Chapter 7

Production for Recovery

7.1 Drilling for Oil and Gas Recovery

Locating possible oil or gas accumulation is followed by exploratory drilling, during

which rock and fluid samples are collected for laboratory testing, and the reser-
voir structure is further defined. During this process and the subsequent drilling of
production wells, measure-while-drilling (MWD) technology analyzes sound waves
generated by drill bits to further refine structure maps. Exploratory drilling provides
the basis for refined estimates of the volume of reservoirs and their potential eco-
nomic value. If the refined estimates justify further investment, production wells are
drilled into the underground reservoirs.
Each reservoir can have multiple wells to ensure that the extraction rate is eco-
nomically optimal. Some secondary wells may also be used to pump water, steam,
chemicals or gas mixtures into the well to enhance productivity and to raise or main-
tain reservoir pressure and, consequently, the rate of extraction.
Key components of a drilling rig are shown in Fig. 7.1. To drill a well, a bit is
attached to the end of a drill string, which is comprised of sections of steel pipe that
are 30-feet (9 m) long. Drilling bits are designed to produce a generally cylindrical
hole in the Earth’s crust by rotary drilling. Many drill bits are encrusted with natural
or man-made diamonds or coated with tungsten carbide steel to increase the hardness
and extend the useful life of the bit. The drill string is lengthened as the well gets
deeper by attaching additional sections of pipe to the top. Drill collars are thick-walled
sections of drill pipe at the bottom of the drill string; collars apply extra weight to the
bit. As the bit cuts through rock, a drilling mud is pumped down through the inside
of the drill string, out the bit, and up through the space between the drill string and
the well bore.
Drilling fluids or drilling muds are designed blend of fluids, solids and chemicals.
They aid the drilling of boreholes into the earth in several ways: by providing hydro-
static pressure to prevent formation fluids from entering the well bore, by keeping
the drill bit cool and clean during drilling, by controlling downhole pressure, and by
carrying out rock cuttings back to the surface. The density of drilling mud is crucial.

© Springer Nature Switzerland AG 2019 97

C. S. Hsu and P. R. Robinson, Petroleum Science and Technology,
https://doi.org/10.1007/978-3-030-16275-7_7
98 7 Production for Recovery

Fig. 7.1 A drilling rig [1]

If the mud density is too low, a well is susceptible to a surface blowout. If the mud
density is too high, it can cause an underground blowout—the rupture of the reser-
voir underground—pushing drilling mud into another formation. The cuttings are
removed in shakers, and the fluid goes back to the mud pit, from which it is recycled.
A derrick is used to support drilling apparatus, which must be tall enough to
accommodate a 90-foot-long “triple” comprised of three sections of pipe. For off-
shore drilling, a platform must be built for support of the drilling rig. The drilling
system includes the power system (diesel engine and electric generator), the hoisting
system, rotating equipment, casing, the circulation system, and the blowout preven-
ters. The derrick, pulleys and hawser must be robust enough to support the lifting
and manipulation of the entire drill string, which can weigh hundreds of tons. The
kelly is the top joint of a drill string. It has flat sides that fit inside a bushing on the
7.1 Drilling for Oil and Gas Recovery 99

rotary table, which turns the drill string and bit. Note that not all drilling rigs use a
kelly system.
As the drill begins tunneling through the ground, chunks of rock and mud are
sucked into the pipe by pumps. The chunks are circulated out of the hole and into
pits on the surface previously carved by the drilling crew. The derrick is tall enough
to allow new sections of pipe to be added as the hole becomes deeper. After a certain
depth, depending on the oil reserve, the drill must be pulled out and the well must be
cased to prevent the hole from collapsing in on itself. Casing involves placing steel
piping into the hole and then pumping cement into the annular space between the
outside of the casing and the rock. Centralizers are sections of pipe which keep the
casing from resting against the surrounding wellbore wall, as in Fig. 7.2. Once this
section of the hole is deemed secure enough, the crew continues to drill deeper with
drill pipe of ever narrower diameters. This cycle of drilling, casing and cementing is
done until the final pre-determined depth is reached within the reservoir rock.
Throughout the drilling process, the location and direction of the drill bit is deter-
mined. Well logs are evaluated and cuttings are analyzed, and if necessary the drilling
plan is adjusted accordingly. When drilling is complete and tests have confirmed that

Fig. 7.2 Casing with bow-string centralizers that allow cement to flow through all empty annular
space between casing and well bore
100 7 Production for Recovery

the location is correct, preparations to extract the oil commence. A perforating gun
with explosive charges is dropped into the well to perforate the casing to allow the
flow of oil up the pipe.

7.2 Well Completion

Wells are completed by casing the well bore with steel pipe and cementing the
casing into place. Casing prevents the well from collapsing. The outside diameters
of casing pipe range from 4.5 to 16 in. (114–406 mm). Cementing is a key step. In
a good cement job, the entire annular space between the casing and the well bore is
filled with cement. Centralizers keep the casing from resting against the well bore to

