Petroleum, or crude oil, is a naturally occurring liquid found in porous rocks (reservoirs) below the earth’s surface. It is an organic material comprised of hydrocarbon molecules (molecules formed by hydrogen and carbon atoms) with possible inorganic contaminates, such as nitrogen (N₂), carbon dioxide (CO₂), hydrogen sulfide (H₂S), and others.

Crude oil is found in subsurface rock formations known as oil reservoirs. It is typically found in the presence of natural gas (associated natural gas). Associated natural gases are hydrocarbon gases that co-exists with the crude oil and may be present as: (1) gas dissolved in the crude oil (solution gas), (2) a distinct gas phase in contact with the crude oil (free gas), or (3) both. Natural gas may also exist with no crude oil present (non-associated gas) in natural gas reservoirs. In the context just described, the terms “associated gas” and “non-associated gas” refer to the association of the gas with a liquid hydrocarbon phase. This is illustrated in Figure 1.01.

The role of the International and U.S. Domestic Oil and Gas Industries is to perform the safe, environmentally sound, and efficient discovery, extraction, transport, refining, and marketing of petroleum and natural gas and their refined products. Petroleum and natural gas engineers typically work to extract the crude oil and natural gas from the subsurface reservoirs and also have a secondary role supporting exploration geologists in the discovery of new oil and gas reservoirs.

The oil and gas industry can be classified into three broad segments: the upstream, the mid-stream, and the downstream sectors of the industry. This classification system is based on the direction in which crude oil and natural gas flow from the subsurface reservoirs (upstream sector) to the refineries and the markets (downstream sector) and, eventually, the consumers.

The upstream sector of the oil and gas industry is responsible for the discovery, extraction, and field processing of the crude oil and natural gas. As such, petroleum and natural gas engineers typically work in this sector of the industry. In this sector, petroleum and natural gas engineers work with geologists, geophysicists, other engineering disciplines (e.g., mechanical and chemical engineers), and other petroleum professionals (e.g., petrophysicists, paleontologists, etc.) to extract the crude oil and natural gas and to process the produced fluids to the specifications required by the field export systems (pipelines, tanker ships, etc.).

The mid-stream sector of the oil and gas industry is responsible for the export of the crude oil and natural from the field locations and for the transport of these products to the refineries. These refineries may be continents away from the original oil and gas fields. This transport process may occur onshore using pipelines, trains, or tanker trucks; over oceans and seaways using large tanker ships; and on inland lakes and waterways using smaller barges.

The downstream sector of the industry is responsible for the storage, refining, and marketing of the refined products to the consumers. Storage of the oil and gas may occur on the surface in “tank farms,” underground in old, abandoned oil and gas reservoirs, or in engineered, subsurface formations (e.g., hollowed out salt caverns). Storage may be required for crude oil as an unrefined inventory awaiting processing in a refinery or for storage as a refined product during seasonal lows in demand caused by the weather (e.g., heating fuels). Refining is the process of converting raw crude oil and natural gas into products in demand by industrial or individual consumers.

The international and U. S. domestic oil and gas industries form an integral part of the global economy. Oil and gas production influence all industrial sectors and geographical regions of the world, either as producers, consumers, or both. Figure 1.02 shows the energy mix in the United States by major primary energy source in 2015.

Global energy consumption (Figure 1.03) has a comparable energy mix as in the U.S..

Besides providing fuels to run automobiles, planes, ships or machinery, the primary energy sources shown in Figures 1.02 and 1.03 are also used to power electrical generation plants to provide secondary energy sources to consumers.

In addition to fuels, refined crude oil and natural gas provide other valuable products including kerosene for illumination, lubricants for machinery, butane and propane for recreational and industrial uses, asphalts for road construction, and feedstocks for the petrochemical industry. Figure 1.04 shows the typical product yield from a standard 42 gallon barrel of crude oil.

The petroleum and natural gas engineering profession is normally divided into three major areas of specialization based on the tasks assigned to the engineer. These areas are: Drilling or Drilling and Completions (D&C) Engineers, Production Engineers, and Reservoir Engineers.

Drilling Engineers, or Drilling and Completions Engineers

Drilling Engineers, or Drilling and Completions Engineers, are responsible for planning, designing, and executing the drilling operations of a well. Drilling a well may take several years to properly plan. This is because of the depths and quality of the steel tubulars (drill pipe, casing, and production tubing) that are required by the oil and gas industry. For example, a ten-well drilling campaign to a total depth of 12,000 ft per well in a high temperature, high pressure, highly corrosive environment will take several miles of high-grade steel tubulars which cannot be purchased “off-the-shelf” from steel manufactures. These items are “Long Lead Time” items in the well design and must be considered years in advance of the actual drilling operations. In fact, an aggressive drilling campaign in a single oilfield may exhaust the world’s supply of a particular steel grade for several years. Coordinating the design of the well with the suppliers of the well components is an integral part of the planning process performed by the drilling engineer.

During drilling operations, the drilling engineer must also determine the appropriate drilling fluids to use to allow for safe drilling operations and select the appropriate drill bits to use to allow for optimal drilling efficiency (cost, speed, etc.). The drilling engineer must also decide on the appropriate depths to set casing and the appropriate steel grades of the casing to protect both the wellbore and the environment (Casing is used to isolate the well from the various geologic rock formations and aquifers that a well encounters and to isolate the individual rock formations from each other.).

Once the wellbore has reached the predetermined total depth and the final casing string has been cemented in place, the drilling engineer works with the production engineer to implement the well’s completion. The well completion is the portion of the well that connects the wellbore to the reservoir. This aspect of the well design has many considerations in order to achieve the long-term objectives of the well. Important considerations of a completion design include: selecting the appropriate size and grade of the production tubing; determining the need to stimulate the reservoir (hydraulic fracturing, acidizing, etc.) to allow for economical production rates from the reservoir to the well, and selecting the appropriate artificial lift system (natural lift, pump, gas lift, etc.) to aid in “lifting” the produced fluids from the reservoir to the surface.

Production Engineer

The role of the Production Engineer is to monitor individual wells or groups of wells to ensure that they are producing (or, in the case of injection wells, injecting) optimally. Over time, downhole equipment may fail, produced hydrocarbons fluids may deposit waxes or asphaltenes on downhole equipment and tubing, minerals in produced water may create a scale on downhole equipment and tubing, steel tubing may corrode or erode, etc. All of these phenomena can negatively affect the performance of the well. In addition, due to changing reservoir conditions, equipment and tubing sizes that were optimal at the beginning of production may be suboptimal at depleted reservoir conditions.

To monitor wells, production engineers may install permanent downhole sensing equipment to continuously observe well performance in real time. In addition, the production engineer may perform discrete tests on the well by sending monitoring tools down the well to observe well performance as a “snapshot in time.” These discrete tests can either be (1) well logs, where tools are sent downhole that measure properties of interest to the engineer such as flow rates, temperatures, internal tubing diameters etc., or (2) well tests, where pressure gauges are sent downhole, well rates are adjusted in a controlled, known manner, and the corresponding pressure responses are recorded and analyzed. The analysis of the pressure responses during a well test provides a valuable insight into the near-well performance of the reservoir.

If a problem is identified with the well, it is then up to the production engineer to determine the appropriate remedial actions to resolve the issue. These well remediations may take the form of simple “wireline workovers” or more complex “major rig workovers (MRWO).” In a wireline workover, all work is performed with tools lowered into the well at the end of an electrical cable (wireline). Using a wireline, perforations (connections to the reservoir) can be added, tubing plugs can be set or retrieved, packers (downhole equipment used to isolate reservoir zones) can be set or retrieved, valves can be opened or closed, etc. In a major rig workover, a drilling rig or specialized workover rig is moved on location above the well and is used to re-enter the well to retrieve the original tubing or completion equipment, cement off depleted reservoir zones (to establish zonal isolation), or to restimulate the well.

In addition to monitoring wells and performing well remediations, production engineers look after the artificial lift systems used in the well. Typical artificial lift systems include beam pumps (see Figure 1.05), downhole electrical submersible pumps (ESPs), or gas lift.

By the nature of their jobs, production engineers interact with oilfield service providers to ensure that the appropriate technologies are applied to optimize well production or injection.

Reservoir Engineers

While production engineers focus on individual wells or groups of wells, Reservoir Engineers attempt to optimize production of the reservoir as a whole. Reservoir engineers work with geologists, drilling engineers, and production engineers to ensure that the entire reservoir system is running optimally. Typical tasks performed by reservoir engineers include: working with geologists to determine the original-oil-in-place in the reservoir and identifying future well locations; identifying the drive mechanisms (the physical phenomena which cause the oil and gas to migrate to the production wells); estimating the reservoir reserves (volumes of oil and gas that can be technically and economically extracted from the reservoir), recommending the appropriate development plans for a reservoir (and recognizing when it is time to modify a plan); forecasting future production and injection rates from the reservoir in its entirety; and determining the need for applying Improved Oil Recovery (IOR) or Enhanced Oil Recovery (EOR) methods.

Typically, petroleum engineering students have the option to choose which of these areas of specialization they would like to undertake during their careers; however, the Law of Supply and Demand also works in the petroleum and natural gas engineering job market. For example, a company in need of the services of Production Engineers will hire engineers with this particular skill set. Consequently, some degree of flexibility among these three areas of specialization is required when searching for an entry-level position in the oil and gas industry.

The modern approach to crude oil and natural gas extraction is the Reservoir Management approach. Reservoir Management is a team based methodology in which all disciplines (geologists, drilling engineers, production engineers, reservoir engineers, and other petroleum professionals) work together toward the common goal of efficient, safe, and environmentally friendly production of oil and gas.

Current status and future challenges of Reservoir Management can be summarized with the Resource Triangle ^[1]. Figure 1.06 shows the current status of Reservoir Management in the Resource Triangle. In this figure, the easy-to-produce resources (crude oil and natural gas) are at the top of the triangle. These resources are characterized by good, high-quality reservoir rock (high storage capacity and ability to easily transmit fluids) which are saturated with highly mobile (easily flowing) fluids. The base of the triangle represents the more difficult-to-produce or yet to be discovered resources. While the resources at the base of the triangle are more difficult to find and extract, they can still be produced at higher energy prices (allowing for more capital to be spent to find, drill, and apply cutting-edge technologies for their extraction) or with improvements in current technology.

Figure 1.06 also illustrates the status of producing assets in known, mature basins. Due to the time-scales of oil and gas production, we are still producing from fields that were discovered in the early to mid-twentieth century. Consequently, some of the equipment installed in the field may be legacy equipment (then-current technologies) and all of the pre-production, baseline data for these fields were acquired using legacy data acquisition technologies. This is the situation in which many newly graduated petroleum and natural gas engineers may find themselves. Consequently, these engineers must be well versed in past, present, and emerging production technologies and analysis techniques.

The Resource Triangle can also be used to illustrate the future challenges in Reservoir Management, as in Figure 1.07.

Figure 1.07 shows the same “easy-to-produce” and “difficult-to-produce” resources as in Figure 1.06. All of these resources, including the “easy-to-produce” resources, have various challenges associated with them. It is the role of petroleum and natural gas engineers to devise cost-effective solutions to these challenges.

Typically, even in the best quality reservoirs, only one-third of the original-oil-in-place can be recovered using conventional production technologies (typically 30 – 35 percent recovery efficiencies). Recovery efficiencies for natural gas reservoirs are normally much greater (typically 65 – 85 percent recovery efficiencies). The remaining in-place oil and gas after the application of conventional production technologies, therefore, represents a significant target for additional recovery.

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[1] Reference: MRS Bulletin: Factors That Will Influence Oil and Gas Supply and Demand in the 21st Century [7]

Improved Oil Recovery (IOR) and Enhanced Oil Recovery (EOR) Methods are methods used to target the resources not capable of being produced with conventional production methods. IOR is defined as any recovery method used to improve oil recovery above the use of non-stimulated, naturally-flowing vertical production wells (Please note that with this definition, each reservoir will have a different baseline because each reservoir will respond differently to the application of these wells). This baseline represents the simplest production technology available to the petroleum and natural gas engineer and was a common development option up to the 1960s – 1970s and often resulted in recovery efficiencies of less than ten percent.

This definition of IOR encompasses a wide variety of production technologies including additional vertical wells (infill drilling) or complex well designs (deviated, or slanted, wells; horizontal, or single-lateral, wells; multi-lateral wells), well stimulation (hydraulic fracturing and acidizing), artificial lift (beam pumps, ESPs, and gas lift), secondary recovery methods (waterflooding and gas flooding), and EOR (thermal recovery, miscible displacement, and chemical flooding).

This definition of IOR allows for the use of additional vertical wells for greater well coverage (infill drilling) than considered in the initial development plan or the use of more complex well designs to improve well performance from a single surface location. Figure 1.08 shows some of the more advanced well designs used in the current Reservoir Management. As discussed earlier, the design and execution of these complex wells is the task of the drilling engineer.

Well Stimulation

Well stimulation is an IOR technology that is used to clean well perforations and improve the flow capacity of the reservoir rock in the near-well vicinity. The two most common well stimulation methods are hydraulic fracturing and acidizing. Hydraulic fracturing, or frac’ing, refers to the high-pressure injection of a fracturing fluid, typically water (slickwater), gas, or gel, into a reservoir causing the rock to mechanically fail or fracture. Injection of the fracturing fluid is normally followed by the injection of a proppant slurry, composed of natural sand or man-made ceramic beads, used to prop-open the induced fractures once pressure is relieved after the well stimulation treatment. Hydraulic fracturing can be applied to most rock lithologies, including sandstones, carbonates (limestones and dolomites), coals, and shales.

Acidizing

Acidizing is a well technology that uses the injection of an acid solution into a porous reservoir to dissolve any residual drilling fluids or natural sediments in the well perforations and the near-well vicinity. These residual drilling fluids may impair fluid flow to the well. Several variations of the acidizing process are used to stimulate a well including: matrix acidizing where the acid solution is pumped into the reservoir below the fracture pressure (or parting pressure) to clean pores near the well and acid-fracturing where an acidic fracturing fluid is injected above the fracture pressure in order to simultaneously fracture the reservoir and dissolve the formation (creating flow channels linking the rock to the fracture). Matrix acidizing is typically used in sandstone and carbonate reservoirs; while acid-fracturing is used in carbonate reservoirs which are susceptible to breakdown by acid.

Artificial Lift

Artificial lift was discussed briefly and is defined as an IOR technology used to ”lift” reservoir fluids once they enter the well. Early in the life of a well, the natural pressure in the reservoir is great enough to overcome gravity and to push fluids to the well and up the well to the surface. This is referred to as natural flow or natural lift.

As pressure is depleted from the reservoir by the withdrawal of oil, gas, and water (comparable to letting the air out of a balloon), the natural energy in the reservoir can no longer overcome the weight of the produced fluids and cannot force them up the production tubing. At this point, the application of artificial lift is required to keep the well flowing. A second situation may also occur which requires the application of artificial lift. As oil and gas are produced from the reservoir, these fluids are often replaced by increasingly greater volumes of produced water. The produced water is a much heavier fluid than the oil and gas and the fluid column in the well may become too heavy to flow by natural means. When this occurs, artificial lift is required to continue to produce the well. As discussed earlier, the tasks of well stimulation and artificial lift fall to production engineers.

Secondary Recovery

Secondary Recovery is an IOR process used for increasing the recovery efficiency of many oilfields. In this context, Primary Recovery refers to Reservoir Management processes which deplete the reservoir energy from the natural drive mechanisms associated with the reservoir. In secondary recovery, water or natural gas are injected into the reserve to provide an external source of reservoir energy. Waterflooding is the most common form of secondary recovery used for crude oil production.

The terms, Primary Recovery and Secondary Recovery, refer to the historical order in which oil production techniques were applied. Primary recovery was typically applied as a first stage of development to take advantage of the natural drive mechanisms in the reservoir; while secondary recovery was applied at a later stage of development to supplement the depleted natural drive mechanisms. Reservoir Engineers typically determine the design and timing of the secondary recovery operations. Most oil reservoirs require some form of secondary recovery to achieve recovery efficiencies in the range of 30 – 35 percent.

Enhanced Oil Recovery, or Tertiary Recovery

In Figure 1.07, Enhanced Oil Recovery (EOR), or Tertiary Recovery, is also applied to large reservoirs. EOR involves the injection of fluids into the reservoir, which aids in crude oil production by means other than simply supplying external reservoir energy. The baseline for EOR is the incremental production after primary and secondary production. Note that this definition of the baseline for EOR differs from that for IOR. As the terminology implies, “Tertiary Recovery” technologies were historically used after primary and secondary recovery.

The type of EOR technology to be applied to a given reservoir depends on the nature of the reservoir and the fluids that it contains: polymer solutions can be used to improve the efficiency of a waterflood; miscible fluids or surface active agents (surfactants, or soup solutions) can be injected to reduce capillary forces (one of the forces that entrap crude oil in the capillaries in the reservoir); or steam can be injected into heavy oil reservoirs to reduce the viscous forces (another force that entraps crude oil) required to displace the oil. Again, the design and timing of an EOR project typically fall to the reservoir engineer.

Figure 1.07 also illustrates a current trend in Reservoir Management: the use of “Smart Technologies.” Smart technologies are capable of sensing changing reservoir conditions and modifying production characteristics in real time to continuously improve reservoir performance.

The very base of the Resource Triangle, “Emerging Frontiers,” may sound somewhat exotic; however, the last “emerging frontier” in the oil and gas industry occurred in western Pennsylvania. This was the Shale Boom that began in the mid-2000s.

It was the application of hydraulic fracturing, in conjunction with the application of the more complex, multi-lateral well designs, which made shale reservoirs commercially viable. One such shale formation, the Marcelus shale, is a massive oil and gas bearing formation located in western Pennsylvania, Ohio, West Virginia, and New York. Oil and gas production from the Marcellus shale, along with the Barnett shale (Texas), Bakken shale (North Dakota), and the Eagle Ford shale (Texas) have significantly reduced the dependency of the United States on foreign energy sources during the last decade and is projected to continue to produce for decades to come. As with all aspects of energy production, the longevity of the shale boom will depend on future oil and gas prices.

