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Journal of Petroleum Engineering & Technology
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It is my privilege to present the print version of the [Volume 6; Issue 3] of our Journal of Petroleum
Engineering & Technology, 2016. The intension of JoPET is to create an atmosphere that stimulates
vision,researchandgrowthintheareaofPetroleumEngineering.
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STM JOURNALS

1. A Study on Oil and Gas Processing Facility in a Part of Upper Assam Basin
Himangka Kaushik, Nitish Prasad, Nayan Medhi, Anirban Rajkhowa, Tanbi Medhi,
Antoni Baruah, Thong Teron 1
2. Designing Methodology for Identifying Different Types of Influx Entering in a Well Bore during
Drilling and Study of Influx Behavior
Pulkit Chaudhary, Deepankar Chadha 7
3. Effects of Fracture Properties on Oil Recovery in Tight Reservoirs
Fuseinatu Latif, Victus Kordorwu, Kwabena Okyere-Nyako, Joel Teye Tetteh, Quaye Carl Anthony 12
4. Well Injectivity Management during Geological Carbon Sequestration Activity
R.M. Benashor, A. Nourian, G. Nasr, A.J. Abbas 32
5. Two-Phase Flow Modelling in Clay Rich Shale
H. Bashir, Y. Wang, A. Abbas 44
6. Construction/Assembling of a Low Cost Adsorption Apparatus for Cored Clay Shales
H. Bashir, Y. Wang, A. Abbas 54
7. Study the Effect of Variation of Crude Assay on the Design of Distillation Column
Mohamed Abusin, Abdelgadir Basheer, Moh. Hamed, Moh. Abdlaziz 61
8. Comparative Study between Smart Controls and Conventional Bottom Hole Completions
Perez Antwi Boafo, Victus Kordorwu, Joel Teye Tetteh, Kwabena Okyere-Nyako 77
ContentsJournal of Petroleum Engineering & Technology

JoPET (2016) 1-6 © STM Journals 2016. All Rights Reserved Page 1
Volume 6, Issue 3
www.stmjournals.com
A Study on Oil and Gas Processing Facility in a
Part of Upper Assam Basin
Himangka Kaushik, Nitish Prasad, Nayan Medhi*, Anirban Rajkhowa,
Tanbi Medhi, Antoni Baruah, Thong Teron
Department of Petroleum Engineering, Dibrugarh University, Assam, India
Abstract
Crude oil that is produced from the oilfields cannot be directly sent to the refineries for
further processing. It must undergo additional processing before being sent to refineries to
prevent pipeline corrosion, resolve transportation issues and satisfy the crude specification of
the refinery which can be achieved by oil and gas processing facility. It is an integral part of
the upstream petroleum industry, which meets the required specifications of oil and gas before
sent to the refineries. The present work aims to study the typical processes of an oil and gas
processing facility to understand the design, control and optimization of such facility in a part
of Upper Assam Basin. The study analyses the existing methods for crude oil and gas
processing of the study area and an attempt has been made to develop the existing
arrangement of the facility to improve the energy efficiency as well as product quality. The
new arrangement of the processing facility can be applied to corresponding oil and gas
processing facilities in other parts of the world that have the similar arrangement as that of
the study area.
Keywords: Oilfield, refineries, oil and gas processing facility, basin
INTRODUCTION
Oil and gas processing acts as the preliminary
treatment required to be performed on the raw
crude oil and gas obtained from the wells so as
to make it fit for further processing in the
refinery. An oil well generally produces a
mixture of crude oil, condensate, hydrocarbon
gas; water containing dissolved minerals; other
gases including nitrogen, carbon dioxide and
possibly hydrogen sulphide and solids
including sand from the reservoir, dirt, scale
and corrosion products from the tubing. The
purpose of an oil and gas processing facility is
to separate the oil from gas, water and solids
so that it meets the desired sale specifications
and criteria and subsequently deliver it to the
transportation system for further refining.
The first processing step employed at many oil
and gas processing facilities involves the
separation of oil, gas and water produced from
the well. The separation process is done in a
pressure vessel called 'separator'. In the two-
phase separator, the gas is separated from the
liquid (oil+water) whereas in the three-phase
separator gas, water and liquid hydrocarbons
are separated [1]. A Degasser can be used for
degassing the emulsion solution. A Vapor
Recovery Unit (VRU), which is a small, self-
contained compressor may be used to suck
vapor out of the crude oil storage tank and
pump them into the gas collection system [2].