Fig. 7.3 Well completion with cement

7.2 Well Completion 101

block the flow of cement, resulting in a poor cement job and increasing the risk of a
blowout. Figure 7.3 shows well completion with cementing.
The integrity of cementing is tested by a positive-pressure test and a negative-
pressure test. In the positive-pressure test, the pressure in the steel casing is increased
to see if it is intact along with seal assembly. In the negative-pressure test, the pressure
is reduced to below atmospheric to test the integrity of the cement at the bottom of
the hole. The test is deemed successful if the pressure remains low after the suction
is stopped.
A key consideration during completion is the weight of the well casing, which rests
on the bottom of the well bore, creating friction that limits the distance/depth (D/D)
ratio. Long, shallow wells are especially susceptible to D/D limitations. In extended-
reach horizontal drilling (ERHD) technology, [2] a special tool at the bottom of
the casing allows the casing to be filled with air instead of mud. This reduces the
friction substantially, allowing much higher D/D ratios. The technology is employed
in certain wells at Wytch Farm, England. On Platform Irene offshore California,
ERHD enabled Unocal to set records, both for horizontal reach (14,671 ft), widest
pay zone (5990 ft) and greatest angle of deviation from vertical (76°) [3]. Those
records have since been broken, and the technology has advanced, but the invention
by Mueller, et al. [2] was a significant first step. After cementing, perforation guns
punch small holes through the casing into the reservoir rock, providing a path for the
flow of oil and gas into the well. In open-hole completion, the last section of the well
is uncased. Instead, the installation of a gravel pack stabilizes the casing and allows
fluids to enter the well at the bottom. After perforation, special acid-containing fluids
are pumped into the well to increase porosity and stimulate production. Usually, a
smaller diameter tube is inserted into the casing above the production zone and
packed into place. This provides an additional barrier to hydrocarbon leaks, raises
the velocity at which oil flows under a given pressure, and shields the outer casing
from corrosive well fluids.
A blowout preventer (BOP), shown in Fig. 7.4, seals the high-pressure drill lines
and relieves a sudden increase in well pressure into the atmosphere for uncontrolled
gush or gas. The BOP is a collection of safety valves and other devices at the top of
a well. It is located on the surface for an onshore well. It can be placed beneath the
ocean on the sea floor for an offshore well. When activated, it stops a blowout by
sealing off the top of the well.
Underground blowouts are the most common of all well control problems. Many
surface blowouts begin as underground blowouts. Prompt, correct reaction to an
underground event can prevent a dangerous and costly surface blowout [5]. The
severity of the BP Deepwater Horizon oil spill in 2010 was aggravated by the failure
of a blowout preventer.
102 7 Production for Recovery

Fig. 7.4 Blowout preventer (BOP) [4]

7.3 Directional Drilling/Horizontal Drilling

Conventional vertical wells are drilled straight down into the earth. Descriptions of
such wells in China, drilled with bamboo poles, date back to 1500 BC. Vertically
drilled wells are only able to access the targeted gas and/or oil that immediately
below the well. Using horizontal or directional drilling techniques, shown in Fig. 7.5,
a number of wells can be drilled in different directions from a single well pad, which
is much more efficient than having numerous vertical well pads set up to extract oil
or gas. This decreases the surface disturbance and reduces the overall cost of well
pad setups, replacements and maintenance. This is especially beneficial offshore,
because it can decrease the required number of expensive platforms by an order of
magnitude. Tremendous savings are realized when offshore oil can be reached from
onshore drilling sites, as is the case for many wells in the huge Wytch Farm oil field
in the Purbeck District of Dorset, England.
Horizontal drilling technology achieved commercial viability during the late
1980s. Two key components in directional/horizontal drilling plays are mud motors
and measurement while drilling (MWD) sensors. Mud motors can rotate the drill
7.3 Directional Drilling/Horizontal Drilling 103

Fig. 7.5 Directional drilling (left) and horizontal drilling (right) wells [6]

bit without rotating the entire length of drill pipe between the bit and the surface.
Figure 7.6 shows bent sections of pipe (bent subs) which compel the bit to follow a
path that deviates from the previous orientation. MWD sensors are used determine
the azimuth and orientation of the bit. A rotary steerable system (RSS) employs spe-
cialized downhole equipment to replace conventional directional tools such as mud
motors, allowing operators to steer the drill bit in real time.
In the past few years, directional drilling combined with hydraulic fracturing has
been applied to tight rock formations, resulting fantastic production of oil and/or
natural gas from reservoirs which were otherwise unproductive. Major examples are
the Eagle Ford Formation near Three Rivers, Texas, the Bakken Formation of North
Dakota, and the Marcellus Shale of the Appalachian Basin. Due to this technology,
the United States is now among the top oil producers in the world.
The availability of directional/horizontal drilling also stimulates the development
of in situ toe-to-heel air injection (THAI) combustion and steam-assisted gravity
drainage (SAGD) production of heavy oil and bitumen to be discussed later.

7.4 Offshore Drilling

The term of “offshore drilling” refers to drilling activities on the continental shelf,
although the term can also be applied to drilling in lakes, inshore waters and inland
seas. In offshore drilling, a well is drilled below the seabed to explore for and sub-
104 7 Production for Recovery

Steering tool

Orienting sub

Bent sub or
bent mud
motor housing

Bit

Fig. 7.6 Arrangement of a steering tool, orienting sub, and bent sub for directional drilling

sequently extract petroleum which lies in undersea rock formations. Offshore wells
can be drilled from onshore or from platforms.
For offshore wells, two depths are important: the depth of the water, and the
distance from the top of the sea bed to the pay zone [7]. Both must be considered when
selecting a platform design. Another consideration is metocean, i.e., meteorology
and oceanography, involving the quantification of winds, waves, currents and related
physical phenomena in the ocean and atmosphere. United Nations Convention on
Law of the Sea is used for the determination how far we can drill offshore from the
coastline. Figure 7.7 shows the main offshore oil production region in the world as
of 2012 [7].
7.4 Offshore Drilling 105