Throughout history, the engineering profession has played a pivotal role in generating growth and improving the quality of life of society. Due to its very nature, the engineering profession requires strict ethical standards to continue providing this growth in sustained, principled manner. The National Society of Professional Engineers has codified these ethical standards into its Code of Ethics. This ethical code is provided in the following three links:

• National Society of Professional Engineers Code of Ethics for Engineers [9] (website)
• National Society of Professional Engineers Code of Ethics for Engineers [10] (pdf)
• National Society of Professional Engineers Ethics Reference Guide [11] (pdf)
• The Society of Petroleum Engineers also has a website devoted to its Professional Code of Conduct [12]

In light of Climate Change and Global Warming, one aspect of engineering ethics that is becoming more critical to the petroleum and natural gas engineering profession is environmental stewardship. Environmental stewardship refers to the use of conservation and sustainable practices to protect the environment. This is done by using modern best practices to:

• Reduce oil spills and gas emissions with the goal of eliminating them altogether
• Minimizing the environmental footprint of all oil and gas extraction operations
• Minimizing gas flares (intentional burning of natural gas to the environment) with the goal of eliminating them altogether (Note, often a minimal amount of gas may need to be flared to act as a pilot light as part of the safety system required for some oil production operations)
• Protecting freshwater aquifers and ground water used by humans and wildlife

Summary

In this lesson, we learned about the basics of the modern oil and gas industry. In particular, we learned that naturally occurring hydrocarbons exist in subsurface, porous rock formation called reservoirs. We also learned that these naturally occurring hydrocarbons can be found as liquids (crude oil) or as gases (natural gas).

In addition, we learned about the structure of the oil and gas industry. The modern oil and gas industry is broadly composed of three sectors based on the role that sector plays in delivering petroleum products to consumers. These sectors are:

• the upstream sector: responsible for the discovery and extraction of hydrocarbons from the subsurface reservoirs;
• the mid-stream sector: responsible for transporting oil and natural gas from remote oil and gas fields to refineries and markets; and
• the downstream sector: responsible for the storage, refining, and marketing of refined products.

We also discussed the three disciplines in petroleum engineering and their roles in the industry. These petroleum engineering disciplines are:

• drilling engineering: responsible for planning and drilling all wells in the field;
• production engineering: responsible for monitoring and remediating individual wells to ensure that they are producing or injecting at their optimal potentials; and
• reservoir engineering: responsible for planning and implementing development plans for the oil and gas fields.

In addition, we briefly discussed the career potentials of up and coming petroleum engineers. We learned that petroleum engineers are typically hired into the upstream sector of the industry. In addition, with the aid of the resource triangle, we discussed some of the challenges that future petroleum engineers can expect to take on during their careers in the oil and gas industry.

Finally, we discussed the ethics of the engineering profession, in particular, petroleum and natural gas engineering.  We also discussed Environmental Stewardship and its role in crude oil and natural gas extraction.

Final Tasks

Overview

Petroleum and natural gas are found within the pore-spaces of porous rock which forms the crude oil and gas reservoirs. Typically, the oil and gas are found with saline water which may be mobile or immobile. This is in contrast to the popular belief that crude oil is found as “oceans of oil” in vast underground caverns. The pore-space in porous rock is identical to the pore-space found within the sand grains of beach sand.  If you were to dig a hole in the sand at the beach and fill it with ocean water, then that water would eventually drain out of the bottom of the hole and migrate through the sand back to the ocean.  Oil and gas storage and transport are identical to the storage and transport of ocean water in beach sand. In fact, the physical laws that govern the storage and transport of fluids in porous rock and unconsolidated sand are identical.

Learning Objectives

By the end of this lesson, you should be able to:

• illustrate the types of geologic structures where crude oil and natural gas accumulate and/or exit;
• list the five elements that are required to form a hydrocarbon reservoir;
• describe the rock characteristics that are typically associated with hydrocarbons;
• explain the process by which hydrocarbons pass from source rock to reservoir trap;
• describe the geologic properties that make up a reservoir rock and what properties determine the commercial quality of the reservoir rock;
• identify the four hydrocarbon types that make up crude oil and natural gas;
• apply the Gibbs Phase Rule and explain how it governs the phase behavior of complex hydrocarbon mixtures;
• explain how the local hydrostatic gradient and thermal gradient determine the pressure and temperature of a hydrocarbon reservoir at discovery; and
• summarize how the location of the original pressure and temperature of the reservoir within the phase envelope of the phase diagram determines the type of crude oil or natural gas system that will be produced from the reservoir.

Lesson 2 Checklist

Lesson 2 Checklist

To Read	Lesson 2: Origin and Occurrence of Hydrocarbons	Click the Basic Earth Geology link below to continue reading the Lesson 2 material
To Do	Submit the Lesson 2 quiz	Located in the Lesson 2 module in Canvas

Please refer to the Calendar in Canvas for specific time frames and due dates.

Questions?

If you have questions, please feel free to post them to the Course Q&A Discussion Board in Canvas. While you are there, feel free to post your own responses if you, too, are able to help a classmate.

Since the occurrence of crude oil and natural gas are intrinsically associated with reservoir rocks, we must start our discussion of the origin and occurrence of natural hydrocarbons with petroleum geology. Geology is the study of all processes that affect the earth. The earth processes studied by geologists occur at many scales from those at the planetary scale (plate tectonics; interactions between the earth’s core, mantle, and crust; etc.) to those at the grain and pore scale (formation of the cementation that binds sand grains, swelling of clays in pores, etc.). Figure 2.01 shows a schematic diagram (not to scale) of the Earth’s Structure.

Through radiometric dating, the earth is believed to be approximately 4.54 billion years old. As shown in Figure 2.01, it is composed of an inner and outer core, the mantle, and the crust. The earth’s crust is the thin, solid, outer shell of the planet that we live on and interact with on a daily basis. The earth’s crust accounts for approximately 1% of the total volume of the planet.

The solid crust is the upper layer of the lithosphere (the lithosphere is composed of rigid crust and upper portions of the semi-elastic mantle). The earth’s crust can be further divided into the oceanic crust and the continental crust. The oceanic crust is between 3 miles (5 km) and 6 miles (10 km) thick and is overlain by approximately 3 miles of seawater; while the continental crust is between 20 miles (30 km) and 30 miles (50 km) thick. Underlying the oceanic crust and the continental crust is a layer of basalt. Because both the oceanic crust and the continental crust are less dense than the mantle, they both “float” on the mantle.

This floating of the crust on the mantle gives rise to the widely accepted theory of Plate Tectonics. Plate Tectonics is the theory that describes the motion of the continents over the geologic time scale. In this theory, the lithosphere is broken into several major tectonic plates and many smaller plates. The major plates are associated with one of the continents. Slow moving convection currents in the upper mantle are the primary driving mechanisms of plate tectonics; while other mechanisms related to gravity are considered to be secondary driving mechanisms. This is illustrated in Figure 2.02.

In this figure, four tectonic plates are shown along with the convection currents that are driving their drift. The direction of the tectonic drift is shown by the arrows. The separation of tectonic plates is referred to as rifting and is caused by the spreading of two or more convection currents. The mid-Atlantic Ridge is an example of rifting zone. Subduction of tectonic plates, where one plate slides below another plate, results when two or more tectonic plates traveling towards each other collide. The resulting zone is called a subduction zone. A third type of plate boundary, where one plate grinds past another plate, is called a transformational boundary. An example of a transformational boundary is the San Andreas Fault where the Pacific Tectonic Plate is moving across the North American Tectonic Plate.

Due to the friction and built-up stresses in subduction zones and transformational boundaries, these plate boundaries are often associated with volcanism and earthquakes. In fact, the “Ring of Fire” which surrounds the Pacific rim and the North American west coast is caused by the movement of tectonic plates interacting with the Pacific Tectonic Plate.

Rift zones and subduction zones are the only locations where mass transfer from the crust to the mantle (and vice versa) can occur. At a rift zone, fresh rock materials are expelled from the mantle; while at a subduction zone, weathered rock material is returned to the mantle. As we will see, this forms an integral part of the Rock Cycle.

There are three primary rock types present on the earth: igneous, sedimentary, and metamorphic rocks.

Igneous rocks are rocks formed by the cooling and solidification of molten rock material. As such, igneous rocks are associated with volcanology. There are two types of igneous rocks, intrusive igneous rocks and extrusive igneous rocks. Intrusive igneous rocks crystalize below the earth’s surface, allowing for slow cooling and the development of large crystal structures, while extrusive igneous rocks crystalize on the surface, resulting in rapid cooling and the development of small crystal structures. Examples of intrusive igneous rocks include diorite, granite, and peridotite; while examples of extrusive igneous rocks include basalt, pumice, and tuff.

Sedimentary rocks are rocks formed by the accumulation of sediments. There are three types of sedimentary rocks: clastic sedimentary rocks, chemical sedimentary rocks, and organic sedimentary rocks. Clastic sedimentary rocks are rocks formed by the accumulation of debris that has been mechanically broken by earth processes such as weathering and erosion. Examples of clastic sedimentary rocks include sandstones, siltstones, and shales. Chemical sedimentary rock are rocks that are formed by the precipitation of dissolved materials from high mineral content brines. Examples of chemical sedimentary rocks include rock salt, chert, some limestones, and some dolomites. Finally, organic sedimentary rocks are formed from the accumulation of organic materials (dead plants or animals). Examples of organic sedimentary rocks include coal, some limestones, and some dolomites.

Metamorphic rocks are rocks that started as some other rock type (igneous or sedimentary) but have been substantially altered from their original form by excessive heat, pressure, or exposure to high mineral content brines (or combinations of these three mechanisms). Examples of metamorphic rocks include marble, gneiss, and schist.

As stated in the introduction section of this lesson, crude oil and natural gas reside in the pore-spaces between the grains that make up the rock fabric of the reservoir rock. Consequently, the overwhelming majority of hydrocarbon reservoirs occur in sedimentary rocks where the pore-spaces in the accumulated sediments are sufficiently large to allow for the storage of crude oil and natural gas. While the pore-spaces in metamorphic and igneous rocks are too small to allow for the entry of hydrocarbon molecules, if these rock formations are mechanically fractured by tectonic forces, then the space created by the natural fractures can allow for hydrocarbon storage, and fractured reservoirs in metamorphic and igneous rocks are possible.

It should be emphasized that the formation of rock is not a static process, but is more of a dynamic, cyclical process. In other words: when a rock is formed, it is continually acted upon by earth processes and is subject to change over the geologic time-scale. This process is referred to as the Rock Cycle and is illustrated in Figure 2.03.

The study of the geological processes that create crude oil and natural gas reservoirs is referred to as Petroleum Geology. In this discussion, we will also need to include brief discussions of related, specialized areas of geologic study including Stratigraphy and Structural Geology. Stratigraphy is the study of the layers (or strata) within rock formations; while Structural Geology is the study of the deformation of rock under tectonic forces. You are probably most familiar with the concepts of stratigraphy and structural geology from road-cuts seen along highways. These road-cuts often show cross-sectional outcrops of layered, deformed rock formations along the road-side. The layering you see is the local geologic stratigraphy; while the deformations you see form the local geologic structure of the rock formations.

Figure 2.04 shows a road-cut along Route 322 approximately 39 miles south of State College, PA. In this photograph, the layering (stratigraphy) and deformation (structure) of the Keefer Formation (Silurian Age) are clearly evident. The “inverted bowl-shaped” feature in this photo is an anticlinal structure, or simply an anticline. Anticlines statistically form the most common crude oil and natural gas reservoirs. We will discuss this in more detail when we discuss Reservoir Traps later in this lesson.

As we have already discussed, hydrocarbon reservoirs are typically associated with sedimentary rock formations. Over geologic time, weathered and eroded rock materials are carried downstream from elevated regions to lower regions in rivers and streams to oceans, seas, or lakes. At the point in the rivers, oceans, seas, or lakes where the energy in the water can no longer suspend or transport the rock material, it begins to settle in the water and is deposited onto the bottom of the water body. This is called the depositional process. During the depositional process, the environment can change over the geologic time scale: mountain tops and hilltops erode, sea-levels rise or lower, etc. With these changes, the types of sediments that are deposited change and the locations where they are deposited also change. Two commonalities that exist during the depositional process, even over the geologic time scale, are (1) the sediments and, consequently, the sedentary rocks that are lower in the stratigraphic column were deposited earlier than sediments higher in the stratigraphic column and (2) the layers of sediment are initially deposited horizontally. From this discussion, we can see that sediments lower in the stratigraphic column must be older than those higher in the stratigraphic column.

Note, a stratigraphic column is a written, pictorial, or schematic record of the local rock strata showing the order of the rock deposition (older rocks at the bottom and younger rocks at the top), along with notes concerning the age of the rocks, occurrence of any fossils, any rocks which may be absent from the local geological record due to erosion, or any notes of use to a geologist. One example of a stratigraphic column that you may be familiar with is The Obelisk on the University Park Campus of Penn State. The Obelisk is a physical column constructed of quarried building materials from Pennsylvania with the older rocks placed at the base of the column and the younger rocks placed at the top of the column. Consequently, it forms a true stratigraphic column of the building stones of Pennsylvania. A photograph of The Obelisk is shown in Figure 2.05.

From this discussion, we can also see that in their original, natural state, sedimentary rocks are horizontal. Any deformation (folding, uplifting, tilting, faulting, etc.) in sedimentary rock formations is caused by tectonic forces acting on the rock after deposition and solidification.

There are five geological requirements for the formation of a conventional hydrocarbon reservoir:

1. Source Rock
2. Migration Path
3. Cap Rock
4. Reservoir Rock
5. Trap

These geological requirements are illustrated in Figure 2.06. It needs to be emphasized that although this figure consists of solid colored bands, these bands represent either porous or non-porous rocks. In the following discussions, all of the action concerning this figure is occurring in the pore-spaces of porous rock.

In this figure, the Source Rock is represented by the light grey layer. This is the rock in which the original organic material is converted into hydrocarbons. We will discuss this process later in this lesson. As we can see from this figure, the hydrocarbons do not necessarily originate in the hydrocarbon reservoir itself but are generated away from the reservoir in rocks that are conducive to hydrocarbon generation. As we will discuss later, these source rocks are typically organic-rich shales, siltstones, or coals.

Since the hydrocarbons are generated away from the reservoir, there must be a pathway for the hydrocarbons to migrate from the source to the reservoir. This pathway is the Migration Path in the hydrocarbon system. In the example shown in Figure 2.06, the migration path is a water-filled rock layer (aquifer) that is in communication with both the source rock the hydrocarbon bearing reservoir. This aquifer is shown as the blue layer in Figure 2.06.

In Figure 2.06, the solid green arrows represent the primary migration of the hydrocarbons, while the dashed green arrows represent the secondary migration of the hydrocarbons. Primary migration refers to the initial expulsion of the hydrocarbons from the source rock, while secondary migration refers to the remainder of migration to the reservoir.

As shown in this figure, all fluid migration is upward. This is because the main driving mechanism in hydrocarbon migration is buoyancy, which occurs because the oil and gas are less dense (lighter) than the resident water. In order to prevent this buoyant flow from occurring all of the way to the surface, a vertical flow barrier, or Cap Rock, is required along the migration path and at the reservoir itself. A cap rock is simply an overlying rock layer that is impermeable to flow. Permeability is a property of the rock that is a measure of the ease in which fluids can flow through a porous medium (in our case, a rock formation). In Figure 2.06, the cap rock is depicted by the black layer.

The fourth requirement for a hydrocarbon accumulation is the presence of a Reservoir Rock. In the example shown in Figure 2.06, the reservoir rock is the same rock formation as the migration path. As stated earlier, the most common reservoir rocks are sedimentary rocks; however, naturally fractured igneous and metamorphic rocks can also form hydrocarbon reservoirs. The two requirements for a commercial crude oil or natural gas reservoir are high porosity and high permeability. As discussed earlier, oil and natural gas exist in the pore-space between the grains of the sedimentary rocks. The porosity of a rock is defined as the fraction of the rock’s bulk (total) volume occupied by the pores. For example, a cubic foot (1 ft3) of rock with 15 percent porosity will contain 0.15 ft³ of pore space. Consequently, a rock formation with a higher porosity implies greater storage capacity than a rock formation with a lower porosity. This, in turn, results in the possibility of greater quantities of oil and gas stored in the more porous rock.

As discussed earlier, permeability is defined as the ease in which fluids flow through porous media. A high permeability formation implies greater oil and gas production rates and more economically attractive production wells.

The last component of a hydrocarbon system is the Trap. A trap or trapping mechanism is a change in the stratigraphy or a structural deformation that is capable of stopping the migration process and keeping the oil and gas in place over geologic time. In the example in Figure 2.06, the trap is an anticline like that shown in the photograph in Figure 2.04.

Statistically, anticlines are the most common traps; however, they are not the only types of hydrocarbon traps. Crude oil and natural gas traps can be categorized as Stratigraphic Traps or Structural Traps. As the names imply, stratigraphic traps are related to the layering of the rock strata; while structural traps are related to the structural deformations of the rock formations.

Examples of stratigraphic hydrocarbon traps are shown in Figure 2.07. Figure 2.07 shows (a) a “pinch-out” trap and (b) an unconformity trap. In these figures, the yellow layers represent reservoir quality rock (Reservoir Rock); while the green areas represent an oil accumulation in the reservoir trap.

A pinchout trap, Figure 2.07a, is formed due to the relative rise and fall of a water body in relation to the local land mass. (Note: a relative rise or fall may be due to either a true rise or fall of the sea level, or a subsidence or uplift of the land mass.) In this figure, the crude oil reservoir is represented by the green area encased in the black, impermeable layer. As mentioned earlier in this lesson, the size and weight of the sediments that form sedimentary rocks are deposited in water are dependent on the energy of the water suspending the particles. Heavier, coarser materials can only be suspended in high energy environments near the shore where wave and tidal action keep these materials mixed with the water. These materials are deposited as sediments at the point in the depositional environment where the wave and tidal energy can no longer support them. On the other hand, lighter, finer sediments can be suspended in low energy environments away from the shore in more calm waters and, consequently, are deposited further from the shoreline. As the relative position of the sea level changes over the geologic time scale, the positions of the coarser and finer sediments change. The coarser materials with the larger pore spaces between the sediment grains often make good quality rock, while the finer materials, particularly clays and silts, with smaller pore spaces make good impermeable seals (cap rocks). Under the proper sequence of events, as the geographical locations of the sediments change over the geologic time scale, the changes in the size of the sediments can create pinchout, or stratigraphic trap.