The low-pressure gases that cannot be
transported are usually compressed for
reinjection into the reservoir or for use in gas
lift wells.
The produced gas must also be treated before
sales or disposal. All the acid gas compounds,
H2S and CO2 must be removed from the gas
and if it is economical or required for
environmental reasons, the H2S should be
converted to elemental sulphur. The acid gases
are removed from the gas in the sweetening
unit where sweetening agents such as
monoethanolamine (MEA), diethanolamine
(DEA), methyl-di-ethanolamine (MDEA), etc.
are used [3]. The water vapor is removed from
the gas using proper gas dehydration process
such as Glycol dehydration [2]. The Upper
Assam Basin, declared as a proven
petroliferous basin with commercial

Volume 6, Issue 3
www.stmjournals.com
Designing Methodology for Identifying Different Types of
Influx Entering in a Well Bore during Drilling and Study
of Influx Behavior
Pulkit Chaudhary*, Deepankar Chadha
Department of Petroleum Engineering, DIT University, Dehradun, Uttarakhand, India
Abstract
Drillers frequently encounter kick in drilling operations. Kick refers to the unwanted entry of
formation fluid into the well bore. Primary well control and secondary well control are used
to control influx entry into a well during drilling operations. Primary well control refers to
making the overbalance by the hydrostatic pressure exerted by drilling fluid on the formation
pressure. Secondary well control refers to controlling the kick through the use of BOPs. BOPs
consist of annular preventers, pipe ram, shear ram and blind ram. Reservoir fluid entering the
well bore during drilling or tripping is called influx. Influx encountered in a well bore could
be oil, water and gas or their mixture. Behavior of all the influxes is different. For example, if
a gas influx is encountered, it percolates upwards in the annulus while if water it there it just
mixes with the drilling fluid and causes a reduction in its density. The behavior of gas influx in
open well and closed well condition is different and complex. In this paper, the behavior of
different types of influxes encountered in a well bore has been thoroughly studied and a
methodology for understanding the type of well influx that has entered the well bore has been
designed.
Keywords: Kick, influx behavior, influx identification, well control
INTRODUCTION
Drilling refers to digging the earth deeper and
deeper in search of hydrocarbons. It is a very
risky job. So, we need trained and competent
personnel for this job. To do this job, we need
a drilling rig. Different types of rigs are
employed to do different operations. On land,
we employ onshore rigs or land rigs, and at
sea, we use offshore rigs. There are different
types of offshore rigs used. These are
submersible, semi-submersible jack-up, drill
ships and heave-compensators, swamp barges.
Oil companies hire drilling contractor, which
provide drilling crew and drilling rig. Drilling
contractors charge on per day basis, which
may vary according to type of rig chosen. All
the rigs have a common function to perform
that is to drill a hole in search of
hydrocarbons. All the drilling rigs have three
types of systems in common: (1) rotary
system, (2) hoisting system and (3) circulating
system [1]. Rotary system mainly consists of
rotary table and Kelly or top drive (these
days), swivel and rotary hose. Rotary system is
responsible for rotating the drill string. This
process is depicted in Figure 1.
Fig. 1: Rotary System.
Hoisting system consists of draw works,
crown block, dead line anchor, travelling
block, hook, drilling line. Draw works consists
of shafts, clutches, chains and gears for
changing the speed of drilling line and

Volume 6, Issue 3
www.stmjournals.com
Effects of Fracture Properties on Oil Recovery in Tight
Reservoirs
Fuseinatu Latif1
, Victus Kordorwu1,
*, Kwabena Okyere-Nyako2
, Joel Teye Tetteh3
,
Quaye Carl Anthony2
1
Department of Petroleum Engineering, Kwame Nkrumah University of Science and
Technology, Kumasi, Ghana
2
Department of Petroleum Engineering, University of Louisiana, Lafayette, USA
3
Department of Chemical Engineering, University of Utah, Salt Lake City, USA
Abstract
Unconventional reservoirs, characterized by low permeability are gradually becoming
a force to reckon with in today’s world owing to the rapid depletion of conventional
resources. However, low oil production from tight reservoirs can be mitigated by
implementing hydraulic fracturing. In this study, Schlumberger’s eclipse-100 simulator
was used to simulate various scenarios in order to determine the best fracture geometry
and the effects of fracture properties on oil recovery. The properties considered were
fracture half-length, width and number. Oil recovery from the tight reservoir was found
to be 0.47% OIP and the application of hydraulic fracturing increased the recovery to
4.78%. OIP sensitivity analysis was carried out by varying well trajectory, porosity,
permeability and wettability. It was found out that, fracture geometry of 300 ft half-
length, 1 inch width and a fracture number of 15 is ideal for this reservoir, both
technically and economically. An increase in the fracture number affected the spacing
greatly. As the number increased, initial production from the reservoir increased.