Fig. 7.7 Main offshore oil production regions in the world as of 2012 [7]

Fig. 7.8 Mobile offshore drilling units

As of 2010, offshore drilling as deep as 3 km below water was possible. The

equipment that does this is called a mobile offshore drilling unit (MODU). There
are four main types of MODUs in use today for exploration: submersibles, jack ups,
drill ships, and semisubmersibles, shown in Fig. 7.8.
In shallow waters, jack-ups and submersible rigs usually are used. Submersible
MODUs rest about 30 ft below the water on the sea floor. They are connected through
steel posts to drilling platforms on the surface. A jack up sits on top of a floating
barge. The rig’s legs extend as far as 550 ft to the ocean floor as sort of stilts to
106 7 Production for Recovery

raise the rig above the surface and keep it safe from choppy waters; an example is
shown in Fig. 7.8. Semisubmersible rigs and drill ships are used in deeper waters.
Semisubmersible rigs simply let in enough water to lower the platform to appropriate
operating heights. The weight of the lower hull stabilizes the drilling platform, while
massive anchors hold it in place. Drill ships that have a drilling rig on the top deck use
dynamic positioning equipment to maintain alignment with the drilling site, guided
by satellite information and underwater sensors on the subsea drilling template to
keep track of the drilling location.
The major production structures and systems are summarized in Fig. 7.9 [4]. Fixed
platforms or jackets are used for water less than 1500 ft deep with mild climates.
Locations suitable for such platforms are not only constrained by water depth, but
also by the wind and wave strength. Compliant towers are designed to sway and
move with the stresses of wind and sea. Sea Star platforms are a larger version of
submersible designs and are connected to the ocean floor by tension legs. Both of
these platforms operate at water depths up to 3500 ft. For deeper waters, floating
production systems, tension leg platforms (TLP), and subsea systems transfer the
oil and natural gas to production facilities, either by risers or undersea pipelines.
For waters deeper than 7000 ft, a spar platform on a giant, hollow cylindrical hull is
used. The most sophisticated and versatile floating production systems are floating,
production, storage and offloading (FPSO) platforms. FPSOs include an offloading
and storage capacity, They are the obvious choice for stranded fields where there is
no existing pipeline infrastructure. FPSOs store oil, typically about a million barrels,
and offload that oil to a tanker. They are typically fitted with extensive onboard
separation and processing equipment. An example of FPSOs is shown in Fig. 7.10.
As mentioned earlier, the greatest water depth a jackup can drill in is 550 ft.
Many newer jackup units have a rated drilling depth of 35,000 ft. On the floating rig
side, the deepest water depth so far is 12,000 ft. A handful of these rigs have a rated
drilling depth of 50,000 ft, but most of the newer units are rated at 40,000 ft [9].

7.5 Primary Recovery—Primary Oil Production

In primary oil recovery, fluids are pushed into the production well and up to the
surface by natural forces: gas drive and water drive. Gas drive is the most efficient.
Oil is pushed by natural underground pressure, usually supplied by associated natural
gas, liquid expansion and evolution of dissolved gas, shown in Fig. 7.11. Once the
wellbore is drilled, the free gas begins to expand. The expansion energy of the gas
is what allows it to rise out of the reservoir and travel to the surface. The gas-oil
contact plane drops as the oil is depleted. The next most efficient propulsive force
is natural water drive, in which the oil is driven upward under hydrostatic pressure
and into the well by expansion of water inside the reservoir, also shown in Fig. 7.11.
Below the natural resource is an aquifer. The water that drives this kind of recovery
can be either located beneath the natural resource or on the edges of the reservoir in
which the resource is contained. Once the wellbore is drilled into the reservoir, water
7.5 Primary Recovery—Primary Oil Production 107

Fig. 7.9 Major offshore production structures and systems [7]

in the aquifer begins to push the hydrocarbons to the surface until they have been
completely displaced or until the point at which so much water has accumulated in
the well that it is no longer a quality resource.
The efficiency for primary recovery is generally low. Primary recovery typically
recovers 5–15% of oil in the reservoir due mostly to microscopic trapping and bypass-
ing of the remaining oil [10].
108 7 Production for Recovery

Fig. 7.10 A colossal offshore platform lights up the night off the coast of Norway [8]

Oil producing well

Fig. 7.11 Primary oil recoveries by gas drive and water drive
7.6 Secondary Recovery 109

7.6 Secondary Recovery

In primary recovery, the natural force used to drive the resource to the surface will
eventually decrease and become not sufficient. To compensate, an artificial lift system
using mechanical energy may be implemented to aid in the recovery of the natural
resource in a more economical fashion. This mechanism is secondary recovery.
Horsehead pumps or sucker-rod pumps are common surface implements. Submerged
pumps also are used. As with primary recovery, a single production well can be used
for artificial lift.
Water injection (water flood) or gas injection (gas flood) stimulate production by
increasing reservoir pressure or displacement of oil towards the production wells.
At least two wells are used: an injection well and one or more production wells.
Typically, the gas is reinjected natural gas. Another method is gas lift in which
compressed air, water vapor, carbon dioxide or some other gas is injected into the
bottom of an active well, reducing the overall density of fluid in the wellbore. Gas
injection delivers a necessary amount of compressed gas to a distribution cap, pushing
the oil out of the reservoir. Water injection involves pumping water into the reservoir
to displace the natural resource to an adjacent production well.
Figure 7.12 generically illustrates the use of a combination of injection and pro-
duction wells to stimulate production, via both secondary and tertiary recovery. On
average, primary and secondary recovery methods combined allow 20–40% of the
reservoir oils to be recovered [11].