Figure 2.07b shows an unconformity trap. A geological unconformity is a boundary between two rock sequences of different ages that are missing some transitory rock sequences of intermediate ages - in other words, some rock strata are missing from the local geological record. This gap in the geological record is caused by a past erosional period.

The depositional history of an unconformity trap is slightly more complicated than that of a pinchout trap. In this trap system, an early depositional period caused sedimentary rocks to be deposited horizontally. These rocks were then tilted due to local tectonic forces. These form the lower tilted layers in Figure 2.07b. The higher, uplifted portions of the tilted layers were then eroded over geological time. The orange wavy line represents an unconformity surface where rocks are missing from the geological record. Geologists recognize these unconformity surfaces when they see rocks of one age sitting on top of rocks of a different age with no intermediary age rocks between them; while paleontologists recognize unconformities by rocks containing fossils from one age sitting directly on top of rocks containing fossils from a different, much older age. After subsidence, a second depositional period occurs where additional sedimentary rocks are again deposited horizontally over the erosional surface. In order for an unconformity trap to develop, the first layer deposited during the second depositional period must be an impermeable rock which can act as the cap rock for the reservoir. After the second depositional period, the trap can be charged with crude oil to form the oil reservoir - the green area of the figure. (Note that the horizontal yellow layer representing good quality reservoir rock above the unconformity surface, does not contain crude oil or natural gas. This is because it is missing a trapping mechanism at this location.)

These histories illustrate the critical nature of the timing in the development of hydrocarbon reservoirs. For a hydrocarbon reservoir to develop, all five elements of the reservoir system must be in place prior to the formation and migration of the hydrocarbons. If one element is missing from the system, then a crude oil or natural gas reservoir cannot develop.

The second major category of hydrocarbon reservoirs is structural traps. Structural traps, illustrated in Figure 2.08, are related to mechanical deformations and failures of the reservoir rock. Figure 2.08a shows an anticlinal structure, or anticline. As stated earlier, the anticline is statistically the most common reservoir trap. The reason for this is very simple. An anticlinal trap simply requires that the reservoir rock and cap rock be folded in a manner that can trap the lighter hydrocarbons. Figure 2.04 shows the Arch Rock anticline near State College, PA.

Figure 2.08b shows a fault trap. A fault trap is created when a rock formation undergoes mechanical failure during an earthquake and the resulting fault causes a porous and permeable rock formation (reservoir rock) to be positioned adjacent to an impermeable rock formation. Thus, closure to the trap is formed by the cross-fault impermeable layer.

Figure 2.08c shows traps along a salt dome. These traps are common in areas where salt formations exist, such as in the Gulf of Mexico. Since large volumes of salt behave in a plastic manner over geologic time, the weight of the overburden creates great pressures within the salt causing it to flow through any local weak spots in the overburden. These salt intrusions can create hydrocarbon traps above and to the flanks of the intrusion as depicted in Figure 2.08c.

To this point, we have discussed the elements required for the formation of a hydrocarbon reservoir. We have also discussed the timing and histories of the formation of the reservoir traps. We have also mentioned that all of the elements of the hydrocarbon reservoir must be in place prior to the formation and migration of the hydrocarbons. We are now able to discuss the actual formation of the hydrocarbons themselves.

Petroleum and natural gas are naturally occurring substances composed of hydrocarbon molecules (molecules made up of hydrogen and carbon atoms) and, possibly, non-organic contaminants, such as CO₂, H₂S, N₂, and O₂.

The most widely accepted theory of the origin of petroleum and natural gas is the Organic Origin Theory which states that these fluids are generated from the decay of prehistoric plants and animals under the influence of the excessive pressures and temperatures that exist in the earth’s subsurface. Research indicates that petroleum and natural gas originated from zooplankton (single-celled plants found drifting freely in fresh or brackish water) and algae. During their lifetimes, these organisms create energy from photosynthesis to carry out their life processes, and it is this energy that we use today (thus the term, “fossil fuels”). Contrary to the popular myth, petroleum and natural gas do not originate from decomposed dinosaurs.

Over the geologic time scale, these free-floating zooplankton and algae die, settle to the ocean-, sea-, lake‑, river‑, or swamp-bottom, and accumulate as sediment. This process occurs simultaneously with the geological processes (erosion, transportation, and deposition) acting on the sand, silt, and clay sediments that form sedimentary rocks. As the organic material and rock materials accumulate on the sea bottom, the materials at the top of the accumulation exert increased weight (pressure) on the materials at the bottom of the accumulation. As this depositional process continues and the accumulation becomes thicker, the impact of the earth’s geothermal gradient also begins to act on the organic materials. At elevated pressures and temperatures, the decaying organic materials are transformed into a dark waxy material called kerogen. Kerogen is an intermediary stage in the development of petroleum. The process of converting the original organic material into kerogen is called the Catagenesis Process. The formation of kerogen requires that the rock containing the original organic material be impermeable. This requirement is essential because as kerogens are formed, they must remain trapped within the pore-spaces of the rock and cannot be allowed to escape to other rock formations or to the environment. As we have already discussed, the rock formation in which the original organic materials are converted to kerogen, and eventually petroleum, are called source rocks for the hydrocarbons. Typically, fine-grained, clay-rich sedimentary rocks, such as shales, are the most common source rocks for hydrocarbon basins because they satisfy two of the requirements for kerogen generation; they (1) are sedimentary rocks and (2) contain adequately low permeabilities.

During the catagenesis process, the kerogen is “cooked” in the high-temperature environment, and the long-chain kerogen molecules are “cracked” into shorter-chained hydrocarbon molecules. It may take several million years for the deposition process to bury the original organic materials and the source rock to achieve the appropriate temperatures (> 250 - 300 ºF) for kerogen generation and another several million years to generate commercial quantities of oil and gas. There is a specific temperature range, referred to as the “oil window,” in which oil is formed. At temperatures below the oil window, the catagenesis process cannot occur; while at higher temperatures the “cooking” and “cracking” processes are stronger and very short-chain natural gas molecules are generated (thermogenic gas).

A second, less accepted theory for the origin of hydrocarbons is the Inorganic or Abiogenic Theory. In this theory, hydrogen and carbon from inorganic sources are fused at the elevated pressures and temperatures in the earth’s subsurface and are converted to hydrocarbons. While the presence of inorganically sourced hydrocarbons cannot be discounted, there is abundant evidence that the vast majority of crude oil and natural gas have an organic origin.

Crude oil is a complex mixture of several types of hydrocarbon molecules along with inorganic impurities. These hydrocarbon molecules are:

1. Paraffinic (or alkane series) hydrocarbons
2. Naphthenic (or saturated cyclic) hydrocarbons
3. Aromatic (or cyclic) hydrocarbons
4. Asphaltene hydrocarbons

Sometimes we refer to a particular crude oil as a paraffinic crude oil or as an aromatic crude oil. While there may be several thousand different hydrocarbon molecules in a given crude oil, these descriptions simply refer to the dominant hydrocarbon type in the mixture. All naturally occurring crude oils will typically contain molecules of each type.

Paraffinic, or alkane series, hydrocarbons are shown in Table 2.01. These hydrocarbons are typically studied in introductory courses in Organic Chemistry. Alkane series hydrocarbons are composed of only hydrogen and carbon atoms attached with single bonds. They are characterized by the following formula for the number of hydrocarbon atoms present in the molecule:

In this formula, N_H is the number of hydrogen atoms, while N_C is the number of carbon atoms in the hydrocarbon molecule.

Normal alkanes are the chain molecules depicted the first four examples in Table 2.01. Once the number of carbon atoms reaches four (butanes) different permutations of an alkane molecule can exist that still honor Equation 2.01 but do not form chain molecules. These permutations are called isomers with the number of possible permutations (and number of isomers) increasing as the number of carbon atoms, N_C, increases. An example of the difference between a normal and isomeric alkane is shown in Table 2.01 for n-butane and i-butane. Due to the slight discrepancies in the molecular structures, normal alkanes and isomeric alkanes have slightly different physical and chemical properties, such as, boiling points, melting points, etc.

Table 2.01: Examples of Alkane Series Hydrocarbons: Methane (CH₄) through Butanes (C₄H₁₀)

Compound	Formula	2D Representation	3D Representation
Methane	CH4
Ethane	C2H6
Propane	C3H8
N-Butane Normal Butane	C4H10
I-Butane Isomeric Butane	C4H10

As the number of carbon atoms increases, the molecular weight of the molecule increases. The lower molecular weight alkanes, methane and ethane, are the most common hydrocarbon components in natural gas; however, intermediate molecular weight alkanes up to the butanes may also be present in natural gases. In addition to these hydrocarbon components, some inorganic impurities, such as CO₂, H₂S, N₂, and O₂ may also be present in natural gases.

Crude oils from Pennsylvania are generally classified as Paraffinic Crude Oils (“Pennsylvania Grade Crude Oil” was at one time a phrase used to describe high quality crude oils.). As a solid, the alkanes form a waxy substance, paraffin, which is the main component of such products as paraffin candles.

The second category of hydrocarbon molecules found in crude oils are naphthenic (or saturated cyclic) hydrocarbons. Like the alkanes, these hydrocarbons are composed of hydrogen and carbon atoms attached with single bonds; however, they differ from the alkanes in that they do not form chain structures but form cyclic (ring) structures. Examples of naphthenic hydrocarbons are shown in Table 2.02.

Table 2.02: Examples of Naphthenic Hydrocarbons

Compound	Formula	2D Representation
Cyclopropane	C3H6
Cyclobutane	C4H8
Cyclopentane	C5H10

The third category of hydrocarbon molecules found in crude oils are the aromatic (or cyclic) hydrocarbons. These hydrocarbons are composed of hydrogen and carbon atoms that form cyclic structures but contain dual bonds between alternating carbon atoms. The simplest aromatic hydrocarbon is benzene with a single ring structure; while more complex aromatic hydrocarbons are typically formed with multi-ring structures. As the name implies, aromatic hydrocarbons, such as benzene, are associated with a sweet smell. Examples of aromatic hydrocarbons are shown in Table 2.03.

The last category of hydrocarbon molecules found in crude oils are the asphaltene hydrocarbons. These hydrocarbons are large, high molecular weight molecules which may also contain some atoms other than hydrogen and carbon atoms, such as, sulfur, oxygen, or nitrogen atoms. Asphaltenes typically result in the residue from the refining process and are the principal components of asphalt (road paving), tar, and bitumen products.

The mixture of these hydrocarbon molecules can have several consequences on oil and gas production, transport, and refining. These include:

1. The mixture of hydrocarbon molecules gives the bulk fluids (oil and gas phases) the properties which dictate the ease or difficulty in which they flow through the reservoir towards production wells and through production equipment
2. The nature of any solids which may precipitate from the bulk fluids onto rock grains, wellbore, or surface equipment during production causing operational problems requiring different solutions:
   1. Paraffinic crude oils may deposit waxy solids onto the reservoir rock, well completion, or production tubing causing restrictions to flow requiring a remediation treatment, such as hot kerosene injection into the well.
   2. Asphaltic crude oils may deposit hydrocarbon resins onto the reservoir rock, well completion, or production tubing causing restrictions to flow requiring a remediation treatment, such as solvent injection into the well.
3. Local field treatment of the crude oil to upgrade it to the required specifications for the pipelines and refineries where the crude oil will eventually flow
4. The products that can be refined from the crude oils once they reach the refineries: lubricating oils, heating oils, car or aviation fuels, asphalt and tar products, etc.

Table 2.03: Examples of Aromatic Hydrocarbons

Compound	Formula	2D Representation
Benzene	C6H6
Napthalene	C10H8

The definitive methods for determining the different components in crude oil are with laboratory measurements, such as gas chromatography. Often, however, less rigorous methods may be useful for quick, on-site evaluations or for numerical (computer) calculations where the crude oil type is characterized with a single parameter. In the oil and gas industry, one common measure of the dominant character of the crude oil (paraffinic, naphthenic, and aromatic) is the Watson Characterization Factor^[1] (or a generalization suggested by Whitson^[2]). The original form of the Watson Characterization Factor, K_W, is:

Where:

K_W is Watson Characterization Factor, ^oR^1/3

T_b is the mean average boiling point of the mixture, ^oR

ϒ_o is the specific gravity of the mixture, dimensionless

This equation requires that the boiling point, T_b, for the mixture of interest is known. In many cases, T_b is unknown or difficult to measure. For these cases, Whitson correlated the Watson Characterization Factor with the more commonly known molecular weight:

Where:

K_W is Watson Characterization Factor, ^oR^1/3

M_o is the molecular weight of the mixture, lb_m/lb_m-mol

ϒ_o is the specific gravity of the mixture, dimensionless

The guidelines for the use of the Watson Characterization Factor are:

1. K_W ≥ 12.5 indicates a paraffinic crude oil
2. 12.5 > K_W ≥ 10 indicates a crude oil containing naphthenic or aromatic components
3. K_W < 10 indicates a highly aromatic crude oil

Table 2.04 shows the values of the Watson Characterization Factor for substances of known hydrocarbon type (paraffinic, naphthenic, and aromatic).

Table 2.04 Watson Characterization Factor for Substances of Known Hydrocarbon Type

Hydrocarbon Series	Substance	Formula	Tb (oR)	Mo (lbm/lbm-mol)	Υo	Kw(oR1/3) Eq. 2.02a	Kw(oR1/3) Eq. 2.02b
Paraffin	n-Hexane	C6H4	615.4	86.178	0.6640	12.8	12.7
	2-Methylpentane (A)	C6H14	600.1	86.178	0.6759	12.8	12.8
	n-Heptane	C7H16	668.8	100.205	0.6882	12.7	12.6
Napthene	Cyclohexane	C6H12	637.0	84.162	0.7834	11.0	11.0
	Methylcyclohexane	C7H14	673.4	98.189	0.7740	11.3	11.4
Aromatic	Benzene	C6H6	635.8	78.114	0.8844	9.7	9.8
	Toluene	C7H8	690.8	92.141	0.8718	10.1	10.2

(A) One of the isomers is Hexane

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To this point in the lesson, we have discussed the origins of the reservoir rocks and traps that formed over the geologic time scale which result in modern oil and gas reservoirs. We have also discussed the origins of the hydrocarbons that reside in pore spaces of these reservoirs. We can now discuss the types of reservoirs and reservoir systems that are currently of commercial interest to the oil and gas industry. To aid in this discussion, we must first introduce the concept of the Phase Envelope (or, Phase Diagram, or Pressure-Temperature Diagram, or P-T Diagram) for single-component (pure) and multi-component (mixture) systems.

The Gibbs Phase Rule relates the degrees of freedom in a system to the number of components and number of phases in a system. The Gibbs Phase Rule is:

Where:

F the number of degrees of freedom in the system, integer

C is the number of components in the system, integer

P is the number of phases in the system, integer

The use of the Gibbs Phase Rule is best illustrated with examples; however, to do this we must first discuss some fundamental thermodynamic concepts. The phrase “degrees of freedom” refers to the maximum number of independent thermodynamic variables (pressure, temperature, and intensive variables) that you can vary simultaneously within a system at equilibrium before you are forced to specify one or more of the remaining variables (or disturb the equilibrium of the system). By “intensive variables”, we are referring to variables that are independent of the size of the system. For example, phase density in a system is an intensive variable because you can halve the size of the system, and the phase density will remain the same. On the other hand, the mass of a system is an extensive property because if you halve the size of the system, then you halve the mass in the system. A component refers an individual chemical element that exists in the system (in our case, a molecular species: methane, ethane, cyclopentane, benzene, CO2, H₂O, etc.). Finally, a phase is a physical state of matter with homogenous (uniform) composition, physical properties, and chemical properties. In petroleum and natural gas engineering, we typically deal with systems containing four phases: a gaseous hydrocarbon phase (natural gas), a liquid hydrocarbon phase (crude oil), a liquid aqueous phase (water or brine), and a solid rock phase. There are times when we deal with systems containing more phases (such a solid hydrocarbon phase or multiple hydrocarbon liquid phases), but the circumstances when this occurs are beyond the scope of this class.

For a single-component system, we have C = 1, and Gibbs Phase Rule becomes:

If we were to plot the phase state (number and types of phases) on a pressure-temperature plot for this single-component system, then we would obtain a plot like that shown in Figure 2.09. This figure is also referred to as a Phase Diagram or a P-T Diagram. In this Phase Diagram, the grey region represents all of the pressure-temperature combinations that result in the solid form of our single component, the green region represents the pressure and temperature combinations that result in the liquid form of our single component, the red region represents the pressure and temperature combinations that result in the gaseous form of our single component, and the multi-colored region represents the super critical form of our single component. Also posted on this Phase Diagram are two points, the triple point and the critical point.

Getting back to the single component version of the Gibbs Phase Rule, Equation 2.04, we can start to clarify some of the concepts that we have already discussed with some examples. If we consider the single-phase regions in Figure 2.09 (P = 1 in Equation 2.04), then from Equation 2.04, we have 2 degrees of freedom (F = 2). This implies that we can independently vary Pressure and Temperature within the Phase Envelope (colored regions) and not change the phase state of the system. In other words, two degrees of freedom represent two-dimensional regions (areas) on the Phase Diagram in which a single phase exists.

Now, let’s consider the occurrence of two phases coexisting simultaneously (P = 2) in equilibrium. From Equation 2.04 with P = 2, we have one degree of freedom (F = 1). In Figure 2.09, we have two coexisting phases along the borders of the phase envelopes. For example, the line bordering the Solid and Liquid Phases represents the pressure-temperature conditions where the solid form of our single component system can coexist with the liquid form of our single component at equilibrium (think of polar caps sitting on water near the earth’s poles). For two phases to coexist in equilibrium, if we were to change one variable, say temperature, then we would be forced to change pressure in a manner that it remained on the border line between the two single-phase regions. In other words, one degree of freedom represents the one-dimensional, curvilinear lines which act as borders between the single-phase regions. If we change one variable on one of these border lines, then we are forced to change the other variable to remain on the border line.

