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Ecole Nationale Suprieure de Gologie
Producing the reservoir Flow Dynamics & Production
Monitoring
& Well Production Optimization
Prepared by students of International Master SRE
Talgatbek BAZARBEKOV Amir KUVANYSHEV
Nurlan SHAYAKHMETOV Sergey USMANOV
Nancy 2014
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Contents
1. Flow dynamics and production monitoring
1.1. Production vs well and surface equipment
1.2. Producing interval evaluation
1.3. Well testing and monitoring
1.4. Permanent monitoring
1.5. Subsea well / Flow optimization
1.6. Reference
2. Well production optimization
2.1. Assuring flow through tubular
2.2. Production zone selection
2.3. Fracturing
2.4. Well productivity optimization
2.5. Work-over
2.6. Reference
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1. Flow Dynamics and Production Monitoring From the flow
dynamics, we know several types of two phase flow regimes which
varies
by the types of wells and rock, flow properties.
For vertical well:
Bubble flow a lot of discrete gas bubbles widespread in a
continuous liquid phase. Bubbles can be different in size and form,
but most of them are almost spherical and size is much smaller than
well diameter.
Slug flow with increasing of widespread gas volume in the
liquid, merging possibility of several gas bubbles are increases
and we will have gas slugs. Which has size close to well diameter
and characteristic shape resembling a bullet.
Annular flow At one time interfacial share of high velocity gas
located on the liquid film will dominant over the gravity and
liquid will move from center to sides. Gas phase can haven't any
liquid (a) or liquid can appear at gas phase as small droplets (b).
This flow regime a particularly stable.
a) b)
Mist flow At very high gas flow velocities the annular film
thinned by the shear of the gas core on the interface until it
becomes unstable and is destroyed, such that all liquid droplets
will located in the continuous gas phase. This flow regime is
opposite to bubble flow.
The motion in the horizontal tubes is almost the same as in the
vertical tubes, however in
the horizontal wells we have gravity effect and distribution of
the bubbles in two-phase flow pattern depends the gravity. Two
phase flow patterns for horizontal wells:
Bubble flow gas bubbles are dispersed in the liquid with the
high concentration at the upper half of the well due to liquid gas
density ratio. When the shear forces are dominant, bubbles tend to
disperse uniformly in the tube.
Stratified flow at the liquid and gas flow velocities, this two
phases are completely separated along the height. That means due to
difference between gas and liquid density, gas will flow up to the
top of the well and liquid will flow down to the bottom of the
well.
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Stratified-wavy flow by the velocity increasing appears waves
that forms at the separation line and travel to the direction of
the flow. The heights (amplitudes) of these waves are changing and
depends on the relative velocity of the two phases. But they are
can't reach top of the well in this flow regime.
Slug flow by the increasing of the gas velocity, the interfacial
waves become higher and higher so as they are rich and wash the top
of the well. Some of this waves will have bubbles and by the
increasing of the velocity bubbles are start to unit into one slug,
so one will have slug flow with the gas slugs at the top and with
the liquid at the bottom of the horizontal well.
Mist flow as a vertical wells at the high velocities of the gas,
all the liquid may be stripped from the wall and entrained as a
small droplets in the continuous gas phase.
Many scientists try to analyze the changing of types of the
flows and find dependence of
these changing by the fluid or rock properties. Fair (1960),
Hewitt and Roberts (1969) famous and widely used two phase flow
pattern maps illustrated in Figure 1 and Figure 2 respectively. To
use flow pattern map which was proposed by Fair (1960) one should
calculate X axis by the formula shown below and the mass velocity
(here in lb/h ft).
( x1 x)
0,9
( LG )0,5
( G L)0,5
there are:
G gas viscosity, G gas density, L liquid viscosity, L liquid
density, x vapor quality
Using this two values one can locate the point between bubble
flow, slug flow, annular flow, mist flow and find out the type of
two phase flow pattern.
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Figure 1. Two phase flow pattern map of Fair (1960) for vertical
tubes [1]
To use two phase flow pattern of Hewitt and Roberts (1969), one
should calculate mass velocities of the liquid and gas phase using
the vapor quality. Then the values of the x and y coordinates are
determined and the intersection of these two values on the map
identifies the flow pattern predicted to exist at this flow
conditions.
Figure 2. Two phase flow pattern map of Hewitt and Roberts
(1969) for vertical tubes [1]
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1.1. Production vs Well & Surface Equipment When the well is
opened for producing the pressure distribution in the reservoir is
changing,
which can be seen in decreasing of bottomhole pressure (Fig.
1):
Figure 1. Scheme of the pressures in the reservoir-well system,
there: Ps pressure at the
separator, Pwh pressure at well head, Pwf bottomhole pressure,
Pr average reservoir pressure [9]
There are: Safety valve - is a valve mechanism which
automatically releases a substance from a boiler,
pressure vessel, or other system, when the pressure or
temperature exceeds preset limits. Bottomhole restriction a
restriction in a profile near the bottom of the well that allows
some gas
expansion and holds a backpressure on the formation. Rarely
used, but considered for hydrate control.
The term separator in oilfield terminology designates a pressure
vessel used for separating well fluids produced from oil and gas
wells into gaseous and liquid components. A separator for petroleum
production is a large vessel designed to separate production fluids
into their constituent components of oil, gas and water.
D P 1 = P r - P wfs - Loss in Porous Medium D P 2 = P wfs - P wf
- Loss across Completion D P 3 = P wf - P wh = Loss in Tubing D P 4
= P wh - P s = Loss in Flowline D P T = P r P s = Total pressure
loss Due to this pressure drops we will have outflow and inflow. As
mentioned above we can predict
that flow has straight dependence on the pressure i.e. of
pressure difference between surface pressure and reservoir
pressure. According to the Darcys law, which defines the fluid
movement in porous media, the velocity of flow is related to the
pressure gradient, so it is controlled by the surface equipment. We
can't influence to reservoir pressure but we can use choke to
change the surface pressure.
In oil and gas production a choke manifold is used to control
the pressure from the well head. It consists of a set of high
pressure valves and at least two chokes. These chokes can be fixed
or adjustable or a mix of both. The redundancy is needed so that if
one choke has to be taken out of service, the flow can be directed
through another one. By lowering pressure the retrieved gases can
be flared off on site.