However, cumulative production declined with continued increase in fracture number
as spacing decreased. The fracture half-length had a more significant impact on the
early time behavior as a result of the fractures reaching further into the reservoir.
Increase in fracture width impacted on the late time production behavior of the well by
maintaining production for a longer duration. Variations in the reservoir properties
after obtaining the optimum case show that hydraulic fracturing is applicable to tight
reservoirs.
Keywords: Hydraulic fracturing, fracture geometry, recovery factor, oil recovery
INTRODUCTION
Global demand for oil is soaring high and
likely to reach its peak in the near future.
Conventional resources are depleting very fast
and may not be able to sustain the global oil
demand in the near future. This explains why
focus is shifting from conventional to
unconventional resources. Unconventional
resources (tar sands, gas hydrates, shale
reservoirs, tight reservoirs, and coal bedded
methane) have now become the order of the
day in the oil and gas industry. One feature
generally runs in all tight reservoirs, they
naturally have low matrix permeability. One
truth about the reservoir is that the reservoir
fluids and heterogeneity are fixed constants
that cannot be changed; only the way of
accessing the reservoir can be changed. This
explains why technological advancements are
aimed at increasing permeability to maximize
production in tight reservoirs. Hydraulic
fracturing, one of the conventional techniques
used in increasing permeability in tight
reservoirs, employs the use of pressurized
liquid to create additional pores in the
formation. The complexity of the interactions
between the reservoir rock and the fractures
requires modeling to describe. The complexity
also depends on the behavior of the fracture
properties such as fracture half-length, width,
aperture, number, spacing orientation,
direction and etc., and its interactions with one
another, and its effect on production rates. In
this study, a conventional technique known as

Volume 6, Issue 3
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Well Injectivity Management during Geological Carbon
Sequestration Activity
R.M. Benashor*, A. Nourian, G. Nasr, A.J.Abbas
School of Computing, Science and Engineering, University of Salford, Manchester, England
Abstract
It is well known that the saline aquifer formations are considered very reliable candidates for
carbon sequestration because of their wide availability and they have good storage capacity.
Due to high formation salinity, there a big concern about bore formation dry-out resulting
from the salt precipitation in the form of halite (NaCl). The mutual solubility between CO2 and
brine is responsible for creating the salt deposits, this processes may take place in three ways:
(1) when CO2 dissolves in the brine it increases the brine density; (2) when CO2 dissolves in
the brine it reacts with water and forms carbonic acid (H2CO3); (3) H2O dissolves or
vaporizes into CO2 stream, removing water from the brine and increasing its salinity; as the
salt concentration increases, this leads to dry-out and salting-out. When the brine salinity
increases, the dissolution of CO2 will dissolve. If this phenomenon takes place, it will cause
reduction in the well injectivity and this will lead to pressure build up problems. In oil
industry, the formation damage i.e. reduction in the permeability is attributed to the clay
swelling when it comes in contact with water. The permeability is an important property of
porous media, many engineers and geologists intensively studied this property and their main
concern is always about the formation damage. In this experimental work, the focus was about
the well injectivity and how it can be improved. As mentioned earlier, due to high NaCl
concentration, the salt will be precipitated in the near well bore and it will cause reduction in
the aquifer permeability and porosity and consequently the well injectivity will be affected.
The dilution of aquifer salinity by periodic pumping of the sea water (salinity 3.5%) will assist
in improving the well injectivity. In this work, the studied core samples (Gray Berea sandstone
and Parker sandstone) were saturated with different brine solutions (10, 15, 20 and 26.4%),
the core flow tests were carried out for the above mentioned core samples before and after
dilution by sea water utilizing the experimental setup, and the results are obtained. It was
observed that the dilution by seawater assisted in improving the CO2 flow rates; this means
that the injectivity will be increased. The main objective is to improve the well injectivity and
increase the solubility trapping mechanism.