Finally, we can consider the coexistence of three phases (P = 3 in Equation 2-4) in a system at equilibrium. From Equation 2.04 with P = 3, we have F = 0, or no degrees of freedom. This implies that at the point where three phases coexist (the Triple Point in Figure 2.09), we cannot change either pressure or temperature and retain a three-phase system in equilibrium of the single-component (pure) system. The Triple Point is a property of the component that we are considering. Thus, zero degrees of freedom refers to a 0-Dimensional point (the Triple Point)

In Figure 2.09, the Critical Point is also plotted. The Critical Point, defined by the critical pressure, P_c, and the critical temperature, T_c: (P_c, T_c) is the point in the system that defines the onset of the super critical state. Super critical fluids are fluids in which the gaseous phase becomes indistinguishable from the liquid phase (the phase densities become equal).

Consider a pressure-temperature pair in the single-phase gas region with a temperature somewhere between the temperature at the triple point and the critical temperature, T_c, such as Point A in Figure 2.10. If we were to increase the pressure of this single-phase gas (Path A-A’), then we would see a distinct and abrupt change in the phase state of the fluid as we crossed into the single-phase liquid region. This is because the densities of the gaseous phase and the liquid phase are different. Now, if we were to do the same experiment starting at a temperature greater the critical temperature, T_c, such as Point B, then as we increased the pressure on the single-phase gas (Path B-B’) and entered the Super Critical Fluid region, there would be no abrupt phase change.

We could also perform a third experiment where we started at the original point, Point A, and followed the pressure-temperature path Path A-B-B’-A’ into the single-phase liquid region to arrive at Point A’. In this last experiment, we would arrive at the same point, Point A’, as in the first experiment, but without any abrupt phase change. The system properties would change smoothly and continuously during the entire experiment.

For multi-component systems like real crude oil – natural gas systems, the Pressure-Temperature Diagram is much more complex. This is because a real crude oil – natural gas system may contain tens or hundreds of thousands of components. For Multi-Component Systems, the P-T Diagram looks like that in Figure 2.11. A Phase Diagram, such as that shown in this figure, typically is measured in the laboratory but can also be generated mathematically with sophisticated models, such as, Cubic Equation of State Equations (multi-component extensions to van der Waal’s Equation).

In this figure, the region between the green curve and the red curve is the two-phase envelope; while the region outside of the two-phase envelope is the single-phase region. Single-phase liquids exist to the left (lower temperatures) and above (higher pressures) the bubble-point locus (green curve); while single-phase gases exist to the right (higher temperatures) of the dew-point locus (red curve).

The green curve in this figure represents the Bubble-Point Locus of this multi-component system; the red curve represents the Dew Point Locus of the system, and the dashed lines in the two-phase region represents the quality lines of the system (lines of constant volume-fraction of the liquid phase). The bubble-point, defined by a bubble-point pressure, P_b and a bubble-point temperature, T_b, is the point on a pressure-temperature path (originating in the single-phase liquid region) where the path enters the two-phase region (crosses the green curve in Figure 2.11). The name “bubble-point” comes from the fact that this is the point where the first bubble of gas evolved from a liquid as it enters the two-phase region. For example, Point A in Figure 2.11 lies in the single-phase liquid region. As the pressure is reduced at a constant temperature (isothermal conditions), it follows the Path A-A’. The point where Path A-A’ enters the two-phase region (crosses the green, bubble-point locus) represents the bubble-point pressure for this temperature. This is the point where the first bubble of gas is formed in the system. The pressure reduction is continued until it terminates at Point A’. Point A’ lies on the 0.9 quality line, implying that at this point, the system is composed of two-phases with the liquid phase occupying 90 percent of the volume.

On the other hand, the dew-point, defined by the dew-point pressure and dew-point temperature is the point on a pressure-temperature path (originating in the single-phase gas region) enters the two-phase region. The name dew-point refers to the point where the first liquid drop condenses from the gaseous phase. For example, Point B in Figure 2.11 lies in the single-phase gas region and enters the two-phase region when the pressure is reduced under isothermal conditions (Path B-B’). The dew point pressure for this temperature then is the pressure where Path B-B’ crosses the red dew-point locus. If the isothermal pressure reduction is stopped at Point B', then the system at equilibrium will contain two phases with the liquid phase occupying 10 percent of the system volume.

Finally, the pressure, P_max in Figure 2.11 is the cricondenbar (the maximum pressure in which two phases can coexist); while the temperature, T_max is the cricondentherm (the maximum temperature in which two phases can coexist).

With these preliminary concepts, we can now continue with our discussion on the types of hydrocarbon reservoirs encountered in the oil and gas industry.

Undersaturated black oils, sometimes referred to as “low shrinkage oils,” are single-phase liquid systems that reside in reservoirs with an original temperature that is significantly lower than critical temperature, T_C. The phase diagram for an undersaturated black oil is shown in Figure 2.12.

In this figure, the reservoir temperature, T_R, and reservoir pressure, p_R, at the time of discovery are determined by the earth’s local temperature gradient and hydrostatic pressure gradient, respectively. The phase diagram for the crude oil is determined by the composition of the crude oil. As shown in this figure, the original reservoir temperature and pressure lie in the single-phase liquid region of the phase diagram at a temperature lower than the critical temperature.

The term “undersaturated” implies that the crude oil has the capacity to dissolve additional gaseous components and remain in the single-phase region. For example, if we change the composition of the system by adding more lower molecular weight components (e.g., methane and ethane), then the phase envelope would expand with the bubble-point locus beginning to shift towards the Point (T_R, p_R). In this example, we could continue to add gaseous components to the system until the bubble-point locus has shifted all of the way to the Point (T_R, p_R). At this point, with Point (T_R, p_R) lying on the bubble-point locus, we would call the fluid a bubble-point fluid. This is the point where the system would be unable to accept additional gaseous components and still remain a single-phase liquid, i.e., a single-phase crude oil. We will discuss the significance of the term “low shrinkage” when we discuss “high shrinkage” volatile oils.

The production of oil and gas is an isothermal process. We typically deplete the reservoir pressure by removing fluids from the system. Even in the cases where we inject fluids at different temperatures into the reservoir, such as with steam injection, the volume of fluids that we inject are so small compared to the size of the reservoir and the over- and under-burdens that, at most, we cause a local change in the temperature at the point of injection and have no significant impact on the temperature of the system. For isothermal processes, the pressure-temperature path of the fluids inside the reservoir is a vertical line at a fixed temperature. This is represented in Figure 2.12 (A) as the solid black arrow going from Point (T_R, p_R) to Point (T_R, p_A).

Figure 2.12 (B) shows the undersaturated black oil in an anticlinal trap at the time of discovery, that is, at the original reservoir temperature, T_R, and pressure, p_R. This figure depicts a single-phase liquid hydrocarbon (crude oil) system. As we produce reservoir fluids, single-phase oil (and the dissolved natural gas components) and possibly water, the pressure in the reservoir depletes. This is the solid arrow from Point (T_R, p_R) to Point (T_R, p_A). At some point in time, the reservoir pressure drops below the bubble-point pressure, and we enter the two-phase region in the phase diagram. At this point in time, a second, free gas phase evolves in the reservoir. This occurs when the path of the reservoir fluids crosses the green, bubble-point locus.

As we continue production, we now produce crude oil (and the gas dissolved in it), free natural gas, and, possibly, water. At some point during the depletion process, the natural pressure in the reservoir becomes so low that it can no longer overcome the weight of the fluids in the wells and lift these fluids to the surface at commercial rates. At that point in time, we may be able to install some form of artificial lift (e.g., pumps) to help the natural reservoir pressure lift the reservoir fluids, but that is only a temporary solution, and eventually we will be forced to abandon the reservoir. The pressure at which we abandon the reservoir is called the “abandonment pressure,” p_A.

Figure 2.12 (C) shows the same reservoir at abandonment conditions after the free gas phase has developed. Since gas is lighter than oil, it will migrate to the top of the reservoir and accumulate there. When gas comes out of solution due to pressure depletion and accumulates at the top of a reservoir, we refer to the resulting accumulation as a “secondary gas cap.”

Please note that we may run into some situations in which the abandonment pressure occurs before we drop below the bubble-point pressure. In these cases, the path of the reservoir fluids would remain in the single-phase liquid region, and a free gas phase would never develop in the reservoir.

Also depicted in Figure 2.12 (A) is the dashed arrow from Point (T_R, p_R) to Point (T_S, p_S). This is the path that the reservoir fluids travel in the well and through the surface facilities. Point (T_S, p_S) refers to the separator conditions. The separators are field equipment, typically designed by facilities engineers, that are used to separate the produced fluids. Normally, produced oil has a higher commercial value to the oil and gas company than produced natural gas, so typically the facilities engineers design the separators to optimize the volume of liquid at the surface. In other words, the faculties engineers will design the separator conditions T_S and p_S to lie on the quality line of the phase diagram with the maximum feasible volume percent liquid.

Saturated black oils are oils which are fully saturated with natural gas components (e.g., methane and ethane). This implies that the original reservoir temperature and pressure are in the two-phase region of the phase diagram at the time that the reservoir is discovered. This is shown in Figure 2.13.

Figure 2.13 (B) shows a saturated black oil in an anticlinal trap. In this figure, we can see that a gas cap overlies the oil at discovery. Since this gas accumulation was present at the original temperature and pressure conditions, we refer to this gas accumulation as a “primary gas cap.” Figure 2.13 (C) shows the state of the reservoir at abandonment conditions. As shown in this figure, at the lower pressure condition, the gas cap size has expanded.

Undersaturated volatile oil reservoirs are single-phase oil systems that reside in reservoirs with an original temperature relatively close to the critical point (relative compared to low shrinkage oils). As with the undersaturated black oils, the term undersaturated implies that the original reservoir temperature and pressure lies in the single-phase liquid region of the phase diagram. Such a system is shown in Figure 2.14.

We are now in a position to discuss the terms “low shrinkage oil” and “high shrinkage oil” as they pertain to the oil and gas industry. The blue bars on Figure 2.14 (A) represent equal pressure drops below the bubble-point pressure (these bars are of equal length). We can see from this figure that due to the convergent nature of the quality lines (dashed lines) near the critical point, equal pressure drops result in different volume percentages of the liquid phase in the two-phase region. The pressure drop represented by the blue bar further from the critical point results in a two-phase system with 90 percent of the volume occupied by the liquid phase; while the blue bar closer to the critical point results in a two-phase system with 80 percent of the volume occupied by the liquid phase. Thus, the volume of the liquid phase shrinks more in a system that is closer to the critical point for similar pressure drops. Since the liquid phase occupies less volume for a volatile, high shrinkage oil for comparable pressure drops, at abandonment the secondary gas cap will occupy a larger volume.

The definition of a “volatile fluid” is a fluid that easily evaporates or vaporizes. This definition gives rise to the name “volatile oils.” These systems develop larger gas phase volumes for comparable pressure drops when entering the two-phase region of the phase envelope.

Gas condensate reservoirs are gas systems that reside in reservoirs with the original temperatures lying between the critical temperature, T_C, and the cricondentherm (T_max in Figure 2.11). If the original reservoir pressure is greater than the dew-point pressure, then a single-phase gas system will occur in the reservoir as in Figure 2.15.

In this figure, the reservoir is initially a single-phase gas, but as we deplete the pressure due to gas production the pressure-temperature path of the system enters the two-phase region of the phase envelope and liquid hydrocarbons condense from the gas in the reservoir (thus the name gas condensate reservoir.)

We are actually very familiar with this process in our everyday lives. Think of a four-component mixture of oxygen, carbon-dioxide, nitrogen, and water vapor (a mixture of air) and its phase envelope. If we started at a point in the single-phase gas region with a pressure below the cricondenbar (p_max in Figure 2.11) and reduced the temperature under constant pressure conditions (isobaric conditions), then we would cross the dew point locus of the phase envelope. This would be the pressure and temperature where we would see the first dew forming on plants and the first water condensation forming on glass and metal. If we were to continue reducing the temperature, then the percent volume of liquid (water) would increase and it would begin to rain. What is happening in this simple example is that the heaviest component in our system (water vapor) is condensing out of the gas phase (air mixture) and forming a second phase (liquid water) in the two-phase region.

This is essentially what is occurring in the reservoir of a gas condensate system but under isothermal conditions. As we pass through the dew point pressure, the heaviest hydrocarbon components in the system begin to drop out and form a second, liquid hydrocarbon phase in the two-phase region of the phase envelope inside the reservoir.

There is one interesting characteristic of gas condensate reservoirs that is worth further discussing and that is the retrograde behavior of these systems. This is illustrated in Figure 2.16. In this figure, if we were to follow the isothermal Path A-A’-A’’, then we would go below through the dew-point pressure, increase the volume percentage of the liquid hydrocarbon phase until it reached a maximum at Point A’ with further reductions in pressure resulting in a lower volume percentage of the liquid hydrocarbon phase. We could also continue the isothermal pressure reduction, reenter the single-phase gas region, and stop at Point A’’.

We can see from Figure 2.09 and Figure 2.10 that for a pure (single-component) system, the liquid phase occurs at higher pressures than the gas phase. Thus, if we were to start in the single-phase liquid region of a pure system, we would need to reduce the pressure isothermally to create a gas phase.

The analogy for our multi-component system is that if we start at the point of maximum liquid volume (Point A’ in Figure 2.16) and reduced the pressure isothermally, then we would get the conventional behavior for a pure system along Path A’-A’’. Conversely, if we were to start at Point A’ and increased the pressure isothermally to Point A in the single-phase gas region, then we would get the behavior opposite of that for a pure system along Path A’-A. This behavior, opposite to a pure system, is referred to as retrograde behavior. This behavior occurs in the green shaded region in Figure 2.16. This region, formed by connecting all of the points of maximum temperature on the quality lines, is referred to as the retrograde region of the fluid.

Sometimes we see or hear the terms “Retrograde Condensate Reservoir” or “Retrograde Condensate System.” This terminology is used to describe reservoirs in which the isothermal reservoir pressure-temperature path traverses the retrograde region of the system’s phase envelope.

Wet gas reservoirs are gaseous hydrocarbon systems that reside in reservoirs with the original temperatures above the cricondentherm. In addition, the field surface facilities, separators, gas plant, etc., are in the two-phase region of the system’s phase diagram. This is shown in Figure 2.17. Under these conditions, as the pressure in the reservoir is reduced due to production, the reservoir never enters the two-phase region of the gas and no hydrocarbon liquids drop out in the reservoir. That is, as pressure is reduced, the hydrocarbon fluid in the reservoir remains in its gaseous state. However, as the produced gas travels up the well and to the surface, at some point in the production system it enters the two-phase region of the phase envelope and liquid hydrocarbons develop in the well or surface facilities.

Dry gas reservoirs are gaseous hydrocarbon systems that reside in reservoirs with the original temperatures above the cricondentherm. In addition, the surface conditions are also greater than the cricondentherm. This is shown in Figure 2.18. Under these conditions, as the pressure in the reservoir is reduced due to production, both the fluids in the reservoir and the fluids in the production system remain a single gaseous phase.

• Crude oil and natural gas exist in the ground in the pore spaces of reservoir rock, typically sedimentary rock.
• Crude oil and natural gas accumulate in the ground in structures known as hydrocarbon reservoirs.
• There are five elements that are required for a hydrocarbon reservoir. The absence of just one element will preclude a geological feature from acting as a hydrocarbon reservoir. The timing of the formation of these elements is critical; all elements must be in place before the migration of oil or gas begins. These elements are:
  • the source rock
  • the migration path
  • the cap rock
  • the trap
  • reservoir quality rock
• The source rock is an organic-rich sedimentary rock where catagenesis converts dead organic material, predominantly dead algae and zooplankton, into kerogen and eventually hydrocarbons.
• The migration path is a pathway where mature oil and gas migrate from the source rock to the trap. During the migration process, buoyancy is the dominant force acting on the hydrocarbons.
• The cap rock is an impermeable rock that prevents lighter oil and gas from migrating vertically away from the trap and towards the surface.
• The trap is a specific geological structure that keeps the crude oil and natural gas in place over geological time (i.e., provides four-way closure to the oil and gas). Traps can either be stratigraphic in nature, where the trapping mechanisms are dominated by the layering of sedimentary rocks, or structural in nature, where the trapping mechanisms are dominated by the folding and faulting of the rocks.
• The reservoir rock is a rock that has sufficient reservoir quality to allow for commercial crude oil and natural gas accumulations:
  • sufficiently high porosity to allow for the storage of crude oil and natural gas in commercial volumes;
  • sufficiently high permeability to allow for the subsurface transport of crude oil and natural gas at commercial production rates.
• The prevailing theory is that the hydrocarbons that make up crude oil and natural gas are organic in nature.
• Crude oil and natural gas are complex mixtures of four hydrocarbon types:
  • alkane hydrocarbons
  • naphthenic hydrocarbons
  • aromatic hydrocarbons
  • asphaltene hydrocarbons
• The phase behavior of the complex mixtures of hydrocarbons are determined by the composition of the mixture and are governed by Gibbs Phase Rule.
• The original pressure and temperature of a hydrocarbon reservoir at discovery are determined by the local hydrostatic gradient and thermal gradient, respectively.
• Where the original pressure and temperature of the reservoir lies in the phase envelope of the phase diagram determines the type of crude oil or natural gas system that will be produced from the reservoir.

Summary

In this lesson, we learned about the origin of crude oil and natural gas and their occurrence in subsurface reservoirs. In particular, we learned that subsurface reservoirs are composed of porous and permeable rocks and that there are five requirements for a crude oil or natural gas reservoir:

1. the presence of a source rock where organic material accumulates and, over time, is converted to kerogen (a precursor to crude oil and natural gas) due to the subsurface heat and pressure;
2. the presence of a migration path where hydrocarbons can migrate from the source rock to the reservoir;
3. the presence of a cap rock to prevent the lighter oil and gas molecules from escaping from the reservoir to the surface because of their buoyancy in water;
4. the presence of a reservoir rock to allow for (A) the accumulation of oil and gas in commercial quantities and (B) the producibility of fluids at commercial rates;
5. the presence of a trap to provide a mechanism to contain the oil and gas over geologic time until discovery.

