Production Engineering #2

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PRODUCTION ENGINEERING#2
(Practical Manual)
DEPARTMENT OF PETROLEUM AND GAS
7st
Semester, 4TH Year
BATCH 2017
Supervised by:
Sir Najeeb Soomro
Prepared by:
Hashir Ali(PG-30)

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Contents
1. Hydraulic Fracturing and It’s Process............................................................................................................. 3
What is hydraulic fracturing?.............................................................................................................................. 3
Hydraulic Fracturing Process............................................................................................................................... 4
2. Importance and Application of Hydraulic Fracturing in Shale Formation .................................................... 5
Importance of Hydraulic Fracturing .................................................................................................................... 5
Hydraulic Fracturing in Shale Formation............................................................................................................. 5
3. Inflow Performance Relationship (IPR).......................................................................................................... 7
1. What is IPR and uses of IPR?........................................................................................................................... 7
2. List three main factors affecting IPR?............................................................................................................. 8
3. Explain inflow and outflow performance?...................................................................................................... 8
4. Artificial Lift Method and Its Application....................................................................................................... 9
Application of Artificial Lift.................................................................................................................................. 9
Hydraulic pumps ............................................................................................................................................. 10
Beam pumps ................................................................................................................................................... 11
5. Electric Submersible Pumps.......................................................................................................................... 13
6. Gas Lift Method............................................................................................................................................. 14

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1. Hydraulic Fracturing and It’s Process
What is hydraulicfracturing?
Hydraulic fracturing, informally referred to as “ fracking ” is an oil and gas well development process that
typically involves injecting water, sand, and chemicals under high pressure into a bedrock formation via the
well. This process is intended to create new fractures in the rock as well as increase the size, extent, and
connectivity of existing fractures. Hydraulic fracturing is a well-stimulation technique used commonly in low-
permeability rocks like tight sandstone, shale, and some coal beds to increase oil and/or gas flow to a well
from petroleum-bearing rock formations. A similar technique is used to create improved permeability in
underground geothermal reservoirs.
In hydraulic fracturing, the proppant-filled fracture at the end of pumping strongly influences the fluid
conductivity of natural oil and gas. Therefore, it is very important to create optimal propped fracture
geometry by designing pumping schedules to increase the recovery of shale hydrocarbon. Currently, pumping
schedule is designed offline and applied to a hydraulic fracturing process in an open-loop manner, which may
lead to poor process performance if there are large disturbances and plant-model mismatch. Furthermore, the
propped fracture geometry depends on interaction between simultaneously propagating multiple fractures

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(stress-shadow effects), and the interaction between propagating hydraulic fractures and pre-existing natural
fractures in naturally fractured unconventional reservoirs. Motivated by this, first, we focus on developing
high-fidelity process model of hydraulic fracturing processes to understand these interactions. Then, we
develop a model predictive control framework for the design of pumping schedules to achieve optimal
propped fracture geometry in unconventional reservoirs, which is directly related to the overall efficiency of
the operation.
HydraulicFracturingProcess
A hydraulic fracture is formed by pumping fracturing fluid into a wellbore at a rate sufficient to increase
pressure at the target depth (determined by the location of the well casing perforations), to exceed that of the
fracture gradient (pressure gradient) of the rock. The fracture gradient is defined as pressure increase per unit
of depth relative to density, and is usually measured in pounds per square inch, per square foot, or bars. The
rock cracks, and the fracture fluid permeates the rock extending the crack further, and further, and so on.
Fractures are localized as pressure drops off with the rate of frictional loss, which is relative to the distance
from the well. Operators typically try to maintain "fracture width", or slow its decline following treatment, by
introducing a prop pant into the injected fluid – a material such as grains of sand, ceramic, or other particulate,
thus preventing the fractures from closing when injection is stopped and pressure removed. Consideration of
prop pant strength and prevention of prop pant failure becomes more important at greater depths where
pressure and stresses on fractures are higher. The propped fracture is permeable enough to allow the flow of
gas, oil, salt water and hydraulic fracturing fluids to the well.
During the process, fracturing fluid leak off (loss of fracturing fluid from the fracture channel into the
surrounding permeable rock) occurs. If not controlled, it can exceed 70% of the injected volume. This may
result in formation matrix damage, adverse formation fluid interaction, and altered fracture geometry,
thereby decreasing efficiency .
The location of one or more fractures along the length of the borehole is strictly controlled by various
methods that create or seal holes in the side of the wellbore. Hydraulic fracturing is performed
in cased wellbores, and the zones to be fractured are accessed by perforating the casing at those locations.
Hydraulic-fracturing equipment used in oil and natural gas fields usually consists of a slurry blender, one or
more high-pressure, high-volume fracturing pumps (typically powerful triplex or quintuple pumps) and a
monitoring unit. Associated equipment includes fracturing tanks, one or more units for storage and handling
of prop pant, high-pressure treating iron a chemical additive unit (used to accurately monitor chemical
addition), low-pressure flexible hoses, and many gauges and meters for flow rate, fluid density, and treating
pressure. Chemical additives are typically 0.5% of the total fluid volume. Fracturing equipment operates over a
range of pressures and injection rates, and can reach up to 100 megapascals (15,000 psi) and 265 liters per
second (9.4 cu ft/s) (100 barrels per minute).