Fig. 7.12 Generic depiction of injection and production wells for secondary and tertiary recovery
110 7 Production for Recovery

7.7 Tertiary Recovery (Enhanced Oil Recovery)

Tertiary recovery, also known as enhanced oil recovery (EOR), is used to extract
the remaining oil from reservoirs where primary and secondary recoveries are no
longer cost effective. Many sandstone or carbonate reservoirs have low primary and
secondary recovery due to poor sweep efficiency for bypassed or unswept oil. EOR
may also be used to stimulate production from reservoirs containing very viscous
crude oils and from low-permeability carbonate reservoirs. It is designed to reduce
viscosity of the crude oil. According to the US Department of Energy (DOE), there
are three primary techniques for EOR: gas injection, chemical injection and thermal
recovery. Using EOR, 30–60%, or more, of the formation and reservoir’s original
oil can be extracted, compared with 20–40% using primary and secondary recovery.

7.7.1 Gas Injection

Miscible flooding is considered one of the most effective enhanced oil recovery
processes applicable to light-to-medium oil reservoirs. This method can yield as
much as 17% of a field’s original oil-in-place. It is accomplished with hydrocarbon
solvents or gases such as carbon dioxide, natural gas, or liquefied petroleum gas
(LPG). The injected fluids are capable of displacing crude oil for recovery from the
reservoir rock. Supercritical CO2 has a viscosity similar to hydrocarbon miscible
solvents. Both improve volumetric sweep-out when there is an unfavorable viscosity
ratio in the reservoir. However, the CO2 density is similar to that of oil. Therefore,
CO2 floods minimize gravity segregation compared with the hydrocarbon solvents.
Introducing miscible gases reduces the interfacial tension between oil and water,
maintains reservoir pressure, and improves oil displacement. CO2 is most commonly
used, because it reduces the oil viscosity and is less expensive than LPG.
One difficulty with CO2 injection is that petroleum companies must first secure,
transport, and store an adequate supply of CO2. However, CO2 is a green-house gas
produced in large volumes by many industrial factories. CO2 capture and sequestra-
tion (CCS) by using it to stimulate oil production mitigates two important problems.
Certain producers inject CO2 injection into coal mines to produce coal-seam methane
[12].
Not all locations and reservoirs are appropriate for this technique; Suitability
depends on geology and fluid characteristics. Nitrogen gas can be used in combination
with CO2 flooding when complete CO2 flooding is not economical. Nitrogen and
flue gas are lower in cost and have shown success in re-pressuring reservoirs.
7.7 Tertiary Recovery (Enhanced Oil Recovery) 111

7.7.2 Chemical Injection

There are many chemicals that can improve oil mobility by reducing its viscosity
and/or reducing the intermolecular interactions which hold oil onto rock. Chemical
methods include polymer flooding, surfactant flooding and alkaline flooding. In all
of the chemical injection methods, the chemicals are injected into several wells
(injection wells) and the production occurs in other nearby wells (production wells).

7.7.2.1 Polymer Flooding

Polymer (augmented) flooding consists in mixing a dilute solution of a water-

soluble polymer, such as polyacrylamides (PAM), partially hydrolyzed polyacry-
lamide (HPAM), or xanthan gum (a polysaccharide biopolymer), to increase the
viscosity of the injected water and improve the mobility ratio between the injected
and in-place fluids. The polymer solution affects the relative flow rates of oil and
water and sweeps a larger fraction of the reservoir than water alone, thus increasing
the amount of oil recovered in some formations. This method is suitable for hetero-
geneous reservoirs (fractures, layers with large permeability contrasts, impermeable
layers) where the oil’s viscosity is too high for normal extraction.

7.7.2.2 Surfactant (Micellar) Flooding

Surfactant flooding recovers additional oil left behind by waterflooding. Surfactants

may be used in conjunction with polymers. Much of the remaining oil is trapped
in capillaries as microscopic oil droplets, which usually constitute more than half
the residual oil. By the injection of surfactant solution, the oil is mobilized through
a large reduction in the interfacial tension between oil and water. The decrease in
oil/water surface tension reduces residual oil saturation and improves the macro-
scopic efficiency of the process.
Dilute solutions of surfactants such as sulfonates or biosurfactants such as rham-
nolipids may be injected. Primary surfactants usually are augmented with co-
surfactants, activity boosters, and co-solvents to improve stability of the formulation.
Figure 7.13 depicts a two-step enhanced oil recovery process, in which a surfactant
slug is injected into the well followed by a larger slug of water containing a high-
molecular-weight polymer, which acts like a piston to propel the chemicals.

7.7.2.3 Caustic Flooding (Alkaline Flooding)

Caustic flooding, also called alkaline flooding, is accomplished by adding sodium

hydroxide to injection water. Alkaline flooding is a very complex process. It improves
oil recovery by using in situ surfactants (soap) produced from the reaction of alkali
112 7 Production for Recovery

Fig. 7.13 Recovery by alkaline-surfactant-polymer (ASP) flooding [12]

and the organic acids naturally occurring in the oil. It enhances oil recovery by
lowering the interfacial tension, decreasing the rock wettability, emulsification of
the oil, mobilization of the oil, and helping to draw the oil out of the rock.
Caustic flooding is usually accompanied in conjunction with surfactant and poly-
mer flooding. The combination is called alkaline-surfactant-polymer (ASP) flooding,
shown in Fig. 7.13, in which the three slugs are used in sequence. Alternatively, the
three fluids could be mixed together and injected as a single slug. The objective of
the ASP flooding process is to reduce the chemical consumption per unit volume of
oil, resulting in a reduction in cost.