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Figure 2. Inflow performance relationship. Production rates at
various drawdown
pressures are used to construct the IPR curve, which reflects
the ability of the reservoir to deliver fluid to the wellbore.
Combining this with a curve reflecting the tubing performance
identifies the operating point. Determination of rate vs.
pressure is often referred to as the reservoir inflow performance,
which is
a measure of the ability of the reservoir to produce gas to the
wellbore. The inflow performance curve is a plot of bottomhole
pressure vs. production rate for a particular well determined from
the gas well deliverability equations depicts a typical gas well
inflow performance curve. This curve allows one to estimate the
production rate for different flowing bottomhole pressures
readily.
The pressure drop in any component, and thus in either the
inflow or outflow section of the system, varies as a function of
flow rate. As a result, a series of flow rates is used to calculate
node pressures for each section of the system. Then, plots of node
pressure vs. production rate for the inflow section and the outflow
section are made. The curve representing the inflow section is
called the inflow curve, while the curve representing the outflow
section is the outflow curve. The intersection of the two curves
provides the point of continuity required by the systems analysis
approach and indicates the anticipated production rate and pressure
for the system being analyzed.
The relationship between well inflow rate and pressure drawdown
can be expressed in the form of a Productivity Index, denoted PI or
J, where:
Q= J (Pws Pwf ) or J = Q
Pws Pwf
Q0=kh(Pav Pwf )
141.2 0 B0[ ln (r erw 3 /4)]
There: P - pressure (psi), Pav - average pressure, k -
permeability (md) h - height (ft) re - drainage
radius (ft) rw - wellbore radius (ft) O - fluid viscosity (cP)
Bo - formation volume factor (bbls/stb) When the inflow is modeled
the pressure drop, production fluid properties (viscosity) and
the
reservoirs parameters (permeability) is taking into account, to
calculate the out-flow the influence of the well and surface
equipment is of a great importance. Such calculation can be used to
define optimal flow conditions and necessary equipment (tubing,
surface facilities). By combining both, in-flow and out-flow
models, one obtains such called full-field model, which can be used
in planning of production processing and transport.
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1.2. Producing Interval Evaluation During the production we can
have some mismatch because of heterogeneity of reservoir. For
example, one can have well with perforation which located above
water-oil contact, but on the surface we can deplete much more
water than it should be. That's happened when we have some
heterogeneities like cracks etc. To find this overflow zones we use
logging equipment like:
Flow meter tool using which we can calculate locally
quantification of volume fluid movement, illustrated in Fig. 1.
Water holdup electrical sensor which can indicate appearance of
water by the resistivity, as reservoir brine has resistivity lower
than oil or gas, illustrated in Fig 2.
Figure 1. Flow meter [15] Figure 2. Water holdup [17] Gas holdup
sensor which can indicate appearance of gas presented in Fig. 3,
for example Ghost
gas holdup which uses Schlumberger indicate gas appearance by
the LED light reflection and designed so that the amount of
reflected light is much greater when the sensor is in gas than when
it is in liquid. Work principle of Ghost holdup illustrated in Fig.
4.
Figure 3. Gas hold up [16]
Figure 4. Work principle of Ghost hold up [14]
Now firms like Schlumberger have many possibilities and new
technologies so that one can measure multi-phase flow rate, using
equipment presented above. One of many possible PS Platform
configurations recommended for multiphase flow analysis presented
in Fig. 5.
Figure 5. PS Platform configurations recommended for multiphase
flow analysis [14] 8
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All information which one takes from the sensors are processed
at the special computer utilities and the specialist can present
production profile, find overflow zones and re-perforate well so
that this zones will be closed (Fig. 6).
Figure 6. Multiphase flow logging measurement. a) before b)
after re-perforation [14]
Horizontal and highly deviated wells are drilled to target
specific pay zones in the oil and
gas reservoirs. They may increase the recovery percentage from
onshore and offshore fields. The ability to drill such wells
provides cost effective means for extracting resources from
reservoirs, that may not otherwise have been economically viable.
Due to the increase in highly deviated and horizontal wells, there
is a need for intervention technologies that allow for down-hole
operations in such wells. For this operations will be developed the
wireline tractor illustrated in the Fig.7.
Applications of the wireline tractor:
Production logging Logging while tractoring Pipe recovery
Perforation Plug setting Tractor jar Drift Can be used in tandem to
negotiate restrictions in wellbore Anchor and conveyance for
rotational services
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Key features of the wireline tractor:
Cost effective wireline conveyance in horizontal wells Flexible
arms follow ID variations in well Compatible with 3rd party tools
DC voltage operated Hydraulic drive mechanism Helicopter
transportable Short toolstring length compared to similar products
on the market [19].
Figure 7. Wireline tractor [18]
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1.3. Well Testing & Monitoring Well Testing is the technique
allows measurement of reservoir data production
capabilities and reservoir properties permeability, pressure,
temperature, fluid properties, flow rate, productivity etc under
dynamic conditions for both, shut-in and flowing well.
Usually, well testing suggests influencing the pressure
distribution in the reservoir by some operation with well, i.e. one
changes the chock size in the chock manifold which leads to
changing a flow rate and, consequently, to some pressure
perturbations in reservoir tested. Another possibility is to shut
in the well totally (producer or injector) after some period and
pick the pressure response (pressure fall-off curve for injection
well and pressure build-up curve for production well). Also surface
and in-situ sampling is used.
Well Testing can be performed at different stages of well
life:
Drilling Open hole DST (drillstem test) Cased hole DST
Exploration well DST Development well DST and/or Production
Test
Well testing methods
Openhole and cased hole, no completion. Conventional
deliverability tests, involving extensive surface and downhole
equipment, are designed to simulate the production characteristics
of new wells. Fig. 1 shows a typical surface onshore layout for an
exploration well test and a sketch of the drillstem test (DST)
string of downhole testing tools (the purpose of well testing
equipment is given). Also, Multiphase tester (Fig. 2) can be used
as shown in the Permanent Monitoring Chapter, replacing the bigger
part of the equipment shown in Fig.1.
Wireline testing. Wireline tests are performed mostly in open
hole using a cable-operated formation tester and sampling tool
anchored at depth while reservoir communication is established
through one or more pressure and sampling probes. Fig. 3 shows
typical configurations for testing and sampling with the Modular
Formation Dynamics Tester tool.