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2. Importance and Application of Hydraulic
Fracturing in Shale Formation
Importance of HydraulicFracturing
Hydraulic fracturing is used to increase the rate at which fluids, such as petroleum, water, or natural gas can
be recovered from subterranean natural reservoirs. Reservoirs are typically
porous sandstones, limestone or dolomite rocks, but also include "unconventional reservoirs" such
as shale rock or coal beds. Hydraulic fracturing enables the extraction of natural gas and oil from rock
formations deep below the earth's surface (generally 2,000–6,000 m (5,000–20,000 ft)), which is greatly below
typical groundwater reservoir levels. At such depth, there may be insufficient permeability or reservoir
pressure to allow natural gas and oil to flow from the rock into the wellbore at high economic return. Thus,
creating conductive fractures in the rock is instrumental in extraction from naturally impermeable shale
reservoirs. Permeability is measured in the microdarcy to nanodarcy range. Fractures are a conductive path
connecting a larger volume of reservoir to the well. So-called "super fracking," creates cracks deeper in the
rock formation to release more oil and gas, and increases efficiency. The yield for typical shale bores generally
falls off after the first year or two, but the peak producing life of a well can be extended to several decades.
While the main industrial use of hydraulic fracturing is in stimulating production from oil and gas
wells, hydraulic fracturing is also applied:
 To stimulate groundwater wells
 To precondition or induce rock cave-ins mining
 As a means of enhancing waste remediation, usually hydrocarbon waste or spills
 To dispose waste by injection deep into rock
 To measure stress in the Earth
 For electricity generation in enhanced geothermal systems
 To increase injection rates for geologic sequestration of CO2
 Since the late 1970s, hydraulic fracturing has been used, in some cases, to increase the yield of drinking
water from wells in a number of countries, including the United States, Australia, and South Africa.
HydraulicFracturingin Shale Formation
Shale formations present a great variability, and for this reason no single technique for hydraulic fracturing has
universally worked. Each shale play has unique properties that need to be addressed through fracture
treatment and fluid design. For example, numerous fracture technologies have been applied in the
Appalachian basin alone, including the use of CO2, N2 and CO2 foam, and slick water fracturing. The
composition of fracturing fluids must be altered to meet specific reservoir and operational conditions. Slick

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water hydraulic fracturing, which is used extensively in Canadian and U.S. shale basins, is suited for complex
reservoirs that are brittle and naturally fractured and are tolerant of large volumes of water.
Ductile reservoirs require more effective proppant placement to achieve the desired permeability. Other
fracture techniques, including CO2 polymer and N2 foams, are occasionally used in ductile rock (for instance,
in the Montney Shale in Canada). As discussed below in Sections 2.4 and 2.9.1, CO2 fluids eliminate the need
of water while providing extra energy from the gas expansion to shorten the flow back time.

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3. Inflow Performance Relationship (IPR)
A mathematical tool used in production engineering to assess well performance by plotting the well production
rate against the flowing bottomhole pressure (BHP). The data required to create the IPR are obtained by
measuring the production rates under various drawdown pressures. The reservoir fluid composition and
behavior of the fluid phases under flowing conditions determine the shape of the curve.
1. What is IPR and uses of IPR?
IPR stands for Inflow Performance Relationship. The relation between the flow rate (q) and the flowing
bottom-hole pressure (Pwf) states the inflow performance relationship. For a gas well to flow there must be a
pressure differential from the reservoir to the well bore and the fluid characteristics and changes with time.
There is a linear relationship between the reservoirs producing at the pressures above the bubble point
pressure, this is the pressure when Pwf is greater or equal to bubble point pressure.
The linear form of an IPR represents the Productivity Index (PI), which is the inverse of the slope of IPR. The
gas reservoir is deliberately evaluated using the well inflow performance relationship (IPR). Gas well IPR also