7.7.3 Microbial Stimulation

Microbial injection is part of microbial enhanced oil recovery (MEOR) and is rarely
used because of its higher cost and because the method is not widely accepted.
These microbes function either by partially digesting long hydrocarbon molecules,
by generating biosurfactants, or by emitting carbon dioxide which can be used in gas
injection.
7.8 Thermal Recovery 113

(Days to Weeks) (Days) (Months to Months)

oil + water
steam

Fig. 7.14 Huff and puff cyclic steam injection [14]

7.8 Thermal Recovery

Various methods are used to heat the crude oil in the formation to reduce its viscosity
and surface tension, thus, increasing the permeability of the oil. The heated oil may
also vaporize and then condense forming improved oil. Methods include cyclic steam
injection (Huff and Puff), steam flooding, and combustion.

7.8.1 Cyclic Steam Stimulation (Huff and Puff)

Cyclic steam stimulation (CSS) is also known as the Huff and Puff method, shown
in Fig. 7.14. It requires only one wellbore and consists of 3 stages: injection (Huff),
soaking, and production (Puff). First, steam at elevated pressure is injected into a
well at a temperature of 300–340 °C for a period of weeks to months. Next, the
well is allowed to sit for days to weeks to allow heat from the elevated pressure
steam to soak into the formation and reduce the viscosity of the oil around the well.
Finally, the hot oil is pumped out of the well for a period of weeks or months.
Once the production rate falls off, the well is put through another cycle of injection,
soaking, and production. The process is used for thinner shallow production near
bitumen reservoirs. High reservoir porosity and oil saturation is ideal for this method
of recovery. This process is repeated until the cost of injecting steam becomes higher
than the money made from producing oil [13]. This process can typically remove
about 25% of the total reserve.
Steam degrades (weakens) the formation by removing alkali- and alkaline-earth
ions from reservoir constituents, such as particulates, thereby causing the forma-
tion to swell. This decreases permeability and slows down production. Watkins and
Kalfayian [15] invented methods for decreasing swelling by injecting ammonium
salts and ammonia precursors with the steam, replacing the removed K+ , Mg2+ , etc.,
with NH4 + .
114 7 Production for Recovery

7.8.2 Steam Flooding (Steam Stimulation or Steam Drive

Injection)

Steam flooding is also known as steam drive injection or steam stimulation, shown
in Fig. 7.15. In this method, some wells are used for steam injection and other
wells for oil recovery. Two steps are involved: first, the oil is heated by steam to
higher temperatures to decrease its viscosity so that it more easily flows through the
formation toward the producing wells; second, the oil is pushed to the production
wells in a similar manner as water flooding. More steam is needed for this method
than for the cyclic method.

7.8.3 In Situ Combustion (Toe-to-Heel Air Injection)

The steam injection methods mentioned above are applicable for oils with viscosities
in the range of 100–10,000 cP. Heat provided by the steam reduces the viscosity of
the oil, thereby making it mobile. For heavy oils and bitumen with viscosities greater
than 10,000 cP, combustion becomes the method of choice.
An effective and revolutionary in situ combustion method for producing heavy
oil is THAI (toe-to-heel air injection) [16], shown in Fig. 7.16. THAI combines a

Fig. 7.15 Steam drive injection (steam flooding or steam stimulation) [12]
7.8 Thermal Recovery 115

vertical air injection well with a horizontal production well. THAI is also applicable
to horizontal wells, which due to their geometry are not suitable for steam injection
methods.
For the first few months, steam is injected in the vertical well to preheat the hori-
zontal well and condition the reservoir around the vertical well. Then air is injected
in the vertical well and combustion initiated. The combustion raises temperatures
to approximately 400–600 °C (750–1110 °F). At these temperatures, both thermal
cracking and coking occurs. In this process, about 10% of the oil is lost to coke. The
oil from thermal cracking is of higher quality than reservoir oil. The mobilized oil
flows by gravity as a toe to the horizontal section of the L-shape production well.
The combustion front sweeps the oil from the toe to the heel of the horizontal pro-
ducing well, recovering the original oil-in-place while partially upgrading the crude
oil in situ. The combustion gasses bring the mobilized oil and vaporized water to the
surface, so no pumps are needed.
Another good feature of this process is the minimal amount of water supply
needed. Once the first few months of steam injection has been completed, no more
water or even natural gas is used. Combustion continues as long as air is injected.
With less equipment also comes a smaller footprint at the surface and less land is
required. The combustion is also self-limiting, so as soon as air injection is stopped
the flames burn out. With this method, the area at and near the combustion zone will
turn into coke Eventually, the reservoir no longer retains any oil or natural gas.