Production or injection test with completion string in place.
Production and injection well tests, performed using production
logging tools, are conducted to obtain pressure and optional flow
measurements. Fig. 4 shows a sketch of a basic version of the
Schlumbergers PS Platform new-generation production services
platform, equipped with a gas holdup sensor [20].
DST Production test Retrievable packer Tubing or Drill pipe
Flowhead
Permanent packer Tubing Christmas Tree (X-tree)
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Figure 1. Typical surface onshore layout for an exploration well
test and a sketch of the
drillstem test [21, 22] 1-the Flowhead controls the well
pressure 2-the choke manifold controls the flow and the pressure.
3-the heater (or steam exchanger) is used to raise the effluent
temperature to fight hydrates (gas well), and to break emulsion or
to reduce foam and viscosity (oil well), and improve burning. 4-the
separator is use to separate, measure and sample the three phases
of the effluent (to obtain accurate & representative data,
separator must be run under steady conditions) 5-the gauge tank are
used to store oil, to calibrate the liquid meters, to measure the
shrinkage and low liquid flowrate. 6-the oil is disposed of through
the burner located at the extremity of the booms to reduce heat
radiations towards the rig. 7-the gas is burned separately through
a gas flare located on the burner booms
Figure 2. Ultra-deep water multi-phase flow measurement [23]
1 2
3 4 5
6
7
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Figure 3. Typical MDT configurations for formation testing and
sampling [20]
Figure 4. Sketch of a basic PS Platform tool for production
logging and testing in production and injection wells [20]
Processing of Well testing During a well test, a particular flow
rate schedule is applied to the tested reservoir, by
using flow control equipment (conventional testing) or a
software-selected drawdown routine (wire-line formation testing).
The pressure response and the flow rates obtained are recorded
versus time. From the measured pressure, and from predictions of
how reservoir properties influence this response, the estimation of
these properties (permeability, skin factor) becomes possible. A
particular aspect of well testing is formation fluid sampling,
which is one of the main reasons wells are tested [20].
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Measurements from well testing
Measurements necessary to satisfy these aims are: o Rates of
each fluid produced o The bottom hole pressure and temperature
behavior o PVT study of representative reservoir samples
The primary purpose of a DST or production test
Determine the nature of fluids produced. o PVT tests to be
performed on the bottom-hole or recombined samples.
Define the well productivity. One of special parameters measured
during well testing is well performance, or productivity the
measure of a well completions ability to produce, expressed in
volume of gross liquid produced per day per unit of differential
pressure between the static reservoir pressure and the wells
flowing bottomhole pressure. The productivity carries variety of
useful information, i.e. the hydroconductivity, effective thickness
etc o Productivity index and IPR plot for oil wells. o
Deliverability curve and absolute open flow for gas wells.
Evaluate the characteristics of the producing formation. o
Static pressure. o Formation flow capacity (Kh), reservoir
heterogenities, limits.
Evaluate any formation damage o Determine if acidizing or other
treatment is required. o Control the results of the stimulation or
treatment [21]
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1.4. Permanent monitoring Nowadays new technologies allow
permanent monitoring of reservoir parameters, such as
pressure, temperature, fluid produced etc. All these data allow
reservoir engineer to adapt the reservoir model to the instant real
conditions and effectively plan measures to meet the different
tasks (pressure maintenance, recovery factor, water cut control
etc)
To make a monitoring of reservoir pressure and temperature its
important to place the sensors in vicinity of the perforation
interval to avoid effects occurred in the tubing string. Optic
technologies applied (Fig.1).
Figure 1. Bottomhole Pressure-temperature monitoring [24]
Moreover it is possible to monitor the production fluid in-situ.
To meet this Weatherford
provides the complex solution Downhole optical multiphase
flowmeter (Fig.2).
Figure 2. Downhole optical multiphase flowmeter [25]
The optical multiphase flowmeter technology is based on a
flow-velocity measurement and a speed-of-sound measurement where
the speed of sound is proportional to volume fraction of oil,
water, and gas in the flowing mixture. The flowmeter is deployed as
part of the production tubing and is typically integrated with one
or two Weatherford optical pressure and temperature gauges ported
to tubing and/or annulus. The tool is connected to the perforated
interval and
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isolated from the other space by packer. Such type of
installation allows continuous data acquisition [26]. The
advantages of this kind of tools meet the majority of permanent
monitorings advantages:
Continuous data acquisition Identification and localization of
production anomalies in real-time Local control in multi-lateral
wells (multi-zone intelligent completions) Direct determination of
well productivity index Reduction of surface well tests and surface
facilities Subsea installations with fiber in the umbilical.
The disadvantage of the technology is price and laborious
maintenance. Downhole flow monitoring at the most basic level can
be considered as simply an alternative flow measurement required
for well production optimization. In subsea environments a downhole
meter can be the most cost-effective option for adequate data
gathering [27].
Using the permanent monitoring, engineers perform the continuous
cycle: Monitoring-Data
manipulation-Decision-Execution-Monitoring-Data manipulation
Also surface flow testing is used to monitor the production
fluid. It can be convenient method when all the production is
separated in the surface, so one can define a phase composition
(oil, gas, water) produced. The big disadvantage of such method is
an involving of extensive surface and downhole equipment as it is
shown in previous chapter.
Also, therere some problems, related with separation of the
production [28]:
It can take several hours to obtain reliable flowrate
measurement from a test separator. Some oil remains in water, some
gas in oil etc, leading to inaccuracy on flowrate
measurements. Slugs, foam, emulsion. Viscous oil: not easy to
separate the oil from water
However, nowadays Schlumberger and some others provide an
opportunity to avoid such involving by using PhaseTester Vx (Fig.
3).
Figure 3. Schematic View of a PhaseTester Vx [29] 16
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This multiphase well testing unit allows carrying out In-line
Flow Measurements:
Venturi meter and Cross correlation of different sensors data
(Gamma-ray, electricalcapacity and conductivity etc) to determine
the velocity of the multiphase flow and amass flowrate
Gamma-ray (densitometer defines a high contrast between liquid
and gas), Microwave(microwave sensor between water and
hydrocarbons) and Dielectric constant(permittivity will be
different for each of the three components in an
oil/gas/watermixture) to define the phase composition of producing
fluid.