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depends on the flow conditions, that is, transient, steady state or pseudo state flows which are determined by
reservoir boundary conditions.
Uses of IPR:
It is special type of measurement property which is used to measure life and productivity of reservoir.
Inflow performance relationship is useful as a tool monitor well performance and predicts the simulation and
artificial lift requirements of a number of wells.
In order to check or correct the size of a well to an accurate value IPR of a well must be known.
2. List three main factors affecting IPR?
The three important factors affecting IPR are:
Pressure inside the reservoir.
Nature of reservoir fluids.
Types of rocks.
3. Explain inflow and outflow performance?
Inflow performance of a reservoir is defined as the functional relationship between the flowing bottom-hole
and the resulting flow rate. It is the rate at which fluid will flow towards the wellbore and depends on the
viscosity of the fluid, the permeability of the rock, and the driving force. For a gas well to flow there must be a
pressure difference from reservoir to the well-bore at the reservoir depth. If the well-bore pressure is equal to
the reservoir pressure there can be no inflow. If the well-bore pressure is zero , the inflow would be a
maximum possible i.e. the Absolute Open Flow (AOF).
For intermediate well-bore pressures, the inflow will vary. For each reservoir, there will be unique relationship
between the inflow rate and wellbore pressure. For a heterogeneous reservoir, the inflow performance might
differ from one well to another. The performance is commonly defined in term of a plot of surface production
rate (stb/d) versus flowing bottom hole pressure (pwf in psi). Several models are available for determining the
different types of Inflow performance Relation; they are Straight line flow, Vogel’s method, Future IPR flows,
The Fetkovich method and many more.
Outflow Performance involves fluid flow through flow through the production tubular, the wellhead and the
surface flow line. In general the fluid flow involves the pressure difference across each segment of the fluid
flow. Calculating the pressure drop at each segment is serious problem as it involves the simultaneous flow of
oil, gas and water(multiphase flow), which implies the pressure drop dependent on many variables in which
some of them are inter-related.
Due to this, it is very difficult to find an analytical solution. Instead, empirical formulas and mathematical
models have been developed and used for predicting the pressure drop in multiphase flow. In order to obtain
the realistic results, it is therefore important to define the input parameters carefully, through close co-
operation with production engineers and to check the results of the Vertical Flow Performance which is also
called as the Outflow Performance.

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4. Artificial Lift Method and Its Application
Artificial Lift is a process of changing reservoir pressure in oil wells in order to increase the flow of oil (or
water) to the surface. As production continues, the natural reservoir pressure declines, as such, there is no
force to push the oil out. What Artificial Lift does is provide this additional drive by increasing pressure.
Artificial Lift is used in mature fields, as well as in newer fields to make projects economics work. More than
75% of wells worldwide ( around 1million) use Artificial Lift. North America is the largest region for Artificial
Lift application, with more than 50% of the market. This is followed by Europe, Asia Pacific and Latin America.
Effective utilization of Artificial Lift requires a detailed analysis whereby almost each well feature makes a
difference. Deviation and lateral profiles, pressure and temperature, gas-to-liquid ratio, facilities footprint and
many more. Selecting the optimum lift method involves extensive planning, analysis and scenarios. Each
method has its own pros and cons and may not be the best method during the later time of the field, although
initially, it was the optimum solution. Poor selection may result in high operating costs or deferred production,
due to wells not being at its optimum production levels. Frequent pump failures, due to sand and solids,
tubing wear and many more, result in unnecessary well work-over’s.
When it comes to breaking down the market by type, it is difficult to have a very accurate segmentation, as
the numbers are conflicting, sometimes. However, as a guide (95% accuracy) the segmentation of Artificial Lift
industry looks like as below. In offshore applications, ESP and Gas Lift significantly dominate the market of
Artificial Lift, with smaller proportion of PCP and Jet Pumps
Artificial lift refers to the mechanical lifting of wellbore fluids to the surface. Mechanical lifting of wellbore
fluids is required when reservoir pressure is insufficient to drive reservoir fluids to the surface. Artificial lift
equipment also can be used to increase production from flowing wells by reducing the producing bottom hole
pressure.
A number of different types of artificial lift systems are currently in use. The four primary artificial lift systems
are
 Electric submersible pump (ESP)
 Gas lift
 Hydraulic pump (piston and jet pump)
 Beam pump
Application of Artificial Lift
Any liquid-producing reservoir will have a 'reservoir pressure': some level of energy or potential that will force
fluid (liquid, gas or both) to areas of lower energy or potential. The concept is similar to that of water