Keywords: Aquifer salinity, porosity, permeability, CO2 storage, well injectivity
INTRODUCTION
The global carbon dioxide emissions can be
mitigated, throughout the geological
underground storage [1]. The existing
technology of CO2 capture process assisted for
the implementation of several sacksful storage
projects. [2]. The existing projects
demonstrated that over 1 million metric tons of
CO2 per year is currently stored, the projects
includes the Sleipner project in the North Sea
[3], the In-Salah field in Algeria [4] and the
Snohvit field in Norway [5]. Depleted oil and
gas reservoirs are good choices for CO2
storage as they are located adjacent to carbon
dioxide sources. As it is known, the saline
formations contain salt water and this water
which is not suitable for drinking. Due to high
brine concentrations, the salt in the form of
halite (NaCl) will be precipitated around the
well bore, and it will cause the dry-out
phenomenon due to the dissolution
(vaporization) of brine into the dry, flowing
stream of supercritical CO2 [6]. For the
sacksful CO2 storage projects, the cost
effectiveness is a very important factor, and
this comes through minimizing the number of
the CO2 injectors [7]. Several factors can
control the well injectivity; these include the
storage formation permeability, formation
thickness, and the storage formation porosity.

Volume 6, Issue 3
www.stmjournals.com
Two-Phase Flow Modelling in Clay Rich Shale
H. Bashir*, Y. Wang, A.Abbas
School of Computing, Science and Engineering, University of Salford, Manchester M5 4WT,
United Kingdom
Abstract
Computational fluid dynamics (CFD) have made huge strides lately and are bit by bit turning
into a pervasive device in science and engineering. In this paper, we present a new
mathematical model, which adequately describes single- and two-phase flow, which considers
relative permeability and capillary pressure in water rich clay shale. Furthermore, we
implement the two-phase flow model into COMSOL multiphysics software. From the result
analysis, it is concluded that the relative permeability and capillary pressure are important
properties, which describe the simultaneous movement of water and gas phase in
unconventional clay-rich shale.
Keywords: COMSOL multiphysics, clay rich shale, two-phase flow, relative permeability,
capillary pressure
INTRODUCTION
Computational fluid dynamics (CFD) has been
utilized to study various problems in broad
spectra of disciplines including the oil and gas
industry. It empowers the researcher or
engineer with tools needed in demonstrating
the material science of fluid movement
through prohibitive media and thus is suited to
investigate the flow of fluids or liquids
through repositories, completion and wells [1].
In light of its far-reaching computer capacity
and broad advancement in the simulation field,
CFD has been highlighted as an efficient tool
of immense importance in the 21st century. It
has quality in its capacity to model a 2 or 3-
dimensional (D) complex problems and is a
proficient strategy for flowing phases, which
are complex in nature [2].
Computational methods have an advantage,
however in the sense that they provide direct
insight into the relationship between the
microscopic and macroscopic behaviour of the
system investigated. The capability to utilize
CFD to examine the affectability of
preparation to reservoir parameters is
especially essential for reservoirs, for example,
shale gas repositories, where current estimates
are troublesome or illogical to perform [3].
One of the challenges in the shale gas is
hydraulic fracture fluid [4, 5] and gas in place
estimation [6–8]. The monolayer Langmuir
isotherm has been shown to fit methane gas
adsorption data accurately for clay-rich shale
[9–12], i.e., it is correlated to gas reservoir
pressure. To incorporate the gas adsorption
mass term into the mass conservation
equation, the amount of adsorbed gas is
determined according to the Langmuir's
isotherm as a function of reservoir pressure.
As the pressure increases with continuous gas
storage in reservoir wells, more adsorbed gas
is stored in the solid matrix from free gas
phase from the region of higher pressure,
contributing to the total gas storage. Therefore,
this must be considered when modelling by
gas transport by the inclusion of an adsorption
isotherm. Fluid flow in unconventional shale
gas reservoir has different dynamics when
compared to the conventional natural gas
source, the reason for this complication is that
shale gas is characterized by complex pore
system each with a different physical property.