Both, permanent and temporary measurements can be processed,
which allows to update the reservoir model continually. In total
such technology provides more accurate surface measurements in any
flow conditions. The advantages are:
Independent of flow regimes More accurate than a separator No
flowing calibration Continuous monitoring Very low pressure loss
Based on physical principles With no moving / intrusive parts
Safety Environmentally friendly No flaring (Zero Emission Testing)
No pumping and leak risks
Also, other solutions for multiphase in-flow measurement which
use sonar technologies exist (Fig. 4).
Figure 4. ACTIVESONAR (a) and PASSIVESONAR (b) flowmeters
[30]
b) a)
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Such type of equipment for permanent flow monitoring provides
wide spectrum of data and easy to transport and install (Fig.
5).
Figure 5. Multiphase flow measuring [31]
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1.5. Sub-sea well. Flow optimization Subsea oil field
developments can be splited into categories to distinguish between
the
different facilities and approaches that are needed [32]:
Shallow water: 600 feet, floating drilling vessels and floating
oil platforms are used, and remotely operated underwater vehicles
are required)
Most of the new oil fields are located in deep water and are
generally referred to deepwater systems. Development of these
fields sets strict requirements for verification of the various
systems functions because of the high costs and time involved in
changing a pre-existing system due to the specialized vessels with
advanced onboard equipment.
Subsea production systems can include numerous wells on a
template or clustered around a manifold and transferring to a fixed
or floating facility, or directly to an onshore installation.
Subsea production systems can be used to develop reservoirs, or
parts of reservoirs, which require drilling of the wells from more
than one location. In such complicated conditions the incidents
consequences can be extremely dangerous, that is why the
requirements for subsurface equipment are very strict. The
development of subsea oil and gas fields requires specialized
equipment, which must be reliable enough not only to safeguard the
environment, but also to make the exploitation of the subsea
hydrocarbons economically feasible. The deployment of such
equipment requires specialized and expensive vessels. Any
requirement to repair or intervene with installed subsea equipment
is very expensive [33].
The general scheme of sub-sea production is shown in Fig. 1. The
wells are connected to subsea production manifold, the production
is gathered by manifold into pipeline and can be processed subsea
or pumped via riser, which insures the connection between pipeline
and floating production platform. The umbilical between platform to
manifold allows control and well monitoring.
Figure 1. Offshore capabilities [34]
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Nowadays Subsea Processing is available [35]: Subsea processing
solutions: Why Subsea Processing: 3 phase separation Gas &
Liquid Separation Sand Removal Water removal and reinjection Gas
removal and reinjection Single and Multiphase Boosting Gas
compression Raw Seawater Injection
Increased recovery Accelerate production Reduced Capital
Expenditure Makes it possible to: -connect satellite fields to
existing infrastructure -exploit fields that are normally
inaccessible -exploit costly infrastructure fully throughout the
systems operational period -depressurize system as a hydrate
strategy Influence on the environment will decrease Reduces water
disposal to sea Enhances flow management
Subsea well intervention (Fig. 2) offers many challenges and
requires much advance
planning. The cost of subsea intervention has in the past
inhibited the intervention but in the current climate is much more
viable. These interventions are commonly executed from light/medium
intervention vessels or mobile offshore drilling units for the
heavier interventions such as snubbing and workover drilling
rigs.
The special arrangement (intervention riser system) and multiple
control is applied to obtain an ultimate connecting. Such system
allows for the deployment and free movement of fluids, coiled
tubing, wireline or slickline within the riser system.
Figure 2. Sub-Sea Production & Well intervention [36]
Riser system
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1.6. Reference 1. Thome, John R. "Two Phase Flow Patterns."
Engineering Data Book. Lausanne:
Wolverine Tube, 2004. N. pag. Print. 2. Bratland, Ove, Dr. "The
Flow Assurance Site." Chapter 1, Pipe Flow 1 Single-phase
Flow. Ove Bratland, 2010. Web. 12 Dec. 2014. 3. Baker, O., 1954,
Simultaneous Flow of Oil and Gas, Oil and Gas Journal, Vol. 53,
pp.
185. 4. Bonjour, J., and Lallemand, M., 1998, Flow Patterns
during Boiling in a Narrow Space
between Two Vertical Surfaces, International Journal of
Multiphase Flow, Vol. 24, pp. 947-960
5. Fukano, T., Kariyasaki, A., and Kagawa, M., 1989, Flow
Patterns and Pressure Drop in Isothermal Gas-Liquid Flow in a
Horizontal Capillary Tube, ANS Proceedings, 1989 National Heat
Transfer Conference, ISBN 0-89448-149-5, ANS, Vol. 4, pp. 153-
161.
6. Hewitt, G.F., 2000, Fluid Mechanics Aspects of Two-Phase
Flow, Chapter 9, Handbook of Boiling and Condensation, Eds.
Kandlikar, S.G., Shoji, M., Dhir, V.K., Taylor and Francis, NY.
7. Coleman, J.W., and Garimella, S., 2000, Two-phase Flow Regime
Transitions in Microchannel Tubes: The Effect of Hydraulic
Diameter, HTD-Vol. 366-4, Proceedings of the ASME Heat Transfer
Division-2000, Vol. 4, ASME IMECE 2000, pp. 71-83.
8. Barnea, D., Luninsky, Y., and Taitel, Y., 1983, Flow Pattern
in Horizontal and Vertical Two-Phase Flow in Small Diameter Pipes,
Canadian Journal of Chemical Engineering, Vol. 61, pp. 617-620.
9. Gilbert, W.E. 1954. Flowing and Gas-Lift Well Performance.
Drill. & Prod. Prac., 126-57. Dallas, Texas: API.
10. Mach, J., Proano, E., and Brown, K.E. 1979. A Nodal Approach
for Applying Systems Analysis to the Flowing and Artificial Lift
Oil or Gas Well. Paper SPE 8025 available from SPE, Richardson,
Texas.
11. Brown, K.E. 1984. The Technology of Artificial Lift Methods,
4. Tulsa, Oklahoma: PennWell Publishing Co.
12. Greene, W.R. 1983. Analyzing the Performance of Gas Wells. J
Pet Technol 35 (7): 1378-1384. SPE-10743-PA.
http://dx.doi.org/10.2118/10743-PA.
13. Brown, K.E. and Lea, J.F. 1985. Nodal Systems Analysis of
Oil and Gas Wells. J Pet Technol 37 (10): 1751-1763. SPE-14714-PA.
http://dx.doi.org/10.2118/14714-PA.