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pressure in a municipal water system. As soon as the pressure inside a production well is decreased below the
reservoir pressure, the reservoir will act to fill the well back up, just like opening a valve on a water system.
Depending on the depth of the reservoir and density of the fluid, the reservoir may or may not have enough
potential to push the fluid to the surface - a deeper well or a heavier mixture results in a higher pressure
requirement.
There are two major options to increase pressure:
I. A device inside the well that would provide the required pressure to lift the fluids. Normally the device
is a pump with different operating basics
II. Injecting pressurized gas produced from a well, to the production section of the reservoir, through a
down-hole valve
Hydraulic pumps
A hydraulic pump operates similarly to a gas liftsystem, with high pressurepower fluid used as the energy sourcein placeof high
pressuregas.There aretwo different types of hydraulic pumps:piston and jet. A piston type pump assembly consistsof a
hydraulically operated motor at one end and a plunger type pump at the other end.
High pressurehydraulic fluid ispumped down the tubing stringand enters a reciprocatinghydraulic motor.This motor activates the
piston type pump which lifts the produced fluids and hydraulic fluid up the casingannulustoward the surface.The hydraulic fluid
most commonly used is produced oil fromthe well itself.When the produced fluids and hydraulic fluid arepumped to the surfa ce,
the oil is separated and some of the oil is reused as the power fluid.
The hydraulic jetpump system uses a Ventura pressuredrop to commingle the power hydraulic fluid and the produced fluids.Th e
jet pump system does not requirethe hydraulicfluid to be as clean as thatfor the piston type system. The jet system a lso allowsfor
wider production rates than does the piston type pump system. Hydraulic pumps areused primarily in deep wells requiringlift
volumes greater than those capablefrombeam pump systems.

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Beam pumps
Beam pumping systems were one of the firsttype of artificial liftused in the oil field and arestill themost widely used means of
artificial lift.A beam pump system lifts fluid by reciprocatinga rod stringthatactivates a positivedisplacementpump. The positive
displacement pump is seated in the tubing stringand set below the operating fluid level in the well (Figure 4). A surfacepumping
unit provides the power to reciprocatethe rod string.
The surfacepumping unitis made up of two primary components: a prime mover (motor) and a walkingbeam connected to a
pivotal post.The walkingbeam operates likea seesawon the pivotal post,providinga reciprocatingmotion to the rod string. On
each upward stroke of the rod string,a volume of produced wellbore fluids is lifted upward in the tubing stringtoward the sur face.
The capacity of the beam pumping system is set by the sizeof the down hole pump, the stroke length of the rod string,and the
speed atwhich the rod stringis reciprocated.When pump capacity exceeds wellbore fluid entry, the surfacepumping unit can be set
up to run intermittently by shutting down the pumping unit for a set period of time.

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The limitations of the beam pumping system are approximately 150 bbl of fluid per day at 12,000 ft of depth. Larger fluid volumes
can be produced with beam pumping systems at shallower depths.Beam pumping systems have been used in wells as deep
as 15,000 ft.

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5. Electric Submersible Pumps
An electric submersible pump (ESP) consists of a centrifugal pump coupled to an electric motor. The pump and
motor combination is run in the well on the bottom of the tubing string and is set below the operating fluid
level in the well.
The electric motor powers a centrifugal pump that forces fluid into the pump up through the tubing and out at
the surface. The electric motor is powered by an electric cable strapped to the side of the tubing string. Lift
capacity for each pump is adjusted by changing the number of stages in the centrifugal pump and/or by
changing the horsepower of the electric motor.
Electric submersible pumps are beneficial in wells that must lift high volumes of fluids from less than 10,000
ft deep. ESPs are often used in the late stages of water flooding where high water cuts require lifting large
production volumes from each well.

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6. Gas Lift Method
Gas lift is the process of lifting fluids from the wellbore using high pressure gas as the energy source. Down
hole gas lift equipment consists of a series of gas lift valves spaced at predetermined depths in the tubing
string. The tubing string is set in a packer above the casing perforations . Gas is normally injected down the
tubing/casing annulus and enters the tubing via the gas lift valves. A surface gas compressor is used to provide
the high gas pressure required to open the gas lift valves.
Gas lift systems move the reservoir fluids to the surface by reducing the hydrostatic pressure of the fluid column
in the tubing below reservoir pressure. The injected gas expands as it moves upward in the tubing, providing
additional lift. Gas lift systems can be installed to operate continuously or intermittently. Gas lift is commonly
used in offshore applications and in areas where an abundant supply of gas exists. Often the gas produced
from the well is separated from the produced fluids and reinjected into the same well.

Production Engineering #2

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