In addition, we discussed the two major classifications of hydrocarbon traps:

1. stratigraphic traps where the trapping mechanism is dominated by the layering of the rock;
2. structural traps where the trapping mechanism is dominated by the folding, faulting, and deformation of the reservoir rock.

We also saw that crude oil and natural gas is composed of hydrocarbon molecules of organic origin.  These hydrocarbon molecules are categorized into four types:

1. paraffinic (or alkane) hydrocarbons which are straight chain molecules (or branched-chain molecules call isomers);
2. naphthenic (or saturated cyclic) hydrocarbons which are ringed molecules where all of the bonds between carbon atoms are single bonds;
3. aromatic (or unsaturated cyclic) hydrocarbons which are ringed molecules where double bonds between carbon atoms are present;
4. asphaltene hydrocarbons which are complex mixtures of chain and ring molecules.

We also saw that the dominant hydrocarbon type can be determined by the Watson Characterization Factor.

Finally, we discussed the basics of the phase behavior of the hydrocarbon accumulations.  We saw that this phase behavior can be visualized in a Phase Diagram and can be quantified with tools, such as the Gibbs Phase Rule, among others (like Cubic Equations of State).  We also saw that the phase envelopes shown in the Phase Diagrams, the initial reservoir pressure and temperature at discovery, the pressure-temperature path of the reservoir during production, and the pressure-temperature path of the fluids going up the well and through the surface equipment results in several types of hydrocarbon reservoirs.  The hydrocarbon reservoirs that we discussed were:

1. undersaturated and saturated black oil, or low-shrinkage, crude oil reservoirs;
2. undersaturated and saturated volatile oil, or high shrinkage, crude oil reservoirs;
3. gas condensate reservoirs (sometimes referred to as retrograde condensate reservoirs) where liquid hydrocarbons condense from the gaseous phase;
4. wet gas reservoirs;
5. dry gas reservoirs.

Final Tasks

Overview

Petroleum engineers working in the upstream sector of the oil and gas industry must perform their analyses on the known properties of the reservoirs and reservoir fluids associated with the oil and gas fields they are tasked to manage. The properties that these petroleum professionals are most likely to use during their careers are:

• Rock properties
• Fluid properties
  • Oil properties
  • Gas properties
  • Water properties
• Rock-Fluid interaction properties

These data are required for most routine calculations and are typically obtained with field or laboratory measurements. In cases where these data are unavailable due to time or cost constraints, industry accepted correlations are available for generating missing data. For detailed analyses, measured data are preferred; however, data from correlations serve a vital role of generating data for quick, low cost analyses. In this lesson, we will discuss the data used in petroleum engineering analyses. We will discuss what data are available, how the data are used in the field, how the data are measured in the field or laboratory, and what correlations are available to supplement missing data.

Learning Objectives

By the end of this lesson you should be able to:

• identify the units used in the oil and gas industry;
• list the data used by petroleum engineers on a daily basis during their careers;
• list the sources (field, laboratory, or derived from correlations) of these data;
• explain the basics of the field and laboratory procedures used to obtain these data;
• list and discuss the assumptions behind the field and laboratory measurements;
• calculate required data from raw laboratory or field measurements;
• calculate required data from industry standard correlations;
• describe the relationships and dependencies of the data;
• integrate rock, fluid, and rock-fluid interaction data to perform basic analyses, such as storage and flow rate calculations; and
• discuss the concept of fluid saturations and how these saturations impact storage and production of oil and gas.

Lesson 3 Checklist

Checklist

To Read	Read the Lesson 3 online material	Click the Oilfield Measures and Units link below to continue reading the Lesson 3 material
To Do	Lesson 3 Problem Set	Submit your solutions to the Lesson 3 Problem Set assignment in Canvas

Please refer to the Calendar in Canvas for specific time frames and due dates.

Questions?

If you have questions, please feel free to post them to the Course Q&A Discussion Board in Canvas. While you are there, feel free to post your own responses if you, too, are able to help a classmate.

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The domestic United States oil and natural gas industry uses a very specific set of measures and units that were common at the dawn of the industry and, at least in the U.S., have been retained and expanded upon over the years. These units are often called Oilfield Units. In the international oil and gas industry, the metric system or the related S.I. (Systeme Internationale) system are used. In this course, we will use the U.S. domestic, oilfield units.

The standard measure of volume in the U.S. oil and gas industry is the Barrel (bbl) for liquids and the cubic foot (ft³) for gases. The barrel is defined as 42 U.S. gallons. That is:

$$1\text{ bbl = 42 gal (U}\text{.S}\text{.)}$$

You have probably noticed that the unit for barrel, “bbl,” has two “b’s”, while the word for barrel only has one. One story relating the origin of the unit “bbl” and the measure of 42 U.S. gallons follows^[2]:

In the early 1860s, when oil production began, there was no standard container for oil, so oil and petroleum products were stored and transported in barrels of all different shapes and sizes (beer barrels, fish barrels, molasses barrels, turpentine barrels, etc.). By the early 1870s, the 42-gallon barrel had been adopted as the standard for oil trade. This was 2 gallons per barrel more than the 40-gallon standard used by many other industries at the time. The extra 2 gallons was to allow for evaporation and leaking during transport [sic] (most barrels were made of wood). Standard Oil began manufacturing 42 gallon barrels that were blue to be used for transporting petroleum. The use of a blue barrel, abbreviated "bbl," guaranteed a buyer that this was a 42-gallon barrel.

In August of 1866, independent American oil producers met in Titusville, PA and agreed that the 42 gallon barrel would be the industry standard in the U.S.A. ^[3]

Because of the slightly compressible nature of liquids and the compressible nature of gases, the volume of a given mass of liquid or gas at one set of pressure and temperature conditions will not equal the same volume at a different set of pressure and temperature conditions. To provide a common measure of volume, we can specify the volume of a given mass measured at a reference pressure and temperature.

For liquids, the Upstream Oil Industry uses the pressure and temperature at Stock Tank Conditions as the reference conditions for discussing standardized volumes. The stock tank is the last vessel used in the field separation of crude oil and natural gas prior to the transport to other field processing plants (local oil or gas plants) or export to a distant refinery. The Stock Tank Pressure and Stock Tank Temperature make up a field dependent set of conditions which are determined by the pressure and temperature that maximizes the volume of the produced oil. In other words, a crude oil with a specific composition is produced from a reservoir and the field Separator and Stock Tank conditions are adjusted to maximize the volumetric yield of the crude oil. The pressure and temperature conditions that maximize the crude oil volume from one reservoir will be different from the pressure and temperature conditions that maximize the crude oil volume from another reservoir due to the difference in the crude oil compositions. Thus, the stock tank pressure and stock tank temperature in one oilfield may be different from the stock tank pressure and stock tank temperature in another oilfield. Representative stock tank conditions may be on the order of 100 psi and 75°F. Figure 3.02 shows a typical, three-stage, gas-oil Separation Train.

In this figure, the stock tank pressure and temperature, p_ST and T_ST, are the field-specific reference pressure and temperature used in all reservoir engineering calculations for crude oil and produced water. When referring to liquid volumes at stock tank conditions, we use the units of Stock Tank Barrels (STB).

For gases, we use Standard Conditions, p_SC and T_SC, as the reference conditions for volumetric reservoir engineering calculations. Standard conditions are defined by different governments, scientific agencies, industries, or in some instances, specific legal contracts. The Society of Petroleum Engineers (SPE) defines these conditions as p_SC = 14.696 psi (101.325 kPa) and 59°F (15°C). Informally, many engineers use p_SC = 14.7 psi and 60°F. The appropriate set of standard conditions to be used in engineering calculations will often be dictated by the company and the location where the engineer works. When referring to the gas volumes at standard conditions, we use the units of Standard Cubic Foot (SCF).

For volumetric rate calculations, the U.S. oil and gas industry uses the symbol “q” for the volume of oil or gas produced (or transported) over a 24-hour period. Thus, we have:

• q_o = STB/day for oil (at stock tank conditions)
• q_w = STB/day for water (at stock tank conditions)
• q_g = SCF/day for gas (at standard conditions)

When we consider volumes at a field scale, we often need to use units greater than the stock tank barrel, STB, or the standard cubic foot, SCF. For this, the oil industry uses the uppercase letter “M.” This stands for thousands of STB or SCF. For example, the unit of MSTB refers to thousands of STBs, and the unit of MSCF refers to thousands of SCF. Likewise, the unit of MMSTB refers to millions of STBs, and the unit of MMSCF refers to millions of SCF.

Table 3.01: Volume Units

1 MMSTB	= 1,000 MSTB	= 1,000,000 STB
1 MMbbl	= 1,000 Mbbl	= 1,000,000 bbl
1 MMSCF	= 1,000 MSCF	= 1,000,000 SCF
1 MM ft3	= 1,000 M ft3	= 1,000,000 ft3
1 MMSTB/day	= 1,000 MSTB/day	= 1,000,000 STB/day
1 MMSCF/day	= 1,000 MSCF/day	= 1,000,000 SCF/day

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The reservoir rock properties that are of most interest to development geologists and reservoir engineers (amongst others) are Porosity, Compressibility, and Permeability. Porosity is a rock property that defines the fraction of the rock volume that is occupied by the pore volume. Compressibility is the rock property that governs the relative change in the pore volume when pressure is either increased or decreased. Finally, permeability is the rock property that is a measure of the ease (or difficulty) with which liquids or gases can flow through a porous medium.

Rock Porosity

As previously mentioned, porosity, ϕ, is the fraction of the Bulk Rock Volume, $v_b$ , that is occupied by the Pore Volume, $v_p$. Mathematically, it is defined as:

The bulk volume, V_b, can also be defined as the sum of the volumes of the two constituents of the rock, pore volume and Grain Volume, V_g. That is:

From these two expressions, we can develop several equivalent definitions for porosity:

Figure 3.03 (below) shows the porosities for three different idealized grain packings. In this figure, the rock grains are the spheres and the pore volume is the space between the spheres. Note that the porosities of these three systems are independent on the radii of the grains. In a real rock, the grains would be angular (if quartz grains in sandstones) and some of the void space might be filled with smaller grains, mineral cementation, and clays.

Figure 3.03: Porosities for Three Different Idealized Grain Packings

	$$\varphi =\frac{V_b-V_g}{V_b}=1-\frac{\pi }{6}=0.467$$ $$V_b={\left(2r\right)}^3$$ $$V_g=8\left[\frac{1}{8}\left(\frac{4}{3}\pi r^3\right)\right]=\frac{4}{3}\pi r^3$$
	$$\varphi =\frac{V_b-V_g}{V{}_b}=1-\frac{\pi r^3}{3\sqrt{3}{r}^3}=0.395$$ $$V_b=\left(2r\right)\left(2r\right)\left[r\sin (60)\right]=4\sqrt{3}{r}^3$$ $$V_g=\frac{4}{3}\pi r^3$$
	$$\varphi =\frac{V_b-V_g}{V{}_b}=1-\frac{4\pi r^3}{3\sqrt{3}{r}^3}=0.260$$ $$V_b=\left(2r\right)\left(2r\right)\left(h\right)=4\sqrt{2}{r}^3$$ $$h=\sqrt{4r^2-2r^2}=\sqrt{2}r$$ $$V_g=\frac{4}{3}\pi r^3$$

At this point, we must distinguish between two types of porosity in rock: Total Porosity, ${\varphi }_t$, and Effective Porosity, ${\varphi }_e$. Real reservoir rock is comprised of connected pores and isolated pores. As the name implies, connected pores are pores which are connected to other pores and are capable of transmitting fluids. Isolated pores are pores, or groups of pores, which do not connect to other pores or form dead-end pathways. These isolated pores are incapable of transmitting fluids. Total porosity is defined as the total pore space (connected plus isolated pores) divided by the bulk volume, while effective porosity is the connected pore volume divided by the bulk volume.

Reservoir engineers are concerned with how fluids are stored and flow in the reservoir. Consequently, reservoir engineers are more concerned with effective porosity, ${\varphi }_e$

The porosity is of primary concern to geologists and reservoir engineers because it is a direct measurement of the ability of a reservoir rock to store fluids. There are two ways that oil and gas professionals can obtain measurements of porosity through laboratory measurement and through the use of Well Logs.

One method in which porosity is determined is by laboratory measurements of Core Samples brought to the surface during drilling. Measurement of porosity in the laboratory is part of Routine Core Analysis, sometimes referred to as PKS Analysis (porosity, permeability, and saturation analysis).

Core samples are rock samples that are cut from the reservoir formation using specialized Coring Bits. The extraction of core samples is a very complicated process and requires a lot of planning. When cutting a core, all phases of the coring process must be considered to ensure that the porosity is not altered prior to its delivery to the laboratory. These phases include core cutting, core handling, core preservation, core transport, core sampling, and core testing. Typically, a Formation Evaluation Specialist takes the lead role in designing the core program while working with a development geologist, a reservoir engineer, and a drilling engineer.

After retrieving representative core samples and delivering them to the laboratory, there are several methods that can be used to determine porosity. As shown in Equations 3.01 through 3.03, to determine porosity, we need to determine two of the three volumes, $V_b$, $V_p$, or $V_g$. Once these are determined, then the porosity and the third volume are known.

Bulk Volume, $V_b$, Determination

Bulk volume can be determined by one of two methods, physical measurement and displacement. The use of physical measurements is only applicable to core samples with regular geometric shapes. As the name implies, physical measurement involves the measurement of the dimensions of the core sample (typically a cylindrical core plug) and calculating the volume from standard volumetric formulae.

Displacement methods involve the immersion of the core sample in mercury inside of a pycnometer or graduated cylinder. Mercury is used in displacement methods to prevent invasion into the pore space. The bulk volume of the sample is the apparent volume change of the mercury in the pycnometer or graduated cylinder. Alternative, Archimedes’ Principle can be used to determine the bulk volume of the core sample from the apparent weight change due to buoyancy when fully immersed.

Grain Volume, $V_g$, Determination

The most direct method for determining grain volume is to measure the weight of a dried sample and to divide by the density of the rock matrix. Unfortunately, the rock densities are often not accurately known.

A second method, similar to the immersion method for bulk volume determination, can be used for grain volume determination. In this method, a core sample is crushed and the resulting rock grains are placed into a pycnometer or graduated cylinder along with a known volume of liquid. The volume of the rock grains can then be determined from the apparent volume change of the liquid (the Russell Method) after immersion or the apparent weight change (the Melcher-Nutting Method) of the immersed sample due to buoyancy using Archimedes’ Principle.

Unfortunately, the disadvantage of this method is that it is destructive. Once the sample is pulverized, it cannot be used for further testing. Since we have crushed the core sample to its constituent rock grains, the porosity determined from the immersion of these grains is the total porosity, ${\varphi }_t$.

A third method is the Boyle’s Law Method. As the name implies, it uses Boyle’s Law for the grain volume determination:

In this method, the core sample is placed into one chamber of an experimental apparatus containing two chambers of known volume connected by a closed valve. An inert gas (helium or nitrogen) is introduced into the chambers at different, but known, pressures. At this point, the total number of moles, n_T, in the apparatus can be determined from:

For isothermal conditions, this reduces to Boyle’s Law:

The valve between the chambers is opened and the pressure is allowed to stabilize to the final pressure, p_f, and is recorded. If we assume that the core sample was placed into Chamber 1, then we have:

Solving for $v_g$ :

The advantages of this method are that it is non-destructive and can be very accurate. The disadvantage of this method is that for low permeability core samples, it may take a long time for the pressures to stabilize. Since the gases can only enter or leave the connected pores, the porosity obtained from the Boyle’s Law Method is the effective porosity, ${\varphi }_e$.

Pore Volume, $V_p$, Determination

Early methods used for pore volume determination, such as the Washburn-Bunting Method, used mercury injection into the pore spaces of the core sample. In these Mercury Injection Methods, high pressure mercury was injected into the core sample and the volume of mercury entering the core was measured. These methods had several drawbacks, including the destructive nature of the test and the compression of any gases in the core sample retaining a residual volume, resulting in measurement inaccuracies.

A second method, the Resaturation Method, uses a clean dry core sample and resaturates it with a fluid of known density. The change in weight of the sample can then be used to determine the pore volume, V_p, of the sample

Since the fluid can only enter or leave the connected pores, the porosity obtained from the resaturation method is the effective porosity, ${\varphi }_e$.

A third method for the determination of the pore volume is the Summation of Fluids Method. In this method, a core sample in its native state (not cleaned or dried) is halved. In one of the halves, mercury injection is used to estimate the gas volume, while the second half is used in the retorting (distillation) process to determine the oil and water volumes. The pore volume is then set equal to the sum of the fluid volumes. The advantage of this method is that the Phase Saturations (fraction of the pore space occupied by each phase – oil, gas, and water) can be determined simultaneously with the porosity. The disadvantages of the method are the destructive nature of the test and the assumption that both halves of the core sample contain similar fluid volumes.

Again, in the summation of fluids method, fluids can only enter or leave the connected pores. Consequently, the porosity obtained from this method is the effective porosity, ${\varphi }_e$.

Table 3.02: Comparison of Laboratory Methods for Porosity Determination

Method	Porosity Type	Advantages	Disadvantages
Grain Determination by Immersion	Total Porosity, ${\varphi }_t$	Accurate	Destructive testing Core preparation is critical
Grain Determination by Boyles Law	Effective Porosity, ${\varphi }_e$	Accurate Non-destructive testing Testing rapid for moderate to high permeability core samples	Can be slow for low permeability core samples Core preparation is critical Adsorption of gas onto equipment surfaces can lead to errors
Washburn-Bunting (Mercury Injection)	Effective Porosity, ${\varphi }_e$	Low cost	Destructive testing Safety of mercury Core preparation is critical
Resaturation	Effective Porosity, ${\varphi }_e$	Accurate Non-destructive testing	Requires complete resaturation, may not be possible Can be slow for low permeability core samples Core preparation is critical
Summation of Fluids	Effective Porosity, ${\varphi }_e$	Testing rapid Simultaneous determination of phase saturations	Water volumes may exhibit errors if rock minerals contain water Destructive testing Assumes two halves of core sample contain identical fluid volumes

The most common method of determining porosity is with Well Logs. Well logs are tools sent down the wellbore during the drilling process which measure different reservoir properties of interest to geologists and engineers. Due to the expense of obtaining core samples, typically only a few wells are cored. The wells that do get cored are usually wells early in the life of the reservoir (appraisal wells) and key wells throughout the reservoir. On the other hand, well logs are routinely run in wells, if only to identify the depths of the productive intervals. The three open-hole logs used to evaluate porosity are:

• The sonic log
• The density log
• The neutron log

While none of these logs measures porosity directly, the porosity can be calculated based on theoretical or empirical considerations. The measurements obtained from these logs are not only dependent on the porosity but are also dependent on other rock properties such as:

• Lithology (rock type: sandstone, limestone, shale, etc.)
• The fluids occupying the pore spaces
• The wellbore environment (type of drilling fluid, hole size)
• The geometry of the pores

Since many variables may impact the log readings, corrections need to be applied to the log interpretations and the three logs are typically evaluated together to determine the best estimate of the porosity of rock formations. The log evaluations are also calibrated against core porosity in wells where both core and logs are available.