14. Schlumberger. GHOST Gas Holdup Optical Sensor Tool. N.p.:
Schlumberger, 2001. PS Platform. Schlumberger, June 2001. Web.
15. "Production Logging Flowmeter - Downhole Technologies GE
Energy." GE Energy. N.p., n.d. Web. 12 Dec. 2014.
16. "Gas Hold-up Tool (GHT)." GE Energy. N.p., n.d. Web. 12 Dec.
2014. 17. "Enhanced Capacitance Water Hold-up (CWH)." GE Energy.
N.p., n.d. Web. 12 Dec.
2014. 18. Aker Solutions, Statoil Pen Agreement for Wireline
Tractor Services (Norway)."
Offshore Energy Today. N.p., n.d. Web. 12 Dec. 2014. 19. Aker
Solutions. Wireline Tractor and Tractor Applications. N.p.: Aker
Solutions, 2013. 9
Aug. 2013. Web. 12 Dec. 2014. 20. Fundamentals of Formation
Testing. Sugar Land, TX: Schlumberger Marketing
Communications, 2006. Web 21. Surface well testing overview,
Schlumbergers Course Material Presentation 22.
www.mehranservices.com/index.php/services-products/81-well-testing
23. www.fujielectric.fr
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24. http://www.corelab.com/promore/intelligent-wells 25. O.
Haldun Unalmis. Multiphase Flowmetering in Wells Wanted: Reliable
& Accurate
Multiphase Flow Measurement in Intelligent Completions,
Weatherford 26.
www.weatherford.com/Products/Production/ReservoirMonitoring/DownholeOptical-
MultiphaseFlowmeter 27. S. Kimminau The impact of permanent
downhole multiphase flow metering.
Schlumberger 17th World Petroleum Congress, 2002 28.
01-Introduction to Vx technology. Schlumbergers Course Material
Presentation 29. SAGD Real-Time Well Production Measurements Using
a Nucleonic Multiphase
FlowMeter: Successful Field Trial at Suncor Firebag.
Schlumbergers technical paper, 2011
30. www.exprometers.com/Permanent_Clamp_on_Metering 31.
www.exprometers.com/Multiphase_Flow_Meter 32.
www.petromin.safan.com 33. API Recommended Practice 17A 34. Ove
Jansen "Will subsea production make topside obsolete" Floating
Production 2010,
FMS Technologiess presentation 35.
www.tekna.no/ikbViewer/Content/798901/12 36. Trond Inge Ramsnes
Subsea well intervention; Learning from the past planning for
the
future. Statoils presentation, 2010
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2. Well production optimization Every company operating in oil
and gas industry wants to get its revenue today, so its
ultimate goal is to have as high production rate as possible, of
course taking into account the final recovery factor. And this
problem can be divided into two subproblems: long term reservoir
management and short term production optimization.[1] So well
production optimization is the problem of daily well treatment in
order to increase or maintain good production rate.
During production we face various problems which one should
solve. Here we will discuss the following potential problems:
1) Water problem; 2) scale formation; 3) low permeability. As we
begin to produce oil, water table level goes up and in the vicinity
of the well water
coning problem takes place, leading to water production, which
is unwanted. The same problem with gas interface, as we decrease
the pressure in the reservoir, gas starts to expand and goes down
to perforated zone, which is also unwanted. Because in oil and gas
reservoir, firstly we have to produce oil, in order to avoid sharp
pressure drop.
But sooner or later water reaches the production well and we
start to produce more water than oil, we can observe it by WOR. As
we see in the Figure 1, nowadays we produce a lot of water from
hydrocarbon reservoirs, and this leads to our second problem scale
formation.
Scale formation is one of the few problems that can smother a
productive well within 24 hours. So it is very important to remove,
predict and prevent such financial damage. Scale is an assemblage
of deposits that cake perforations, casings, production tubing,
valves, pumps and downhole completion equipment clogging the
wellbore and preventing fluid flow. The scale forms either by
direct precipitation from underground water, or as a result of
produced water becoming oversaturated with scale components when
two incompatible waters meet downhole.[2]
Another problem is the reservoir with low permeability or low
fluid mobility. According to Darcys law:
=
low permeability causes limited production and sharp pressure
drop near the wellbore and leads to flow restriction.
Well production optimization is the way one removes each problem
by proper treatments. For example, to increase permeability, we do
fracturing of the reservoir. There are also methods to treat with
scale formation and water table shift problems. Principles of these
methods are explained widely in the next sections.
Figure 1 - Water-Oil Ratio by regions [5]
23
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2.3. Assuring flow through tubular In this section we will talk
about precipitation and deposition of solids in the tubular and
methods of fighting with it. Scales are precipitated from water,
but there are also precipitations from hydrocarbons:
waxes, asphaltenes and hydrates. They usually cover scale
thereby protecting scale from chemical treatments.
Formation of scales. The main idea in solving this problem is to
identify the causes and locations of scale. The driving force for
scale formation may be a temperature or pressure change,
outgassing, a pH shift or contact with incompatible water. But its
not always the case. The main cause of the deposition is nucleation
processes:
1) Homogeneous nucleation the atom clusters form small seed
crystals triggered by local fluctuations in the equilibrium ion
concentration in supersaturated solutions. The seed crystals
subsequently grow by ion adsorbing onto imperfections on the
crystal surfaces extending the crystal size;
2) Heterogeneous nucleation crystal growth tends to initiate on
a pre-existing fluid boundary surface. It includes surface defects
such as surface roughness or perforations in production liners, or
even joints and seems in tubing and pipelines.
Another cause to catalyse scale formation is a high degree
turbulence zones. This explains why scale deposits rapidly build on
downhole completion equipment. On the picture above we can observe
where does scale forms in the tubing. [2]
Fighting with scale. After identifying, we have to remove it
without damaging the wellbore, tubing or formation environment and
prevent from reprecipitation. Fighting with scale costs a lot to
industry and needs effective and fast methods. There are two
approaches of scale-removal methods depending on the location of
scale and its physical properties:
1. Chemical; a. hydrochloric acid (HCl); b. EDTA
(ethylenediamenetetraacetic acid); c. U105;
2. Mechanical; a. mechanical cleaning; b. chemical cleaning; c.
Jet Blaster tools.