Fig. 7.16 Toe-to-heel air injection (THAI) for oil recovery [17]
116 7 Production for Recovery

7.9 Recovery of Heavy Oils and Bitumen

Heavy crude oil or extra heavy crude oil is highly viscous, and cannot easily flow
under normal reservoir conditions. Heavy crude oil has been defined as any liquid
petroleum with an API gravity less than 20°. In 2010, the World Energy Council
defined extra heavy oil as crude oil having a gravity of less than 10° and a reservoir
viscosity of no more than 10,000 cP. Compared to the lighter crude oils, heavy
crude oils have higher viscosity and specific gravity, as well as heavier molecular
composition with significant contents of nitrogen, oxygen, and sulfur compounds
and heavy-metal contaminants.
Natural bitumen, including tar sands or oil sands, shares the attributes of heavy
oil but is yet more dense and viscous, having a viscosity greater than 10,000 cP.
Natural bitumen and heavy oil resemble the resids from the refining of light crude
oil. They are thought to be the residue of formerly light oil that has lost its light-
molecular-weight components through degradation by bacteria, water-washing, and
evaporation (weathering). Conventional heavy oils and bitumens differ in the degree
by which they have been degraded from the original crude oil.
According to World Resources Institute, remarkable quantities of heavy oil and
oil sands are found in Canada and Venezuela. The largest reserves of heavy crude
oil in the world were located north of the Orinoco Basin in eastern Venezuela. It was
estimated that there were 270 billion barrels of recoverable heavy or extra-heavy
oil reserves in the area, similar to the amount of conventional oil reserves in Saudi
Arabia.
Heavy oil and bitumen are recovered in several ways. They can be dug out with
conventional mining techniques, or they can be liquefied by the injection of high-
pressure steam, for example in cyclic “huff and puff” operations (see above).
At surface facilities, notably in Venezuela and Canada, recovered heavy oil and
bitumen are diluted with lighter hydrocarbons. The resulting “Dilbit” (diluted bitu-
men) flows under ambient conditions, so it can be transported conventionally in
pipelines and oil tankers.
Kerogen is recovered from oil shale by several methods. From 1985 to 1990,
Unocal recovered some 4.6 million barrels of synthetic crude oil from oil shale in a
complex mining and upgrading venture at Parachute Creek, Colorado [18]. The plant
yielded roughly 40 gallons of oil per ton of rock. In the vertical-shaft retort, crushed
kerogen-containing shale was pumped up from the bottom of the retort vessel. Hot
recycle gas flowed counter-currently downward, decomposing the rock and releasing
hydrocarbons. Condensed shale oil was removed from the retort at the bottom. Part
of the hot gas was recycled. The rest either was used to produce heat and hydrogen,
or recovered as product. The spent shale was removed from the top of the retort,
cooled, and stored in pits or returned to the mine. In the reducing environment of the
retort, sulfur and nitrogen were converted to H2 S and NH3 , which were recovered
from product gases by conventional means. The plant yielded high-quality synthetic
crude oil suitable for further refining in conventional facilities.
7.9 Recovery of Heavy Oils and Bitumen 117

More discussions on diluted bitumen and synthetic crude oil for transportation
can be found in Chap. 17, which covers mid-stream operations.
Other oil shale processes involve partial combustion, either underground, at the
surface, or in shafts drilled horizontally into kerogen-rich formations. From 1972
to 1991, Occidental Petroleum developed an in situ process, in which explosives
were used to create underground chambers of fractured oil shale. The oil shale was
ignited with external fuel, and air and steam were injected to control combustion.
The hot rock fractured and released shale oil, which was pumped to the surface from
a separation sump and collecting well.
Bitumens derived from oil shale and many tar sands contain small but significant
amounts of arsenic, which are severe poisons for catalysts in refineries.

7.9.1 Canadian Oil Sand (Tar Sand) and Bitumen

As mentioned earlier, the Western Canadian Sedimentary Basin contains world’s

largest reserve of oil sands. Total natural bitumen reserves in the world are estimated
at 249.67 billion barrels, with 70.8% in Canada. The largest fields are located in
northern Alberta, Athabasca, Cold Lake and Peace River, shown in Fig. 7.17.
The oil sands are loose sand or partially consolidated sandstone containing natu-
rally occurring mixtures of sand, clay, and water, saturated with a dense and extremely
viscous form of bitumen. Bitumen is so heavy and viscous (thick) that it will not
flow unless heated or diluted with lighter hydrocarbons. The viscosity of bitumens
is greater than 10,000 centipoises under reservoir conditions and their API gravities
are less than 10° API.

7.9.2 Recovery of Oil Sand Bitumen

Oil sands are recovered using two main methods: open-pit mining and in situ drilling.
The method depends on how deep the reserves are deposited. In Alberta, 97% of the
total surface area of the oil sands region could be developed in situ.

7.9.2.1 Open Pit Mining

Approximately 20% of the oil sands lie close enough to the earth’s surface to be
mined, which impacts 3% of the surface area of the oil sands region.
Open-pit mining is similar to many coal-mining operations. Large shovels scoop
the oil sands into trucks, which take it to crushers, where the large clumps are broken
down. The oil sand is then mixed with water and transported by pipeline to a separa-
tion plant. A combination of very hot water, agitation, and other processing methods
are required to increase bitumen separation to about 75%. The resulting bitumen is
118 7 Production for Recovery

Fig. 7.17 Oil sand fields in northern Alberta, Canada [19]

not very usable, though, and has to be upgraded. Roughly two tons of sand must
be processed to produce just one barrel of useable oil, so the return on investment
for this method is extremely low; not to mention all of the negative environmental
impacts. Compared to other methods, it has the largest land-use footprint, produces
the most greenhouse gases. It negatively affects surrounding wildlife, and pollutes a
vast amount of water. So companies generally try to avoid this if possible.
Tailings ponds are an operating facility common to all types of surface mining.
In open-pit oil sands processing, tailings consisting of water, sand, clay and residual
oil are pumped to these ponds, where settling occurs. According to industry sources,
78–86% of the water is recovered and reused [20]. Supposedly, when the ponds are
7.9 Recovery of Heavy Oils and Bitumen 119

no longer required, the land will be reclaimed. Reclamation could be troublesome,

because the tailings contain significant amounts of arsenic in concentrations high
enough to be toxic but too low to be of any commercially value.