Some researchers on shale gas reservoirs using
SEM, FIB and petrographic images have
concluded that four different naturally
occurring porous systems are found in shale
reservoir [13–17]. Wang and Reed have shown
that four diverse styles of pore systems co-
exist in shale reservoirs: inorganic medium,

Volume 6, Issue 3
www.stmjournals.com
Construction/Assembling of a Low Cost Adsorption
Apparatus for Cored Clay Shales
H. Bashir*, Y. Wang, A. Abbas
School of Computing, Science and Engineering, University of Salford, Manchester, United Kingdom
Abstract
The secret to unlocking these reserves lies in accurate experimental data which in turn
depends on the experimental method used. Recently many procedures such as manometric,
volumetric and gravimetric have been developed to quantify adsorption. In this paper, we
show how to construct/assemble a simple manometric adsorption apparatus for gas
adsorption. The setup is inexpensive and can be built easily using part available in university
laboratories. Furthermore, it can be used to measure adsorption capacity of different cored
materials using different gases at low pressure (<450 Psia). The laboratorial setup permits
the measurement of gas adsorption equilibrium on cored samples with dimensions of 3-inch
by 1.5 inch up to 450 Psia at laboratory temperature (23°C), and can also be used at higher
temperatures (up to 45°C) by using a water bath.
Keywords: Manometric apparatus, adsorption, clay rich shale
INTRODUCTION
Since the inception of gas adsorption
experiments till date, there have been a
number of techniques used by various
equipment vendors and laboratories
(commercial or in-house manometric,
gravimetric setup/instrument) and researchers
(manometric, volumetric, gravimetric,
chromatographic, temperature programmed
desorption). The most widely used
experimental method in shale adsorption is the
manometric [1–4] and volumetric method. [5–
7] These methods are based on Boyle’s law,
and are very similar to porosity measurements
using pycnometer [8].This technique is
sometimes referred to as Sieverts method and
can be designed as constant-volume
(manometric) or constant pressure
(volumetric) measurement [9]. They are
widely used because of their simplicity and
ease of construction. Commercial devices built
based on these techniques include FY–KT
1000 isothermal adsorption apparatus based on
the volumetric method [1], automated Sieverts'
apparatus known as the PCT-Pro-E&E from
Setaram Instrumentation [5]. Adsorption
apparatus based on other methods are the
Rubotherm and Mettler-Toledo based on the
gravimetric technique [10] and the mass
balance [11, 12].
Some laboratories apply in-house
modifications to these devices and custom
make them for specific experimental
conditions like shale adsorption at high
temperature [13, 14] and moisture
equilibration [15]. Several studies have been
conducted on such devices, for example in
adsorption measurements using gravimetric
techniques [16–19].
In terms of modification and user designed
equipment, several tactics were used by
researchers [16, 19–24]. Gasparik et al.,
2012 modified their setup to enable sorption
measurements at high temperatures, by
separating the low-temperature zone (reference
cell) and high temperature zone (sample cell)
[16]. Li et al. (2015) however, developed a
high-pressure gas adsorption–desorption
instrument mounted on a constant-temperature
oil bath [22]. Heller and Zoback, (2011)
modified a conventional tri-axial machine to
measure adsorption and gas permeability by
incorporating a Quizix Series 1500 pump,
using a method similar to volumetric
adsorption principle, and an adsorption
equipment where an isothermal multistep gas
uptake process measures the storage capacity

Volume 6, Issue 3
www.stmjournals.com
Study the Effect of Variation of Crude Assay on the
Design of Distillation Column
Mohamed Abusin1,
*, Abdelgadir Basheer1
, Moh. Hamed2
, Moh. Abdlaziz3
Department of Petroleum Refining and Transportation Engineering, College of Petroleum
Engineering and Technology, Sudan University of Science and Technology, Khartoum, Sudan
Abstract
The purpose of this study is to investigate the effect of variation of crude assay on the design
of crude distillation column. Different crudes assay (six samples of Sudanese crude oil) with
different properties which are processed at the Khartoum Refinery Company have been
simulated using Aspen HYSYS under the same operating conditions in order to identify the
effect of this variation. Energy consumption optimization is done by using preheated train heat
exchangers to raise the temperature of the crude from 31.2°𝐶 to 198.3°𝐶 (124500 kw has been
saved). The simulation process show different products quantities with slightly variation in
their purities. Specific products (e.g. naphtha) have been increased from 9.1–11.8%. As a
result of that atmospheric residue decreases from 63.8–60.9% by controlling the reflux ratio,
pumps around flow rate and using multi-feed locations. The design results are 2.4 m column
diameter, 27.6 m height of the column and 54 numbers of trays.