The Sonic Log measures the acoustic transit time, Δt, of a compressional sound wave traveling through the porous formation. The logging tool consists of one or more transmitters and a series of receivers. The transmitters act as sources of the acoustic signals which are detected by the receivers. The time required for the signal to travel through one foot of the rock formation is the acoustic transit time, Δt. The acoustic travel time, then, is the reciprocal of the sonic velocity through the formation. The units of Δt are micro-seconds/ft (μsec/ft) or millionths of a second per foot.

There are several ways to interpret the sonic log measurements. One of the most common interpretation formulae is the Wyllie Time-Average Equation:

Where:

• ϕ_sl is the porosity from the sonic log (log measurement) , fraction
• Δt_sl is value of the acoustic transit time measured by the sonic log, μsec/ft
• Δt_ma is value of the acoustic transit time of the rock matrix measured in the laboratory, μsec/ft
• Δt_f is value of the acoustic transit time saturating fluid measured in the laboratory, μsec/ft

The presence of hydrocarbons in the reservoir rock results in an over prediction of porosity measured by the sonic log and some corrections may be required. These corrections take the form:

or,

Table 3.03 has typical values of the acoustic transit time for different reservoir formations and commonly encountered reservoir fluids.

Table 3.03: Typical Acoustic Transit Times for Sonic Log Interpretation

Heading1	Δtma (μsec/ft) Range	Δtma (μsec/ft) Commonly Used	Δtf (μsec/ft) Range	Δtf (μsec/ft) Commonly Used
Sandstone	55.5 – 51.0	55.5 or 51.0	—	—
Limestone	47.8 – 43.5	47.5	—	—
Dolomite	43.5	43.5	—	—
Anhydrite	50.0	50.0	—	—
Salt Formation	66.7	67.0	—	—
Fresh Water Based Drilling Fluid	—	—	189.0	189.0
Salt Water Based Drilling Fluid	—	—	185.0	185.0
Gas	—	—	920.0	920.0
Oil	—	—	230.0	230.0
Casing (Iron)	—	—	57.0	57.0

Other empirically based equations exit for sonic log interpretation. One form of an alternative equation is:

In this equation, the value of C is in the range of 0.625 to 0.700 and is determined by calibrating the equation to known porosity, such as, to core data when a well is both cored and logged. In Equation 3.12 and Equation 3.13, ϕ_sonic is the final interpreted porosity from the sonic log.

The _{Density Log} measures the electron density ρ_e, of the formation (the electron density is the number of electrons per unit volume). The density logging tool emits gamma rays from a chemical source which interact with the electrons of elements in the formation. Detectors in the tool count the returning gamma rays. These returning gamma rays are related to the election density of the elements in the formation.

The electron density is proportional to the bulk density, ρ_b, of the formation (the bulk density is the density of the fluid-filled rock in grams per unit volume). For a molecular substance, this proportionality is:

Where:

• ${\rho }_e$ is the electron density of the formation, electrons/cc
• ${\rho }_b$ is the bulk density of the formation, gm/cc
• ΣZ is the sum of the atomic numbers making up the molecule, electrons/molecule
• MW is the molecular weight, gm/molecule

Table 3.04 contains the term in the parenthesis for common substances related to oil and gas production.

Table 3.04: Properties for Density Log Interpretation

Compound	Chemical Formula	Actual Density, ${\rho }_b$ (gm/cc)	$\left(\frac{\text{2}{\displaystyle \sum \text{z}}}{\text{MW}}\right)$ (electrons/gm)	Electron Density, ${\rho }_e$ (electrons/cc)	Log Reading, Apparent ${\rho }_{ba}$ (gm/cc)
Quartz	SiO2	2.654	0.9985	2.650	2.648
Calcite	CaCO3	2.710	0.9991	2.708	2.710
Dolomite	CaCO3MgCO3	2.870	0.9977	2.863	2.876
Anhydrite	CaSO4	2.960	0.9990	2.957	2.977
Sylvite	KCl	1.984	0.9657	1.916	1.863
Halite	NaCl	2.165	0.9581	2.074	2.032
Gypsum	CaSO42H2O	2.320	1.0222	2.372	2.351
Anthracite Coal	---	1.400 - 1.800	1.0200	1.442 – 1.852	1.355 – 1.796
Bituminous Coal	---	1.200 - 1.500	1.0600	1.227 – 1.590	1.173 – 1.514
Fresh Water	H2O	1.000	1.1101	1.110	1.000
Brine (200,000 ppm)	---	1.146	1.0797	1.237	1.135
Oil	N(CH2)	0.850	1.1407	0.970	0.850
Methane	CH4	${\rho }_{methane}$	1.2470	1.247 ${\rho }_{methane}$	1.335 ${\rho }_{methane}$ - 0.1883
Gas	---	${\rho }_{gas}$	1.2380	1.238 ${\rho }_{gas}$	1.238 ${\rho }_{gas}$ - 0.1883

One important observation from this table is that the column containing the group in parenthesis in Equation 3.14, $\left(\frac{\text{2}{\displaystyle \sum \text{z}}}{\text{MW}}\right)$ , is approximately 1.0. Since this term is close to unity, the electron density is a very close approximation to the bulk density, as also seen in Table 3.03. The logging tool is calibrated by running it against a limestone formation containing fresh water. With this calibration, the Log Reading, Apparent ρ_ba (last column in Table 3.03) is:

For some substances, such as liquid-filled sandstones, limestones, and dolomites, ρba can be used directly as ρ_b. For other substances, such as sylvite, rock salt, gypsum, anhydrite, coal, and gas bearing formations, further corrections are required. These additional corrections are beyond the scope of this course. Once the bulk density is determined, the porosity can be estimated by:

Where:

• ϕ_density is the final interpreted porosity from the density log, fraction
• ρ_ma is the matrix density (from the Actual Density, ρ_b, Column in Table 3.03), gm/cc
• ρ_b is bulk density from density log (Equation 3.15), gm/cc
• ρ_f is the density of the fluid measured in the laboratory, gm/cc

The Neutron Log measures the amount of hydrogen in the formation being logged. Since the amount of hydrogen per unit volume is approximately the same for oil and water, the neutron log measures the Liquid Filled Porosity (the porosity excluding the Gas-Filled Porosity). The neutron logging tool emits neutrons from a chemical source which collide with nuclei of elements in the formation. The element in the formation with the mass closest to a neutron is hydrogen. Due to the parity in mass, the neutron in a neutron-hydrogen collision loses approximately half of its energy. With enough collisions, the neutron eventually loses enough energy and is absorbed by the hydrogen nucleus and a gamma ray is emitted. The neutron logging tool measures these emitted gamma rays. Note, other hydrogen atoms may be present in clays in the rock, or in the rock itself and corrections for these other hydrogen atoms are required.

Interpretation of the neutron log is performed by first calibrating the logging tool to specific well and formation conditions. Interpretation charts supplied by the logging company are used to interpret the log for deviations from these calibration conditions. The interpretation of the neutron log for ϕ_neutron is beyond the scope of this course.

As mentioned throughout the discussion on porosity logging, due to the various wellbore and formation conditions encountered during the logging operations (i.e., real conditions, as opposed to laboratory conditions) many corrections may be required to get a good interpretation from the different well logs. In addition, the logs are typically evaluated together to aid in the interpretation. Finally, if core data are available from a well, then the core derived porosity is used to calibrate the logging tools.

Rock (Pore-Volume) Compressibility

In addition to the porosity and its relation to pore-volume, reservoir engineers are also interested in how the pore-volume behaves (increases or decreases) with increases or decreases in pore-pressure. The industry standard relationship for change in pore-volume is based on the isothermal pore-volume compressibility, c_PV.

The isothermal pore-volume compressibility is always positive and is defined as:

The units of compressibility are 1/psi. Equation 3.17 implies that as pressure increases the pore-volume increases. Hall ^[4] correlated the effective rock compressibility as a function of porosity which is shown in Figure 3.04.

For a constant bulk volume and compressibility, we can separate variables in Equation 3.17 and integrate to arrive at the following relationship between pore-volume (or porosity) and pore pressure:

or,

Where ϕ_ref is a reference porosity measured at reference pressure, p_ref. After some manipulation:

To further simplify this relationship, if we assume a small pore-volume compressibility (as shown in Figure 3.03, we are typically dealing with rock compressibilities on the order of 10^-6 1/psi) and apply a Taylor Series expansion to the exponential function (truncated after one term), we obtain:

The rock compressibility determination is performed in the laboratory on core samples. The rock compressibility is an expensive test to run and is not part of the Routine Core Analysis. It must be specifically requested as part of any Special Core Analysis, or SCAL, testing performed on the core sample.

Rock Permeability

The permeability of a porous medium is a measure of the ease (or difficulty) in which a fluid can flow through the pores of the medium. Permeability is a property of the porous medium which in our case is the reservoir rock. The unit of permeability is the Darcy, or D, named after the French engineer Henri Darcy who investigated the flow of water through filter beds in the city of Dijon in the mid-1800s. The unit of Darcy has the dimensions of length-squared. One significant contribution from Darcy’s work (among many), is Darcy’s Law, which was published in 1856 and forms one of the foundations of porous media flow:

Where:

• q_w is the flow rate of water, cc/sec
• k is the permeability of the medium, Darcy
• A is cross-sectional area, cm²
• l is the length in the direction of flow, ft (x, y, or z in Cartesian coordinates)
• $\frac{\partial p}{\partial l}$ is the pressure gradient, atm/cm

The unit of the Darcy is defined as the permeability, k, required to allow a flow rate, q_w, of one cc of water per second through a medium with a cross-sectional area, A, of one cm², with an applied pressure gradient, Δp/ΔL, of one atm/cm. As it turns out, the Darcy as a unit is too large for most field applications. In reservoir engineering we typically work with the millidarcy, md, which is one one-thousandth of a Darcy:

$$\text{1 D = 1,000 md}$$

Henri Poiseuille later generalized Darcy’s Law to fluids other than water by noting that the flow rate was inversely proportional to the dynamic viscosity, μ_f, of the fluid flowing through the porous medium. The unit of dynamic viscosity, the poise, is named after Poiseuille and is a property of the fluid. Again, as it turns out, the poise as a unit is also too large for most field applications. In reservoir engineering we typically work with the centipoise, cp, which is one one-hundredth of a poise:

$$\text{1 poise = 100 cp}$$

The generalized form of Darcy’s Law for any single-phase fluid which incorporates the fluid viscosity is:

Darcy’s Law has several important assumptions associated with it. These include:

• A rigid porous medium (incompressible medium with no transport of rock grains, e.g. fines movement
• An incompressible, homogeneous, Newtonian fluid that fully saturates (single-phase) the porous medium
• Steady-state, isothermal, and laminar (low Reynolds number) flow conditions
• No interactions between the porous medium and the fluid flowing through it
• A no-slip interface between the porous medium and the fluid flowing through it (zero velocity boundary condition at the rock-fluid interface)

The form of Darcy’s Law discussed so far uses the SI unit system. For oilfield units, we have:

Where:

• q_f is the flow rate of the saturating fluid, bbl/day
• 0.001127 is a unit conversion constant
• k is the absolute permeability of the medium, md
• A is cross-sectional area, ft²
• $\frac{\partial p}{\partial l}$ is the pressure gradient, psi/ft

Measurement of the permeability can be done through laboratory or field measurements. In the laboratory, a core sample of known dimensions (A and ΔL) is cleaned and placed into a fluid-tight core holder. A fluid of known viscosity (typically air) is allowed to flow through the core at a metered flow rate. Darcy’s Law is then used to calculate the permeability of the core sample.

In the field, permeability is measured with a Well Test using Pressure Transient Analysis. Under certain conditions, the production rate(s) (can be a zero-production rate) results in well pressures that honor known solutions to the Diffusivity (or Well Test) Equation. When the well test results are compared to the solutions to the diffusivity equation, the permeability of the formation can be estimated.

One common well test is a Pressure Build-Up Test. In a pressure build-up test, the well is produced at a stable (constant) rate, q_p, for a production time of t_p. The well is then shut in and the pressure is monitored during the shut-in period Δt; where Δt is measured from the beginning of the well is shut-in. The well test is called a build-up test because when the well is shut in, the pressures increase with increasing Δt. One analysis tool for the pressure build-up test is the Horner Plot. A typical Horner plot is shown in Figure 3.05.

In this plot shown in Figure 3.05, p_ws are the shut-in well pressures measured during the well test, t_p and Δt are times in hours (Δt measured from the time that the well is shut-in), q_p is the stabilized production rate during the production period prior to well shut-in in STB/day, μ_o is the oil viscosity in cp, B_o is the Formation Volume Factor in bbl/STB, k is the permeability in md, and h is the reservoir thickness in ft.

In a Horner Plot, the function $\frac{\left(t_p+\Delta t\right)}{\Delta t}\left(bottomx-axis\right)$ , decreases as $\Delta t\left(topx-axis\right)$ increases. As can be seen in this figure, the slope of the Horner Plot is related to the permeability of the reservoir near the well. If the shut-in pressures, p_ws, are measured and the slope calculated, then the permeability can be determined if all the other parameters in the definition of the slope are known.

In semi-logarithmic plots (plots with one conventional axis and one logarithmic axis), such as that in Figure 3.05, the slope is normally taken over one logarithmic cycle. That is:

While there is no universal correlation between permeability, field measurements suggest that as the porosity of a formation increases, the permeability of the formation also increases. This behavior is captured in a permeability-porosity cross-plot. One such example of a permeability-porosity cross plot is illustrated in Figure 3.06.

A permeability-porosity cross-plot is a field dependent transform that relates core derived permeability to core derived porosity. Note that the permeability-porosity transform shown in Figure 3.06 is plotted on a semi-logarithmic plot with the permeability plotted on the logarithmic scale. Also note that in the middle of the plot (ϕ = 20 percent) there is an approximate four order of magnitude error bar in the permeability data. This is typical for a permeability-porosity transform. While the results from these transforms may be crude, they are often the only source of permeability data when building complex models of oil or gas reservoirs. Note, geologists have developed methods for capturing this scatter into their models in the form of Scatter Plots, but the development of such plots is beyond the scope of this course.

The permeability in the presence of a single-phase fluid is called the absolute permeability. Since we will be dealing with multi-phase flow, we will need to discuss extensions to Darcy’s which allow for more than one phase. We will do this later in this lesson when we discuss Reservoir Rock-Fluid Interaction Properties.

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Reservoir fluid properties are normally measured in the laboratory. Pressure-Volume-Temperature (PVT) properties relate these properties to each other at equilibrium conditions.  These variables, typically used for volumetric related reservoir behavior, are measured in a laboratory PVT Cell.  A PVT Cell is a high-pressure vessel (container) that allows for the control and measurement of pressure, volume, and temperature.

In addition to laboratory measurements, reservoir PVT properties can be determined from Equations-of-State (EOS).  Equations-of-state are theoretically derived equations that relate the State Variables: pressure, volume, and temperature (state variables are variables that define the thermodynamic state of a system). Three common examples of equations-of-state include:

Isothermal compressibility:

Real gas law:

Van der Waal’s Cubic EOS:

In Equation 3.26, the negative sign is required because the volume of a fluid decreases as pressure increase (i.e., the derivative is negative).  Note that all of these relationships allow for the determination of one of the state variables, p, V, or T, if the two other variables are known (two degrees of freedom).  For the isothermal compressibility EOS, Equation 3.26, temperature can be considered a variable if we have tables or equations where the value of cf can be defined for a specific temperature.

In addition to the equations-of-state, fluid PVT correlations are also used in the oil and gas industry.  These correlations can be either graphical or mathematical in nature.  Fluid property correlations are simply plots, curve fits, or regressions of many laboratory measurements covering a wide range of data.  In general, these correlations may not be as accurate as laboratory measurements or equations-of-state, but they have their uses in reservoir engineering.

All oil and gas reservoirs have water associated with them.  Since it is a common part of the system, we will need to discuss how it is stored and moves in the reservoir.

Water Formation Volume Factor, B_w

The water (or more correctly, the brine) Formation Volume Factor, B_w, (sometimes referred to as the FVF) is a pressure and temperature dependent property that relates the volume of 1.0 stock tank barrel, STB, of water to its volume in barrels, bbl, at another pressure. It has the units of bbls/STB. We have already discussed the use of the stock tank pressure and temperature as an oilfield reference system.

By definition, if we had 1.0 STB of water at p_ST and T_ST, and that same STB occupied 1.02 bbls at reservoir conditions, p_r and T_r, then it would have a formation volume factor of:

$$B_w\left(p_r,T_r\right)=\frac{V_{wr}bbl}{V_{wST}STB}=\frac{1.02\text{ bbl}}{1.00STB}=1.02bbl/STB$$

We can also define the formation volume factor in terms of densities at stock tank conditions and at reservoir conditions. If we assume the mass of 1.0 STB, m_{1 STB}, then at reservoir conditions, we would have:

which implies:

Water Isothermal Compressibility, c_w

Water is considered to be a slightly compressible liquid with a very low value of compressibility. From Equation 3.26 we have:

One correlation for water compressibility^[5] , c_w, is:

Where:

• p is the pressure, psi
• C is the salt concentration, gm/L
• T is temperature, °F

We can develop an explicit formula for the water formation volume factor based on the water compressibility. If we take 1.0 STB of water and its volume in barrels at a reservoir pressure and temperature, then we would have: V_w (bbl) = B_w (p_r, T_r) (bbl/STB) x 1.0 STB. Now,

or,

Water Viscosity, μ_w

In the laboratory, the water viscosity is measured with an apparatus called a Viscometer. The mechanics and test procedures for a viscometer are beyond the scope of this course, and we will work with known correlations. One correlation from McCain has the form:

with

and

where

• μ_{w 14.7 psi} is the water viscosity at 14.7 psi and temperature, T °F
• S is the salt concentration in weight percent, Wt% (note different unit from Equation 3.31)

Once the viscosity at 14.7 psi and T °F are determined, the water viscosity at other pressures can be determined from:

Water Density, ρ_w

The density of water is also a property of interest in petroleum engineering. McCain^[6] provides the following correlation for estimating the water density at reference conditions:

where

• ρ_{w ST} is the water density at sock tank conditions, lb/ft³
• S is the salt concentration in weight percent, Wt%

The water density at reservoir conditions can then be calculated using Equation 3.29.