Carbonate minerals are highly soluble in hydrochloric acid. But
hard sulphates are not so easy, because the scale has a low acid
solubility. Thats why hydrochloric acid is usually the first
Figure 2 - Scale in tubing [2]
24
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choice to treat with CaCO3 scale. But the rapid acid reaction
hides a problem: spent acid solutions of scale by-products are
excellent initiators for reformation of scale deposits.
The answer to this problem was ethylenediamenetetraacetic acid
(EDTA). It dissolves and chelates calcium carbonate, breaking this
reprecipitation cycle. EDTA treatments are more expensive and
slower than hydrochloric acid, they work well on deposits that
require a chemical approach. It is also effective in noncarbonate
scale removal, e.g. calcium sulphate, mixtures of calcium-barium
sulphate.
After, Schlumberger developed an improved EDTA-based scale
dissolver, called U105. This dissolver was designed specifically
for calcium carbonate, but also effective against iron carbonate
and iron oxide scales. Other chelating agents have been optimized
especially for barium and strontium sulphate scale.
There are also different types of mechanical methods of scale
removal. One of the earliest scale-removal methods was the use of
explosives. But this technique damaged tubulars and cement, and
could not remove thick scale. Here comes impact bits and milling
technology, which were developed to run on coiled tubing inside the
tubular.
Fluid-mechanical jetting tools use multiple jet orifices or an
indexed jetting head to achieve full wellbore coverage. These tools
can be used with chemical washes. But this technique is effective
only for soft scale, such as halite. Adding a small concentration
of solids, 1-5% by weight, to a water jet can drastically improve
its ability to cut through scale. It is called abrasive slurries
method. But when scale is completely removed, abrasives such as
sand can damage steel tubulars. So it was proposed to use new
abrasive material called Sterling Beads abrasives. This material
matches the erosive performance of sand on hard, brittle scale
materials, while being 20 times less erosive of steel. The abrasive
particles have spherical shape, a high fracture toughness and low
friability.
And finally, universal scale-removal system is Jet Blaster tool,
which has jet-nozzle characteristics optimized for use with
Sterling Beads abrasives. This rotating jetting-head-based tool,
combined with Sterling Beads abrasives, forms the basis of new
system of coiled tubing-conveyed intervention services designed to
remove scale in downhole
tubulars. It can be used in two techniques: 1. Scale Blasting
technique; 2. Bridge Blasting technique.
Scale Blasting technique removes scale of any hardness without
damaging the tubular. Bridge Blasting technique is used when scale
deposits completely bridge tubular. [2]
Figure 3 - Jet Blaster tool
25
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2.2. Production zone selection As we said earlier, oil operating
companies do not prefer to produce water. But there are
some waters that better than others. There are three terms
describing water in the oil production: Sweep water water that
comes from an injection well or an active aquifer that is
contributing to the sweeping of oil from the reservoir; Good
water water that is produced into the wellbore at a rate below
economic limit of
WOR; Bad water excess water that is produced above WOR economic
limit. Here are some causes of bad
water (Fig.4): a. Casing, tubing or packer
leaks; b. Channel flow behind casing; c. Moving oil water
contact; d. Coning and cusping; e. Gravity segregation etc.
The main solutions in these cases are to use
shutoff fluids or mechanical shutoff using plugs, cement and
packers. [3]
Plugs can be used in the case when we have only one section or
layer of production, and cement squeeze is used when we are
producing from several layers.
Bridge plug is a downhole tool that is located and set to
isolate the lower part of the wellbore. Bridge plugs may be
permanent or retrievable, enabling the lower wellbore to be
permanently sealed from production or temporarily isolated from a
treatment conducted on an upper zone. They are installed by
wireline or coiled tubing. [6]
Squeeze cementing is the process of using pump pressure to
inject or squeeze cement into a problematic void space at a desired
location in the well. Squeeze cementing operations may be performed
at any time during the life of the well: drilling, completions or
producing phases. Invariably, though, it is an operation undertaken
to remedy a problem and presents the challenge of placing the
proper amount of cement (or sealant) in the target location.
Depending on the remediation need, squeeze cementing operations can
be performed above or below the fracture gradient of the exposed
formation (high pressure squeeze and low pressure squeeze,
respectively). [4]
But for water coning problem these techniques dont work well. So
there is another solution found. It is to perforate the water leg
of the formation and coproduce the water to
Figure 4 - Water problems [3]
26
-
eliminate the water cone (Fig.5). This low cost approach may
increase water cut, but improves the sweep efficiency. [3]
Figure 5 - Fighting water with dual drains
Finally, if water problems are solved, one can make new
perforations in order to increase production rate
27
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2.3. Fracturing The process of fracking produces fractures in
the initially low permeable reservoir rock in
order to stimulate the flow of natural gas or oil towards the
well, thus increasing the recoverable volumes. These fractures are
initiated by different techniques, such as pumping large quantities
of special liquids or gases at high pressure into the rock
formation, using explosives, electricity and etc [7].
The very first fracturing technique, named the exploding
torpedo, was discovered and then patented in 1866 by Col. Edward A.
L. Roberts. An iron case, containing an amount of explosive, was
lowered into the well close to the reservoir rock, where it was
exploded. However, the first commercial application of what is
nowadays known as hydraulic fracturing was conducted about hundred
years later, in 1949 near Duncan, Oklahoma; and has been widely
used ever since [11].
There are 4 main domains of fracturing [9]:
- Hydraulic fracturing (water-based, foam-based, oil-based,
acid-based, alcohol-based, emulsion-based, cryogenic fluids such as
CO2, N2, He);
- Pneumatic fracturing (gas fracturing); - Fracturing by
explosives; - Other (thermal, mechanical cutting, and etc.)
Fracturing by liquids (or hydraulic fracturing) is by far the
most efficient and developed fracturing method today (Fig.6). The
fracturing fluids commonly consist of water, proppant and chemical
additives that create and enlarge fractures within the reservoir.
Different fluid compositions at their end determine different
techniques of hydraulic fracturing based on the formation types.
For example, acids are widely used in carbonate formations, and
water with proppants in cataclastic reservoirs (shales,
sandstones). The proppants - sand, ceramic pellets or other small
incompressible particles are used to hold
open the newly created fractures. In addition, chemical
additives support the process of fracturing by changing the pumping
fluid and rock properties (the list of commonly used chemical can
be found here:
https://fracfocus.org/chemical-use/what-chemicals-are-used).