7.9.2.2 Cold Heavy Oil Production with Sand (CHOPS)

One of the simpler methods of heavy oil extraction is the Cold Heavy Oil Production
with Sand method or CHOPS. This method is simpler because it does not require
sand filtration, allowing sand and oil to be extracted together. The method works
because removing sand creates more space within the reservoir, allowing larger
pockets of liquid oil to form. It’s called “Cold” because there no heat is injected into
the reservoir, so it’s also relatively energy efficient. This method isn’t super effective
and can only recover about 5–6% of the oil within the deposit, but since there is
no heat injection it is pretty cheap to employ. The disposition of the oily sand, after
it has been separated from the extracted liquid, is challenging. Some is used in the
construction of asphalt roads, but there are some problems with that too. Most is
currently deposited in underground salt caverns.

7.9.2.3 In Situ Drilling/Steam Assisted Gravity Drainage (SAGD) [21]

The majority of the oil sands lie more than 70 m (200 ft) below the ground and are
too deep to be mined. These reserves can be recovered through wells with thermal
stimulation, as discussed above.
A form of steam flooding that has become popular since 1996 in the Alberta
oil sands is steam assisted gravity drainage (SAGD), in which two horizontal wells
are drilled, one a few meters above the other. Steam is injected into the upper well
as shown Fig. 7.18. The steam injection can also be performed by multiple verti-
cal injection wells above the horizontal production well. The steam increases the
temperature of the oil sand around it. The viscosity of the oil sand decreases as the
temperature increases. The oil sand and condensed steam trickle down due to gravity.
The condensed steam and less viscous bitumen from the oil sands flow into the lower
horizontal production well. Pressure pushes the bitumen and water into the storage
tanks above ground. The bitumen-water mixture is separated into bitumen and water.
The bitumen goes off to be refined while part of the water is recovered and recycled
within the process. SAGD is a unique process that has taken precedence, due to its
higher recovery, lower cost, and greater efficiency. The development of SAGD is
fairly new in comparison to other methods of oil recovery. The progress of drilling
techniques overlapped with the development of SAGD, so the use of horizontal wells
became less expensive and more efficient. SAGD recovery ranges from 50 to 70%
of oil-in-place.
In SAGD, some of the lighter contaminants will rise with the steam and won’t
have to be separated later. This doesn’t happen with a lot of other heavy oil extraction
methods. However, it has some drawbacks, one being just the cost of generating the
120 7 Production for Recovery

Fig. 7.18 Steam assisted gravity drainage (SAGD)

large amount of steam required. Variations on this method employ solvents instead
of steam to increase the liquidity of the oil, making the process more energy efficient.
Another drawback is high water use. There is a concern that it relies too much on
nearby water supplies and will deplete lakes and river streams. There have been
instances of contamination due to leaking wells. Treating the contaminated water is
costly and not always done [22].

7.10 Hydraulic Fracturing (Fracking) [23]

Natural gas is available as associated gas in crude oil reservoirs and as non-associated
gas in natural gas reservoirs and in the form of condensates. Recently, unconven-
tional sources, such as shale gas, tight gas and coal-bed methane, are commercially
exploited at large scales [24]. Unconventional resources are defined as those that can-
not be produced commercially without altering rock permeability or fluid viscosity.
7.10 Hydraulic Fracturing (Fracking) 121

Fig. 7.19 Hydraulic fracturing (fracking) [25]

Tight gas refers to natural gas reservoirs produced from reservoir rocks with
such low permeability, having less than 0.1 millidarcy (mD) matrix permeability and
less than 10% matrix porosity, that considerable hydraulic fracturing is required to
harvest the well at economic rates. These reservoirs do not have depth constraints.
They can be developed deep or shallow, at high or low pressure and temperature, in
stacked multilayered or single layer configurations, and in homogeneous or naturally
fractured formations.
It has been estimated that shale contains as much as 30% of today’s oil reserves.
Oil and gas are trapped in fine fissures and cannot be recovered conventionally.
Hydraulic fracturing (Fig. 7.19), a well stimulation technique also known as fracking,
is a process used in nine out of 10 natural gas wells in the United States. High quality
crude oils are also produced. Fracking involves injecting a specially designed fluid
under controlled pressure intermittently over a short period (three to five days) to
create fractures in a targeted deep-rock formation. The fractures permit oil, natural
gas and brine to flow to the wellbore.
A well drilled for hydro-fracking goes vertically down until it hits shale. It then
is drilled horizontally through the shale for up to 5000 ft. The next step is injection
of fluid, which has a wide variety of potential compositions. The “fracking fluid” is
typically a slurry of water (90%), proppant (9.5%) and chemical additives, such as
122 7 Production for Recovery