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[5] Petro Wiki: Produced water compressibility [19]

[6] McCain, W.D. Jr.: McCain, W.D. Jr. 1990. The Properties of Petroleum Fluids, second edition. Tulsa, Oklahoma: PennWell Books.

As discussed in Lesson 2, crude oil is a complex mixture of hydrocarbon molecules. As engineers, we are interested in the bulk (large scale) properties of the crude oil and natural gas. As discussed earlier, these properties are typically measured in the laboratory PVT cell. A PVT cell is essentially a piston which allows the volume to be either increased or decreased. It is fitted with a pressure gauge to allow for pressures to be recorded; a measuring device to allow for the determination of the volume of the cell; and temperature control to ensure the test is conducted at the desired temperature.

For reservoirs containing black oils, the laboratory experiment used to determine PVT properties is the Differential Liberation Test. This test is illustrated in Figure 3.07.

In a differential liberation test, a crude oil sample (green) is introduced into the cell at the initial reservoir pressure and temperature (Step 1 in Figure 3.07). The volume of the cell is then increased by extending the piston outward (Step 2), and the pressure and volume are recorded. At Step 2, the pressure in the cell will be less that the original pressure due to the expansion of the crude oil. This process is continued for several pressure steps until the first bubble of gas (red) is observed through a window in the cell (Step 3). This pressure is the bubble-point pressure of the crude oil. Up until the bubble-point pressure is reached, all measurements have been single-phase (liquid hydrocarbon) measurements.

After the bubble-point pressure has been reached, the volume is increased further until a significant volume of free gas has developed (Step 4). At this point, the pressure and the oil and gas volumes in the cell are measured. The gas is then expelled from the piston under isobaric (constant pressure) conditions by reducing the piston volume and allowing the gas to escape through a valve in the system (Step 5). This process is then repeated until the desired final pressure is reached (Step 8). The pressure, liquid volume, and gas volume are then used in the calculation of the appropriate properties for black oils.

What is the differential liberation test trying to model? In the reservoir, as gas comes out of solution, it typically has a much lower viscosity than the oil phase. Consequently, as gas evolves from the oil, this difference in the viscosity allows the gas to move faster than the oil and to separate from the source oil from which it evolved. This is illustrated in Figure 3.08. In addition, due to the density differences between oil and gas phases, gravity will also act to separate the two phases. It is the properties of the separated phases that we are most interested in, as these are more representative of the processes occurring in the reservoir.

API Gravity of the Crude Oil, °API

In the oil and gas industry, crude oils are characterized by the API gravity (American Petroleum Institute gravity) of the oil. The units of the API gravity are degrees, °API (read as degrees API). The API gravity is defined as:

Where:

• ϒ_o is the specific gravity of the crude oil at 60 °F, dimensionless
• °API is the API gravity, degrees API

The API gravity scale acts as an inverse relationship to density (and specific gravity), that is, as density increases, the API gravity decreases. Crude oils are often graded by their API gravity:

• Light crude oil: °API > 31.5°
• Intermediate crude oil: 22.1° ≤ °API ≤ 31.5°
• Heavy crude oil: °API < 22.1o

Molecular Weight of the Crude Oil, MW_o

Samples of the crude oil taken during the differential liberation test can be extracted from the PVT cell, and the compositions of the crude oil samples can be measured as functions of pressure. If the mole fractions, x_i, of all components are measured from an oil sample (any sample, not just a sample from a differential liberation test), then the molecular weight in lbs/lbs-mole of the oil sample, MW_o, can be calculated from:

If laboratory data are unavailable, then the Cragoe^[7] correlation can be used to estimate the molecular weight:

Where:

• MW_o is the molecular weight of the crude oil, lb/lb-mole
• °API is the API gravity, degrees API

Bubble-Point Pressure of the Crude Oil, p_b

As already discussed, the bubble-point pressure is the pressure that first bubble of gas evolves from an undersaturated crude oil during pressure reduction. The laboratory method for calculating the bubble-point pressure, p_b, of a crude oil was discussed earlier in the context of the differential liberation test. Other PVT tests, such as the Constant Composition Expansion Test, can be used to determine the bubble-point pressure of the crude oil. The constant composition expansion test is similar to the differential liberation test, however, the evolved gas is not expelled from the PVT cell during the test. For all measurements made up to and including the bubble-point pressure, the constant composition expansion test and the differential liberation test give identical results.

When measured data are not available, Standing’s correlation^[8] can be used to estimate the bubble-point pressure:

with

Where:

• R_so is the solution gas-oil ratio of the crude oil, SCF/STB (to be discussed)
• ϒ_g is the gas gravity (MW_g/MW_air), dimensionless (to be discussed)
• T is the temperature, °F
• °API is the API gravity, degrees API

Solution Gas-Oil Ratio, R_so

As we have discussed, most crude oils (possibly excluding some extremely heavy crude oils: °API ≈ 10°) contain Dissolved Gas. This dissolved natural gas consists mostly of the low-end molecular weight hydrocarbons (methane, ethane, propane, and butane) and some inorganic impurities (nitrogen, carbon-dioxide, hydrogen-sulfide, etc.). The volume of this dissolved gas is quantified by the Solution Gas-Oil Ratio, R_so (sometimes simply referred to as R_s). The solution gas-oil ratio is defined as the volume of gas, measured is SCF or MSCF, in solution in 1.0 STB of crude oil. As such, it has the units of SCF/STB or MSCF/STB. A typical plot of R_so is illustrated in Figure 3.09.

In this figure, we can see that the reservoir is an undersaturated oil reservoir. The initial reservoir pressure, pi, is greater than the bubble-point pressure. If this reservoir were to undergo pressure depletion from oil production, then the average reservoir pressure would decline over time, and the pressure would eventually reach the bubble-point pressure. During this time period, the volume of gas in solution in the crude oil remains constant at the initial value of R_{so i}.

Once the reservoir pressure reaches the bubble-point pressure, p_b, gas begins to come out of solution. As the gas comes out of solution and evolves into Free Gas, the volume of gas remaining in solution, R_so, must decrease. This is the behavior observed in Figure 3.09. The volume of free gas liberated from the original stock tank barrel can be calculated as (R_{so i} – R_so) in SCF/STB or MSCF/STB.

The laboratory procedure for determining the solution gas-oil ratio was discussed in terms of the differential liberation test. The R_so values are calculated by summing the appropriate gas volumes obtained during the differential test and dividing by the final oil volume. When this is done, all volumes need to be corrected back to the reference volumes of STB and SCF to get to the appropriate R_so curve.

When laboratory derived R_so data are unavailable, then Equation 3.41 and Equation 3.42 can be used to estimate the solution gas-oil ratio. This is done by placing an assumed pressure into Equation 3.42 and using Equation 3.41 to calculate the pressure associated with that assumed R_so value (not the bubble-point pressure as explicitly written in the equation).

Oil Formation Volume Factor, B_o

The Oil Formation Volume Factor, B_o, is comparable to the water formation volume factor. It relates volume of 1.0 STB of crude oil at stock tank conditions, p_ST and T_ST, to its volume at reservoir conditions, p_r and T_r. A typical plot of B_o is illustrated in Figure 3.10.

This figure shows the formation volume factor of the crude oil for the same reservoir as that shown in Figure 3.09 (identical p_i and p_b). As the pressure depletes from the initial pressure to the bubble-point pressure, the formation volume factor increases. This is indicative of the crude oil expanding (remember, the formation volume factor is based on 1.0 STB of oil – when the FVF increases, it is because the volume in reservoir barrels, bbl, of that STB is getting larger). This is the typical behavior that would be expected by a slightly compressible fluid - as confining pressure is reduced, we would expect that the volume would expand.

When the reservoir pressure reaches the bubble-point pressure, the formation volume factor begins to decrease. This is indicative of the crude oil shrinking. This is the opposite of the expected behavior of a slightly compressible fluid. This implies that as confining pressure is reduced the volume of the crude oil gets smaller. The reason for this behavior is that the crude oil is composed of the liquid hydrocarbon and the gas dissolved in it. As the gas comes out of solution, the crude oil loses the volume occupied by the solution gas.

Oil FVF above the Bubble-Point Pressure Pressure, p > p_b

Because the formation volume factor of crude oil behaves differently above and below the bubble-point pressure, we must use correlations that show the proper trends. Since the crude oil behaves as a typical slightly compressible fluid above the bubble-point pressure, we can use the definition of compressibility, Equation 3.32, above the bubble-point pressure:

and

Where, for crude oils, we use p_b as the reference pressure.

Oil FVF below the Bubble-Point Pressure, p < p_b

Below the bubble-point pressure, we can use Standing’s correlation^[8] to estimate the oil phase formation volume factor:

with

Where:

• B_o is the oil formation volume factor, bbl/STB
• R_so is the solution gas-oil ratio of the crude oil, SCF/STB
• ϒ_g is the gas gravity (MW_g/MW_air), dimensionless (to be discussed)
• ϒ_o is the oil specific gravity (ρ_o/ρ_w), dimensionless
• T is the temperature, °F

These equations are valid below and up to and including the bubble-point pressure. Therefore, we can use these equations to generate B_ob for Equation 3.43b if it is unavailable from laboratory measurements.

Oil Phase Compressibility above the Bubble-Point Pressure, p > p_b

As discussed, above the bubble-point pressure, crude oil acts like a slightly compressible fluid. One correlation for oil phase compressibility, c_o, above the bubble-point pressure from Vazquez and Beggs^[9] is:

Where:

• c_o is the oil compressibility, 1/psi
• R_so is the solution gas-oil ratio of the crude oil (for p > p_b; R_so = R_{so i}), SCF/STB
• T is the temperature, °F
• ϒ_g is the gas gravity (MW_g/MW_air), dimensionless (to be discussed)
• °API is the API gravity, degrees API
• p is the pressure, psi

Oil Phase Compressibility below the Bubble-Point Pressure, p ≤ p_b.

Crude oil above the bubble-point pressure can contain large amounts of dissolved solution gas (high values of R_so). At higher R_so values, the crude oil has higher compressibility values due to the solution gas. At pressures below the bubble-point pressure, gas comes out of solution and the compressibility values begin to get smaller as the crude oil tends to behave more and more like a Dead Oil (dead oil is gas free oil; while crude oil with dissolved gas is often referred to as Live Oil). One common correlation for oil phase compressibility, c_o, below the bubble-point pressure from McCain, Rollins, and Villena^[10] is:

Where:

• c_o is the oil compressibility, 1/psi
• p is the pressure, psi
• T is the temperature, °F
• °API is the API gravity, degrees API
• R_{so b} is the solution gas-oil ratio of the crude oil at pb (R_so b = R_{so i}), SCF/STB

Oil Phase Density above the Bubble-Point Pressure, p > p_b

One the values of p_b, R_so, ϒ_g, B_o, and c_o are determined (either by laboratory measurements or by correlations), the oil phase density itself is specified (there are degrees of freedom remaining for ρ_o).  As we discussed earlier, above the bubble-point pressure, crude oil behaves like a slightly compressible fluid. As such, we can use the definition of compressibility based on density:

Now, if we assume 1.0 STB of oil, at reservoir conditions, then we have:

and

Substituting Equation 3.48 into Equation 3.47 results in:

After integration of Equation 3.49 we have:

Oil Phase Density below the Bubble-Point Pressure, p ≤ p_b

Below the bubble-point pressure, the crude oil loses mass (mass of the liberated gas), so we must account for the mass of the liquid oil and the mass of the gas remaining in solution when estimating the oil density below the bubble-point pressure. We can do this with a simple material balance. Below (and up to) the bubble-point pressure, the density of the crude oil can be calculated by dividing the total mass of the oil plus dissolved gas by the total volume. In terms of the properties discussed so far, we have:

Where:

• ρ_o is the oil density, lb/ft³
• ρ_{o ST} is the density of the dead oil (gas free oil) at stock tank conditions, lb/ft³
• ϒ_g is the gas gravity (MW_g/MW_air), dimensionless (to be discussed)
• R_so is the solution gas-oil ratio of the crude oil at p_r and T_r, SCF/STB
• B_o is the oil phase formation volume factor at p_r and T_r, bbl/STB

Note that we can use the properties in at the bubble-point pressure, R_{so i} and B_ob, in Equation 3.51 to obtain ρ_ob for input into Equation 3.50.

Oil Phase Viscosity above the Bubble-Point Pressure, p > p_b

The viscosity of a crude oil is also impacted by the amount of gas in solution.  The typical viscosity behavior of crude oil is shown in Figure 3.11.

Oil Phase Viscosity below the Bubble-Point Pressure, p ≤ p_b

The estimation of the oil viscosity below the bubble-point pressure is a two-step process. In the first step, the dead oil (gas free) viscosity is calculated and in the second step the live oil (oil with solution gas) viscosity is calculated. The dead oil viscosity at reservoir temperature can be calculate by^[11]:

The second step is to calculate the live oil viscosity with the dissolved gas:

with

and

Where:

• A and B are correlation parameters
• μ_oD is the dead oil at T_r, cp
• °API is the API gravity, degrees API
• T is the temperature, °F
• R_so is the solution gas-oil ratio of the crude oil at p_r and T_r, SCF/STB

Oil Phase Viscosity above the Bubble-Point Pressure, p > p_b

The oil viscosity above the bubble-point pressure can found by calculating the viscosity at the bubble-point pressure, μ_ob and R_{so i}, and adjusting it to higher pressures^[11]:

with

Where:

• C is a correlation parameter
• μ_ob is the live oil viscosity at p_b and T_r, cp
• p is the pressure of interest, psi
• p_b is the bubble-point pressure, psi

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For natural gases we are also most interested in the Gas Formation Volume Factor, B_g, and the Gas Viscosity, μ_g, as these properties strongly influence gas storage (and accumulation) and gas flow. For most reservoir engineering calculations, the gas formation volume factor (and Gas Compressibility, c_g, and Gas Density, ρ_g) can be determined from the Real Gas Law, Equation 3.27:

$$pV=ZnRT$$

Where:

• p is the pressure of interest, psi
• V is the volume, ft³
• Z is the oil super-compressibility factor, dimensionless
• R is the gas constant, (psi ft³) / (lb-moles °R)
• T is temperature, °R (°R = °F + 460.67)

Gas Super-Compressibility Factor, Z

The gas supercompresibility factor, Z (or Z-Factor, or Real Gas Deviation Factor), is a function of pressure and temperature that corrects the Ideal Gas Law for high pressure and high temperature conditions. In the oil and gas industry, the z-factor correlation for hydrocarbon gases that is universally accepted in the Standing-Katz Correlation^[12]. This correlation is shown graphically in Figure 3.12.

As illustrated in Figure 3.12 The Standing-Katz Correlation correlates the z-factor to the Pseudo-Reduced Pressure, p_pr, and Pseudo-Reduced Temperature, T_pr. The pseudo-reduced properties are defined by:

and

Where:

• p is the pressure of interest, psi
• p_pc is the pseudo-critical pressure, psi
• T is temperature of interest, °R
• T_pc is pseudo-critical temperature, °R

All of these properties are called pseudo-properties because the pseudo-critical pressure and pseudo-critical temperature are not the true, measured critical properties, but are calculated properties:

and

with

Where:

• p_pc is the pseudo-critical pressure, psi
• T_pc is the pseudo-critical temperature, °R
• ϒ_g is the gas gravity (MW_g/MW_air), dimensionless
• MW_g is the molecular weight of the gas, lb/lb-mole
• MW_air is the molecular weight of air, lb/lb-mole (28.97 lb/lb-mole)

In cases where significant concentrations of inorganic impurities, CO₂ and H₂S are present, then corrections to Equation 3.61 and Equation 3.61 are required:

and

with

Where:

• p_{pc corrected} is the corrected pseudo-critical pressure, psi
• p_{pc Eq. 3.61} is the pseudo-critical pressure from Equation 3.61, psi
• T_{pc corrected} is the corrected pseudo-critical temperature, °R
• T_{pc Eq. 3.60} is the corrected pseudo-critical from Equation 3.60, °R
• ϵ_correction is the correction for CO₂ and H₂S, °R
• y_CO2 is the mole fraction of CO₂ in the gas phase, fraction
• y_H2S is the mole fraction of H₂S in the gas phase, fraction

The Standing-Katz^[12] correlation has also been mathematically curve fit^[13]. The equation for z-factor then becomes:

with

It should be noted that the solution of this equation for the z-factor requires an iteration procedure. This is because the z-factor appears both on the left-hand side of Equation 3.66 and the right-hand side of the equation through the pseudo-reduced density, ρ_pr. Typically, this is solved with a Newton-Raphson iteration procedure which is beyond the scope of this class. For our purposes, if supercompressibility factors are required, we can simply read the chart to obtain them.