Nowadays, the process of hydraulic fracturing is a complicated
process of several stages. The main steps are the following
[8]:
Figure 6. A brief scheme of hydraulic fracturing [10].
28
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1. Injection of a prepad, a low-viscosity fluid used to
condition the formation. It may contain fluid loss additives,
surfactants, and have a particular salinity to prevent formation
damage.
2. Injection of a pad, a viscous fluid with no proppants that
initiates the generation of fractures. Main criteria high pumping
pressure.
3. Injection of a proppant containing fracturing fluid.
Proppants are needed to keep the fractures open and thus highly
permeable.
4. Treatment with flush fluids, in order to clean up the
formation. Main criteria high pumping rate.
Other than water-based hydraulic and acid fracturing, there are
many techniques of fracking the reservoir formations. The most
common techniques are listed in Table 1. Many methods are not
included in the table, because currently they are only in their
concept stage, and were not yet established as commercially
rentable. Type of Fracking Advantages Disadvantages Foam-based
fluids
Water usage reduced (or completely eliminated in case of CO2
based foams).
Reduced amount of chemical additives. Reduction of formation
damage. Better cleanup of the residual fluid.
Low proppant concentration in fluid, hence decreased fracture
conductivity.
Higher costs. Difficult rheological characterization
of foams, i.e. flow behavior difficult to predict.
Higher surface pumping pressure required.
Oil-based fluids
Water usage much reduced or completely eliminated.
Fewer (or no) chemical additives are required. Abundant
by-product of the natural gas
industry. Increased the productivity of the well. Lower
viscosity, density and surface tension of
the fluid, which results in lower energy consumption during
fracturing.
Recovery rates (up to 100%) possible. Very rapid clean up (often
within 24 hours).
Involves the manipulation of large amounts of flammable propane,
hence potentially riskier than other fluids and more suitable in
environments with low population density.
Higher investment costs. Success relies on the formation
ability
to return most of the propane back to surface to reduce the
overall cost.
Alcohol-based fluids
Water usage much reduced or completely eliminated.
Methanol is not persistent in the environment (biodegrades
readily and quickly under both anaerobic and aerobic conditions and
photo-degrades relatively quickly).
Excellent fluid properties: high solubility in water, low
surface tension and high vapor pressure.
Methanol is a dangerous substance to handle: a. Low flash point,
hence easier to ignite. b. Large range of explosive limits. c. High
vapor density. d. Invisibility of the flame.
Emulsion-based fluids
Depending on the type of components used to formulate the
emulsion, these fluids can have potential advantages such as: a.
Water usage much reduced or completely
eliminated. b. Fewer (or no) chemical additives are
required. Increased the productivity of the well. Better
rheological properties.
Potentially higher costs.
Liquid CO2 Potential environmental advantages: The main
disadvantages follow from
29
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a. Water usage much reduced or completely eliminated. b. Few or
no chemical additives are required. c. Some level of CO2
sequestration achieved.
Reduction of formation damage (reduction of permeability and
capillary pressure damage by reverting to a gaseous phase; no
swelling induced).
Evaluation of a fracture zone is almost immediate because of
rapid clean-up. The energy provided by CO2 results in the
elimination of all residual liquid left in the formation from the
fracturing fluid.
the fluids low viscosity. Proppant concentration must
necessarily be lower and proppant sizes smaller, hence decreased
fracture conductivity.
CO2 must be transported and stored under pressure (typically 2
MPa, -30C).
Corrosive nature of CO2 in presence of H2O.
Unclear (potentially high) treatment costs.
Pneumatic racturing Potential environmental advantages: a. Water
usage completely eliminated. b. No chemical additives are
required.
Potential for higher permeabilities due to open, self-propped
fractures that are capable of transmitting significant amounts of
fluid flow.
Limited possibility to operate at depth.
Limited capability to transport proppants.
Explosive fracturing Potential environmental advantages: a.
Water usage completely eliminated. b. No chemical additives are
required.
Minimal vertical growth outside the producing formation.
Selected zones stimulated without the need to activate
packers.
Minimal formation damage from incompatible fluids.
Homogeneous permeability for injection wells. Minimal on-site
equipment needed.
Can replace hydraulic fracturing only for small to medium
treatments, i.e. the fracture penetration is somewhat limited.
Proppant is not carried into the fracture. Instead, propellant
fracturing relies upon shear slippage to prevent the fracture from
fully closing back on itself.
The energy released underground, albeit relatively low, could
potentially induce seismic events.
Table 1. Main non-conventional methods of fracking [9].
30
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Well Productivity Optimization
There are many causes of flow restrictions that lead to
additional pressure drop in the well bore, and thus reduce the
productivity. And understanding these restrictions is the key
feature to the treatment and optimization of the flow. Productivity
itself is a complicated function of well geometry and properties of
the porous medium. With time, many additional restrictors develop
in the production point, which are needed to be taken care of. The
main problems include [14]:
Migration of fine particles Change in wettability Swelling of
clays Induced particle plugging Deposition of asphaltenes and
sludge Emulsion Block Bacteria Water Block
All these problems arise from different operations like [12]:
Drilling (filter cake, water block, swelling of clays,
precipitation of salts,
slumping of sands, etc.); Completion and Workover (migration of
fines to the formation from the cement
slurry, precipitation of solids from the cement, plugging by
materials from wellbore fluids, improper perforation conditions,
hydration and swelling of clays, etc.);
Stimulation (polymer invasion, emulsification, etc.);
Production, water/gas injection, EOR (formation dissolution, fines
migration,
solid invasion, sand influx, etc.). Thanks to the modern
technologies, most of these formation and well bore damages can
be eliminated by a single piece of equipment, called the Coiled
Tubing (CT). The name refers to a long continuous metal pipe, which
is spooled on a reel for transportation. However, a fully
functional CT unit is more than just a reel. The coiled tubing unit
is a complete set of equipment, that can perform standard tubing
operations in the field alone. The unit consists of the following
elements (Fig.7)[15]:
Reel - for storage and transportation of the CT; Injector Head
the driving force to insert and retrieve the CT, also has a
pipe-
straightening unit; Control Cabin used for monitoring and
controlling the CT; Power Pack - generates necessary power to
operate the CT unit.