thickening agents. gels, foams, light diesel, compressed gasses, or any of the other
approximately 750 chemical additives registered for this purpose. The goal is to
increase permeability of the surrounding rock to allow any oil released to flow more
easily. The proppants are small grains of sand, treated like resin-coated sand, man-
made ceramic beads, aluminum oxide or other particulates used to hold the fractures
open when the hydraulic pressure is removed from the well to recover gas and oil.
The actual fracturing part, though, is caused by extremely high pressure and
velocity, sometimes as much as 15,000 psi and 265 L/min. The resulting cracks free
fluid hydrocarbons, including gases, light oils, and heavy oils, allowing them to flow
more easily into the well. Typically, the additives decrease surface tension, reduce
viscosity, and prevent emulsions.
The injected fluids are somewhat recovered with the oil and disposed by injection
into deep wells. This so-called “frack water” is highly contaminated with dissolved
minerals, toxic trace metals, and heavy oil. It could be recovered, but only at great
expense. The disposition of frack water is a question which causes great public
concern.
To check on the status of fracturing and to possibly catch any leakage before it gets
out of hand, seismic monitoring is used. The length and depth of the fractures can be
measured and compared with expectations. If problems are discovered, especially
those that may cause environmental problems, fracturing can be stopped or at least
reduced. Monitoring also can reveal close-by reservoirs. After fracturing has been
completed, the frack oil is handled the same way as conventional oil.
Hydraulic fracturing is highly controversial due to the potential for adverse envi-
ronmental impact. Responsible operators apply fracking well below water tables and
cement their wells using best practices. When such practices are applied, the like-
lihood of loss of containment is minimal. However, disreputable companies have
fractured with explosives instead hydraulic pressure and have done so at shallow
depths, where problems are more likely.
Fracking affects the quality of air due to the amount of fuel being burned to run
the pumps at such high pressure. Some reports also say that up to 90% of the fractur-
ing liquid remains underground and cannot be reclaimed; over time, this may affect
nearby water resources. In some areas, fracking increases seismic activity substan-
tially. Prior to injection into disposal wells, wastewater is stored at the surface in open
vats, from which degassing contaminates the air with methane and other greenhouse
gases. The U.S. congress exempted some aspects of fracking from the Safe Drinking
Water Act (SDWA). The EPA has strict regulations on what oil companies can do
at their fracturing sites, but nobody can know in advance exactly what may happen
underground, where most of the problems can occur.
The oil and gas that cannot be recovered by conventional means, such as primary
to tertiary recoveries, are classified as unconventional oil and gas (UCOG). UCOG
includes oil sand, bitumen, extra-heavy oils, gas hydrates, coalbed methane, gas in
tight sand, etc. The oil and gas recovered by hydraulic fracturing are known as shale
oil and shale gas. The shale oil from fracking can be confused with the oil obtained
from retorting oil shale. Shale oils from fracking are high quality oils because the
heavy metals and asphaltenes remain in the reservoir or formation. But shale oils from
7.10 Hydraulic Fracturing (Fracking) 123

oil shale retorting contain the heavy fractions and toxic inorganic materials, such as
arsenic and mercury. It would probably be better to refer the shale oil from fracking
as “fracking oil” to differentiate from the “shale oil” from oil shale retorting. Shale
gas from fracking is natural gas, mainly methane. The gas from oil shale retorting
contains methane, too, but it also contains significant C2 -to-C4 gases.
A primary consideration when extracting unconventional petroleum, such as from
SAGD and hydraulic fracturing, is the net-energy gain, or NEG. The NEG of a process
is the amount of energy available in the oil recovered minus the amount of energy
that had to be put into retrieve it. If this value is not high enough then it is not worth
recovering the petroleum.

7.11 Wellsite Pretreatment

Crude oil comes from the ground mixed with a variety of substances: gases, water,
salt, and dirt. These must be removed before the crude can be transported effectively
and refined without undue fouling and corrosion. Some cleanup occurs in oil fields
and midstream processes such as the preparation of syncrudes. Natural gas is mostly
methane, but it may contain hydrogen sulfide, CO2 , water, higher hydrocarbons,
mercury compounds, and noble gases (He and Ar).
Natural gas and crude oil need to be transported to a gas plant or a refinery, usually
a considerable distance away from the fields, for processing into useful products.
For large-scale transportation, pipelines and tankers are commonly used. For smaller
scales, especially for the distribution of petroleum products, railroad cars, barges and
tank trucks are used to a large extent. Prior to transportation, most gas and oil require
some form of pretreatment near the reservoir to meet transportation requirements
and safety specifications/regulations.
Considerable planning, including possible trading, is involved in determining how
and where to ship to the oil and gas. Transportation and trading, even storage, can be
considered as “midstream” operations between the field production (upstream) and
refinery or gas plant (downstream).
In certain cases, pretreatment of natural gas can be conveniently performed at the
wellhead. The produced oil, on the other hand, is usually collected from several wells
and sent to a central facility for separation of gas, oil, water and sand.
A field separator at well site is often no more than a large covered vessel that
provides enough residence time for gravity separation into four phases: gases, crude
oil, water, and solids. Generally, the crude oil floats on the water. The water is
withdrawn from the bottom and is disposed of at the well site. Gases are withdrawn
from the top and piped to a natural-gas processing plant or reinjected into the reservoir
to maintain well pressure. Crude oil is pumped either to a refinery through a pipeline
or to storage to await transportation by other means.
Low density natural gas is mostly moved by pipelines. It is also transported by
seagoing tankers at ambient or atmospheric pressure, with the cargo under refriger-
ation; special alloys to resist brittleness at temperatures as low as −160 °C became
124 7 Production for Recovery

available in the late 1960s, enabling operators to cryogenically liquefy natural gas
(LNG) for shipping.
More discussions in transportation can be found in Chap. 17.

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