Real Gas Formation Volume Factor, B_g

The Formation Volume Factor, B_g, of a real gas, like its oil phase analog, is used to convert one standard cubic foot, SCF, of gas at reference conditions to its volume at reservoir conditions. For natural gases, in the U.S. domestic oil and gas industry, we use the standard conditions of p_SC = 14.7 psi and 60 °F. The gas formation volume factor for a real gas can be calculated directly from the Real Gas Law once we have an estimate of the super-compressibility factor. If we assume one lb-mole of natural gas, then the volume that it would occupy at standard conditions would be (assuming Z_SC = 1.0 at standard conditions – a very good assumption):

$$V_{SC}=\frac{Z_{SC}nR{T}_{SC}}{p_{SC}}=\frac{nR{T}_{SC}}{p_{SC}}\mathrm{in}f{t}^3;with{Z}_{SC}=1.0$$

At reservoir conditions, that same lb-mole would occupy a volume of:

$$V_r=\frac{ZnR{T}_r}{p_r}inf{t}^3$$

Now, the gas phase formation volume factor we can define as:

There are times when we would like to consider the volume of gas in reservoir barrels, bbl. This is because we have used reservoir barrels as the units for the liquid (oil and water) volumes, and we would like to determine the volume occupied by the gas and liquids combined. We can convert the units of Equation 3.68a by applying the unit conversion constant of 1 bbl = 5.615 ft³:

Where:

• B_g is the gas formation volume factor, ft³/SCF (Equation 3.68a) or bbl/SCF (Equation 3.68b)
• Z is the supercompressibility factor at reservoir conditions, p_r and T_r, dimensionless
• T_r is the reservoir temperature, °R
• T_SC is the reference (standard) temperature (520 °R in U.S. domestic industry), °R
• p_r is the reservoir pressure, psi
• p_SC is the reference (standard) pressure (14.7 psi in the U.S. domestic industry), psi

Real Gas Compressibility, c_g

The isothermal compressibility of a real gas can also be determined directly from the Real Gas Law. Starting with the definition of isothermal compressibility:

Substituting the Real Gas Law, Equation 3.27, into Equation 3.69:

or

The derivative, $\frac{dZ}{dp}$ , can be calculated by differentiating Equation 3.66 and Equation 3.67 with respect to pressure.

Real Gas Density, ρ_g

The density of a real gas can also be determined directly from the Real Gas Law. Starting with the Real Gas Law:

$$pV=ZnRT$$

Now the number of moles is equal to a mass divided by the molecular weight, n = m / MWg. Substituting into the Real Gas Law:

$$pV=\frac{ZmRT}{M{W}_g}$$

Now from the definition of gas density and the substitution of the Real Gas Law:

Where:

• ρ_g is the gas density, lb/ft³
• p is the pressure of interest, psi
• MW_g is the molecular weight of the gas, lb/lb-mole
• Z is the supercompressibility factor at reservoir conditions, p_r and T_r, dimensionless
• R is the Gas Constant, 10.73 ft³ psi / °R lb-mole
• T is the temperature of interest, °R

Real Gas Specific Gravity, γ_g

The specific gravity of a real gas can also be determined directly from the Real Gas Law. For gases, the specific gravity is defined as the ratio of the density of the gas to the density of air at standard conditions. Dividing Equation 3.71 written for a gas by Equation 3.71 written for air at standard conditions (Z = 1.0) results in:

Now, the molecular weight of gas is 28.87 lb/lb-mole:

Real Gas Viscosity, μg.

The viscosity of natural gases can be determined by the correlation of Lee, Gonzalez, and Eakin^[14]:

with

Where:

• μ_g is the gas viscosity, cp
• K, X, and Y are correlation coefficients
• ρ_g is the gas density at the pressure and temperature of interest, gm/cc
  $\left[{\rho }_g\left(gm/cc\right)=1.4935\times {10}^{-3}\frac{M{W}_{g}p}{zT}\right]$
• MW_g is the molecular weight of the gas, lb/lb-mole
• T is the temperature of interest, °R

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^[12] Standing, M.B. and Katz, D.L.: "Density of Natural Gases," Trans., AIME (1942) 146, 140-49.

^[13] Dranchuk, P.M. and Abou-Kassem, J.H.: "Calculations of z-Factors for Natural Gases Using Equations of State," J. Cdn. Pet. Tech. (July-Sept. 1975) 34-36.

^[14] Lee, A.L., Gonzalez, M.H., and Eakin, B.E.: "The Viscosity of Natural Gases," JPT (Aug. 1966) 997-1000; Trans., AIME (1966) 234.

To this point in the lesson, we have discussed Rock Properties and Fluid Properties, but we must also discuss how the rock and different fluids interact. In other words, how does the rock interact with the fluids and how do the various fluids interact with each other? At the pore and capillary scales, these interactions occur through the various attractive and repulsive forces acting on each component in the system (rock and fluids). These pore-scale forces include capillary forces, surface tensions, interfacial tensions, van der Waal forces, etc. While these topics are interesting in their own right, as engineers, we are interested in how these pore and capillary scale forces manifest themselves at a much larger macro-scale.

Phase Saturations, S_o, S_g, and S_w

To start the discussion about rock-fluid interaction properties, we must first define the phase saturations, S_o, S_g, and S_w, in the reservoir. The phase saturation is defined as the fraction of the pore volume occupied by a particular phase. For example, if the pore-volume of a porous medium by 65 percent oil, 25 percent gas, and 10 percent water, then the phase saturations would be:

• S_o = 0.65
• S_g = 0.25
• S_w = 0.10

Thus, if we had a core sample of rock with a bulk volume, V_b = 200.0 cc, an effective porosity, ϕ = 0.22, and the phase saturations listed above, then the core sample would contain:

• V_o=S_o V_p=S_oϕV_b = (0.65)(0.22)(200.0 cc) = 28.6 cc of oil
• V_g=S_g V_p=S_gϕV_b = (0.25)(0.22)(200.0 cc) = 11.0 cc of gas
• V_w=S_w V_p=S_wϕV_b = (0.10)(0.22)(200.0 cc) = 4.4 cc of water

where V_o, V_g, and V_w are the volumes of oil, gas, and water, respectively, in the core sample. By definition, the phase saturations must always sum to 1.0:

$${\displaystyle \sum _{f=o,w,g}{S}_f=1.0}$$

This relationship is known as the Saturation Constraint.

Capillary Pressure, p_cow and p_cgo

It has been observed that when two or more immiscible fluids occupy the pore-volume and capillaries of a porous medium, the pressures of the different phases are not equal, but are different from each other. This macro-scale phenomenon, known as capillary pressure, is due to interactions of the surface and interfacial tensions of the rock and fluids in the confined dimensions of the rock pores and capillaries. A force balance on the surface and interfacial tensions require that the pressures of the various phases are different. At the macro-scale, this phenomenon is quantified with the Capillary Pressure Relationships:

and

As shown in Equation 3.77 and Equation 3.78, the capillary pressure is the difference between the two phase pressures and is a function of the phase saturations. As written, these equations assume that the reservoir rock is Water Wetting Surface (the surface of the rock preferentially favors contact with the water phase). If we were to write these equations for an Oil Wetting Surface (the surface of the rock preferentially favors contact with the oil phase), then we would have:

and

We will not go into the details of Wettability, Water Wetting Surfaces, or Oil Wetting Surfaces; however, water wet reservoirs are the more common for petroleum rocks, and we will focus on them (Equation 3.77 and Equation 3.78). Please note that while water wetting rocks are the more common for reservoir rock lithologies, there are many examples of oil wet rocks in the petroleum literature. Figure 3.13 shows a typical drainage capillary pressure relationship for a water wet rock.

In Figure 3.13, the solid line is the drainage capillary pressure curve for a wetting phase (in our case, water in a water-wet rock). The capillary pressure, p_e, is the Entry Pressure which is the pressure that is required to force a non-wetting phase (in our case, oil in a water-wet rock). The entry pressure is the pressure that is required to force the first drop of oil into the water-wet rock. Remember, the term “water-wet” implies that the rock has a preference to stay in contact with water. The entry pressure is the pressure required to overcome this preference. At some value of water saturation, the capillary pressure measurements begin to go asymptotic to the vertical. This water saturation, S_wir, is the Irreducible Water Saturation and represents the minimum water saturation that the reservoir rock can reach in the presence of an oil phase. As indicated in this figure, irreducible water saturation is caused by capillary forces acting on the oil, water, and rock components of the system.

In this figure, the term “Drainage Capillary Pressure” appears; this refers to the manner in which the data were measured. There are two ways that we can measure capillary pressure. We could first fill the core sample with the wetting phase (in our case, water) and measure the capillary pressure by increasing the saturation of the non-wetting phase (in our case oil). This is identical to decreasing the saturation of the wetting-phase. This process, where the wetting phase saturation is decreased, is referred to as a Drainage Process and represents processes where the wetting phase is allowed to “drain” from the rock.

Alternatively, we could have first filled the core sample with the non-wetting phase (in our case, oil) and measured the capillary pressure by increasing the saturation of the wetting phase (in our case, water). This process, where the wetting phase saturation is increased, is referred to as an Imbibition Process and represents processes where the wetting phase is allowed to “imbibe” into the core. Both processes, drainage processes and imbibition processes, occur in oil and gas reservoirs.

It turns out that when you conduct the experiment using these two processes, you get different results. When this phenomenon occurs (measurements are dependent on the saturation history – increasing or decreasing wetting phase saturation), it is referred to as Hysteresis. Typical results for oil-water drainage and imbibition capillary pressure measurements including the impact of hysteresis are shown in Figure 3.14.

In Figure 3.14, we see that as we increase the saturation during an imbibition measurement cycle, the water saturation reaches an asymptotic maximum value, S_{w max} (or, 1 - S_orw). This trapped oil saturation, S_orw, is called the Residual Oil Saturation to Water and is the result of capillary forces occurring in the reservoir rock. We will discuss these end-point saturations, S_wir and S_orw, in more detail when we discuss relative permeabilities.

While both drainage processes and imbibition processes occur in the reservoir, the topic of hysteresis is beyond the scope of this course. For this course, we will focus on the drainage capillary pressure of water wet reservoirs.

In the laboratory, capillary pressures are measured using Special Core Analysis (also known as SCAL) methods and must be specifically requested from the core laboratory. The drainage capillary pressure curves (Figure 3.13 and green curve in Figure 3.14) can be estimated from the Brooks-Corey Model^[15]:

Where:

• pc_ow is the oil-water capillary pressure, psi
• λ is the pore-size distribution, dimensionless
• p_o and p_w are the pressures of the oil phase and water phase, respectively, psi
• p_e is the entry pressure, psi
• S_w is the water (wetting) phase saturation, fraction
• S_wir is the irreducible water saturation, fraction

In the Brooks-Corey Model^[15], λ, S_wir, and p_e can be obtained from the capillary pressure data. In addition, S_wir can be obtained from open-hole well logs or by relative permeability data.

Relative Permeability, k_row and k_rw

We have already discussed Darcy’s Law in the context of single-phase flow and absolute permeability. Darcy’s Law, Equation 3.24, was written earlier as:

$$q_f=\frac{0.001127kA}{{\mu }_f}\frac{\partial p}{\partial l}$$

Where q_f is the volumetric flow rate in bbl/day, and all of the properties used in Equation 3.24 were discussed earlier. Note that we can convert the units of flow rate in Darcy’s Law from bbl/day to STB/day by the inclusion of the formation volume factor of the flowing fluid, B_f:

One of the assumptions listed with these versions of Darcy’s Law was that the flowing fluid is an incompressible, homogeneous, Newtonian fluid that fully saturates (single-phase) the porous medium. As we have already seen, the flow of fluids in real petroleum reservoirs is typically up to three-phase flow, and in some rare instances, may be as high as four-phase flow.

For multi-phase flow, we can rewrite Equation 3.82 for each of the phases present, regardless of whether the fluids are mobile or are stationary (we only care about their presence). Assuming three phases; oil, water, and gas, we have:

and

Note that we have assigned a phase designation to both the pressure, p_f, and the permeability, k_f. As discussed earlier, due to the capillary pressures, each of the phases present in the reservoir may have a different pressure, and consequently, we must distinguish between pressures (and pressure gradients) that are specific to each phase.

When we write a permeability value that is specific to an individual phase, k_f, that permeability is referred to as the Effective Permeability to that phase. Therefore, in Equation 3.83, we have the effective permeability to oil, the effective permeability to water, and the effective permeability to gas (k_o, k_w, and k_g, respectively).

The effective permeability is defined as the permeability to a specific phase in the presence of one or more other phases. These effective permeabilities, k_f, are related to the absolute permeability, k, appearing in Equation 3.24 and Equation 3.82 through the Relative Permeability Relationships:

and

Where:

• k_ro, k_rw, and k_rg are the relative permeabilities to oil, water and gas, respectively, fraction
• k is absolute permeability (permeability for single-phase flow: Equation 3.24 and Equation 3.82), md

Substituting Equation 3.84 into these into Equation 3.83:

and

Relative permeabilities are functions of the phase saturations. A typical set of oil-water relative permeability curves is shown in Figure 3.15.

In Figure 3.15, the water saturation is plotted on the x-axis. The most important features that can be seen in this figure are the trends of the relative permeability curves. As the water saturation increase, the relative permeability to oil decreases while the relative permeability to water increases. This is because as the water saturation increases, fewer pathways become available for oil to flow while more pathways become available for water to flow.

In this figure, the parameters of irreducible water saturation, S_wir, and residual oil saturation to water, S_orw, are identical to the values discussed earlier in the section on capillary pressure curves and shown in Figure 3.14. The water saturation range, S_wir ≤ S_w ≤ 1 – S_orw, represents the range in which both the oil and water are mobile. Note that outside of this range, one of the relative permeability values is equal to zero, from Equation 3.85 a zero value of relative permeability implies that the flow rate will be zero.

On this plot, we can see that the maximum water saturation, S_{w max} = 1 – S_orw. We use this terminology because, as stated, the x-axis is the water saturation; while S_orw is an oil saturation. In other words, from Figure 3.15 we can see that S_orw is approximately 0.2, while due to the saturation constraint, ∑_f=o,wS_f  = 1, S_{w max} must be 0.8.

For a two-phase, oil-gas system we have a somewhat similar set of relative permeability curves as with the two-phase, oil-water system. Figure 3.16 shows a typical set of gas-oil relative permeability curves.

In the gas-oil relative permeability curves, the gas saturation, S_g, is plotted on the x-axis. There are several important differences between the oil-gas system and the oil-water system that must be further discussed. One difference is the critical gas saturation, S_gc. The critical gas saturation is similar to S_wir for water, in that it represents the value at which gas will begin to flow in situations the gas saturation is increasing (or, conversely, the saturation at which gas will stop flowing in situations the gas saturation is decreasing). We can also see oil is present and is mobile below S_gc (it has finite values below S_gc). This is because of the dissolved gas in the oil phase. As gas comes out of solution from a mobile oil phase, the gas saturation needs to build up to S_gc before it can begin to flow. While this is occurring, the oil phase remains mobile. Therefore, for gas-oil systems, oil is mobile in the range 0 ≤ S_g ≤ 1 – S_org – S_wir, and gas is mobile in the range S_gc ≤ S_g ≤ 1 – S_org – S_wir.

A second difference between the oil-water curves and the gas-oil curves is the use of the term k_row in Figure 3.15 and the term k_rog in Figure 3.16. This is because the relative permeabilities to oil are different when measured in an oil-water system and in a gas-oil system. The is also true for the residual oil saturations, S_orw and S_org. These differences are due to the differences in the surface tensions and resulting capillary forces between oil and water and between gas and oil.

A third difference is due to the irreducible water saturation, S_wir. As we have already discussed, the irreducible water saturation is the lowest water saturation in the reservoir. Since all real oil and gas reservoirs contain water, the initial water saturation in these reservoirs, S_wi, must be at least equal to the irreducible water saturation, S_wir, or greater: S_wi ≥ S_wir. Therefore, to get representative laboratory measurements or calculations from correlations, we must include S_wir in the analyses. Therefore, when we take laboratory measurements for gas-oil curves, we take them in the presence of an immobile, irreducible water saturation. Also note the application of the saturation constraint for the liquid (oil and water) saturations.

Relative permeability measurements also require special laboratory techniques and must be requested as a part of Special Core Analysis procedures when ordering tests from a core laboratory. There are two general approaches for laboratory measurements of relative permeability, the Unsteady State Method and the Steady State Method. Of the two methods, the Steady State Method (also known as the Penn State Method) is the more accurate laboratory procedure; however, it takes more time (and money) to perform these tests.

When laboratory data are not available, then the relative permeabilities can be calculated using a Power Law Model.

For oil-water curves, we have:

and

While for gas-oil systems we have:

and

Where:

• k_row is the relative permeability to oil measured in an oil-water system, fraction
• k_rw is the relative permeability to water measured in an oil-water system, fraction
• k_rog is the relative permeability to oil measured in a gas-oil system in the presence of an irreducible water saturation, fraction
• k_rg is the relative permeability to gas measured in a gas-oil system in the presence of an irreducible water saturation, fraction
• k_row(S_wir) is the relative permeability to oil at the irreducible water saturation measured in an oil-water system, fraction
• k_rw(1 – S_orw) is the relative permeability to water at the maximum water saturation, measured in an oil-water system, fraction
• k_rog(S_wir) is the relative permeability to oil at the irreducible water saturation measured in a gas-oil system in the presence of an irreducible water saturation, fraction
• k_rg(1 – S_liquid) is the relative permeability to gas at the maximum gas saturation, 1 – S_org – S_wir, in a gas-oil system in the presence of an irreducible water saturation, fraction
• S_o, S_w, and S_g are the oil, water, and gas saturations, respectively, fraction
• S_wir is the irreducible water saturations, fraction
• S_orw is the residual oil saturation to a water displacement
• S_org is the residual oil saturation to a gas displacement in a gas-oil system in the presence of an irreducible water saturation, fraction
• S_gc is the critical gas saturation where gas begins to flow in a gas-oil system in the presence of an irreducible water saturation, fraction
• n_ow and n_w are oil and water exponents, respectively, in an oil-water system (these exponents are referred to as Corey Exponents), dimensionless
• n_og and n_g are oil and gas exponents, respectively, in a gas-oil system in the presence of an irreducible water saturation (these exponents are also referred to as Corey Exponents), dimensionless

Most of these values can be seen in Figure 3.15 and Figure 3.16. Note that all of the groups in the parenthesis in Equation 3.86 through Equation 3.87 go from 0.0 to 1.0 in their respective mobile saturation ranges. These groups are often referred to as Normalized Saturations.

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^[15] Brooks, R.H. and Corey, A.T. 1964. Hydraulic Properties of Porous Media. Hydrology Paper No. 3, Colorado State University, Fort Collins, Colorado, 22–27.