31
-
Figure 7. Schlumberger CT unit [13].
This design of the CT is crucial and brings a lot of advantages
over the other technologies.
The main distinctive features along with the drawbacks of the CT
are given in the Table 2. Advantages Disadvantages
Deployment and retrievability while continuously circulating
fluids;
Ability to work with surface pressure present (no need to kill
the well);
Minimized formation damage when operation is performed without
killing the well;
Reduced service time as compared to jointed tubing rigs because
the CT string has no connections to make or break;
Increased personnel safety because of reduced pipe handling
needs;
Highly mobile and compact. Fewer service personnel are
needed;
Existing completion tubulars remaining in place, minimizing
replacement expense for tubing and components;
Ability to perform continuous well-control operations,
especially while pipe is in motion.
CT is subjected to plastic deformation during bend-cycling
operations, causing it to accumulate fatigue damage and reduce
service life of the tubing string;
Only a limited length of CT can be spooled onto a given service
reel because of reel transport limitations of height and
weight;
High pressure losses are typical when pumping fluids through CT
because of small diameters and long string lengths. Allowable
circulation rates through CT are typically low when compared to
similar sizes of jointed tubing.
CT cannot be rotated at the surface to date. However, interest
in rotating CT has been high in recent years, and several companies
are actively designing equipment that will allow rotating of
CT.
Table 2. Main distinctive features of the CT [12].
32
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2.4. Work-over The work-over is a process of performing major
maintenance or repair works of an oil or
gas well. In most cases, this operation involves killing the
well and the removal of the production tubing. This could be
avoided by using coiled tubing, snubbing or slickline equipment at
the early well service stages. However, if a complete treatment is
necessary, a special equipment unit called the work-over rig is
installed at the well [6].
The main causes of the work-over are given in the table below
[16]:
1. Equipment failure Broken rod in pumping well (due to
mechanical wear); Subsurface pump failure (due to physical wear of
pumps moving parts); Leak in tubing (due to corrosion or mechanical
stresses); Plug (due to accumulation of solids in the production
string).
2. Wellbore problems Sanding Formation Damage Oil-Water
Emulsions Corrosion
The processes of work-over differ based on the problem type.
However, they all share the main steps, which are:
Shutting down the well; Preparation of the well-head; Tubing
rig-up; Service equipment rig-down; Necessary works and restarting
the well
by previous steps in inverse order.
A typical work-over rig consists of the following (Fig.17):
a wheeled truck; an extensible mast (tower) that is
connected by the pivoting assembly to the truck;
a remotely-controlled pivoting assembly that allows moving the
mast from horizontal (travelling) to vertical (operational)
position;
a remotely-controlled telescoping assembly that allows extending
the mast from retracted (travelling) to extended (operational)
position;
a remotely-controlled hoisting assembly
Figure 8. Work-over rig components [17]
33
-
to lift selected objects within the mast; a power supply (diesel
engine); a work floor, a metal deck with a hole in the middle that
allows to work above the
wellhead and the BOP; a tubing board, also known as the
derrickmans working platform.
In addition, work-over rigs can be divided into classes based on
their size and power (Tab.3).
Class II Class III Class IV Class V
-
2.6. References 1. L.A. Saputelli, S. Mochizuki, L. Hutchins, R.
Cramer, M.B. Anderson, J.B. Mueller, A.
Escorcia,A.L. Harms, C.D. Sisk, S. Pennebaker, J.T. Han, A.
Brown, C.S. Kabir, R.D.Reese, G.J. Nunez, K.M. Landgren, C.J.
McKie, and C. Airlie. Promoting real-timeoptimization of
hydrocarbon producing systems. In SPE Oshore Europe
Aberdeen,September 2003.
2. Schlumberger, Oilfield Review Autumn 1999, Fighting Scale
Removal and Prevention 3. Schlumberger, Oilfield Review Spring2000,
Water Control 4.
http://www.halliburton.com/en-US/ps/cementing/cementing-solutions/squeeze-
cementing/default.page?node-id=hfqela4e 5.
http://www.ifpenergiesnouvelles.com/index.php/content/download/70601/1513892/versi
on/2/file/Panorama2011_11-VA_Eau-Production-Carburants.pdf 6.
Schlumberger Oilfield Glossary. . 7. EPA." The Process of Hydraulic
Fracturing. N.p., n.d. Web. 24 Nov. 2014.
. 8. Fink, Johannes Karl. Hydraulic Fracturing Chemicals and
Fluids Technology. Waltham,
MA: Gulf Professional / Elsevier, 2013. Print. 9. Gandossi,
Luca. "JRC Publications Repository." : An Overview of Hydraulic
Fracturing
and Other Formation Stimulation Technologies for Shale Gas
Production. N.p., n.d. Web. 29 Nov. 2014.
10. Granberg, Al. Fracking. Digital image. What Is Hydraulic
Fracturing? N.p., n.d. Web. 29 Nov. 2014. .
11. "Shooters - A "Fracking" History." American Oil & Gas
History. N.p., n.d. Web. 24 Nov. 2014. .
12. "PEH:Coiled-Tubing Well Intervention and Drilling
Operations." PetroWiki. N.p., n.d. Web. 03 Dec. 2014. .
13. "CT EXPRESS Rapid-Deployment Coiled Tubing Unit."
Schlumberger. N.p., n.d. Web. 03 Dec. 2014. .
14. Pandey, A. K. WELL STIMULATION TECHNIQUES. Rep. N.p.: n.p.,
n.d. Web. 2 Dec. 2014. .
15. An Introduction to Coiled Tubing: History, Applications, and
Benefits // ICoTA, 2005 16. "Workovers." Workovers. N.p., n.d. Web.
07 Dec. 2014.
. 17. Ibarra, Santiago. Toy Workover Rig. Patent US 20120045964
A1. 23 Feb. 2012. Print.
35
Contents1. Flow Dynamics and Production Monitoring1.1.
Production vs Well & Surface Equipment1.2. Producing Interval
Evaluation1.3. Well Testing & Monitoring1.4. Permanent
monitoring1.5. Sub-sea well. Flow optimization1.6. Reference2. Well
production optimization2.3. Assuring flow through tubular2.2.
Production zone selection2.3. FracturingWell Productivity
Optimization2.4. Work-over2.6. References