Keywords: CDU, simulation, design, control, ASPEN HYSIS
INTRODUCTION
Background
Most of Sudanese crude are known for their
good quality such as low sulfur content
smaller than 0.5 wt% and moderate to high an
American Petroleum Institute however like
any paraffinic crude oil, some Sudanese crudes
has high content of paraffin waxes. Nile blend
has an API gravity higher than (>32), which
subsequently declined to 30 API indicating a
somewhat heavier crude (medium), Nile blend
has less than 0.06 weight percent of sulfur
consider as sweet oil with a high level of wax
content (>30%) and with continuous increase
in production processes from different regions,
some crudes which are considered much
heavier than others have contributed in the
total production in economical quantities [1].
AL-FULLA crude which is produced from
Western Kordoffan state can be taken an
example of these crudes which has such
properties high density and viscosity, high acid
value and water content, high calcium content,
these properties need to be reduced to the
minimum in order to be treated. Refineries are
designed to process a range of crude oils such
that their feedstock will provide specific
fractions of refined products, sometimes this
range will vary greatly form refinery to
refinery. The change in crude oil quality
around the world has impact the petroleum
refining industry in such a way that the current
and new refineries are being re-configured and
designs respectively to process heavier
feedstock, the crudes which are considered
heavier than other crudes have to be refined
here instead of exporting it as crude to achieve
better economic benefits [2].
Distillation Process
Crude petroleum as it is produced from the
field is a relatively low value material since, in
its native state, it is rarely usable directly.
However, it can be refined and further
processed into any number of products whose
value is many times that the original oil. The
first step in any petroleum refinery is the
separation of the crude into various fractions
by the process of distillation (physical
separation of a mixture into two or more
products that have different boiling points).
These fractions may be products in their own
right or may be feedstock for other refining
processing unit [3]. In most refineries, this
process is carried out in two stages. The oil if

Volume 6, Issue 3
www.stmjournals.com
Comparative Study between Smart Controls and
Conventional Bottom Hole Completions
Perez Antwi Boafo1
, Victus Kordorwu1,
*, Joel Teye Tetteh2
, Kwabena Okyere-Nyako3
1
Department of Petroleum Engineering, Kwame Nkrumah University of Science and Technology,
Kumasi, Ghana
2
Department of Chemical Engineering, University of Utah, Salt Lake City, USA
3
Department of Petroleum Engineering, University of Louisiana at Lafayette, Louisiana, USA
Abstract
This research project made use of Schlumberger’s “ECLIPSE 100” reservoir simulator to
predict the performance of a reservoir with an overlying gas cap and an underlying aquifer
(i.e., a three- phase Water-Oil-Gas reservoir) under conventional BHC techniques. Additional
work was done to ascertain the suitability of incorporating an Intelligent Well (IW) to deal
with water production problem by placing Inflow Control Valves (ICV) at particular segments
in the well to monitor and control fluid flow. Comparing BHCs, it was found out that open
hole completion yielded the maximum performance whereas gravel pack completion yielded
the least. The simulation yielded FOEs of 13.27, 13.04, 13.02 and 12.98% for open hole,
cased hole, perforated liner and gravel pack completions, respectively. Application of the
intelligent well (IW) as opposed to the conventional cased hole well yielded a 4.06%
increment in FOE. The project yielded a 41% reduction in water cut by the intelligent well
compared to the conventional well. These were all due to the open-close action of the valves
employed in the intelligent well model. This justified the applicability and suitability of
intelligent wells in improving oil production by solving unnecessary water production, thus
providing better returns on investment.
Keywords: Open-hole, Casing, Annular Cementation, Perforated Liner, Pre-slotted liner,
Gravel Pack, Intelligent Well, Field Oil Efficiency
INTRODUCTION
After exploration of oil and the subsequent
drilling of a well to obtain oil from the
containing reservoir to the surface, the major
problem faced is the type of bottom-hole
completion configuration to use to maximize
efficiency and profit. A well represents the
direct communication link between the surface
and the reservoir. Drilling a well contributes a
huge percentage of the total cost of
development of an oil and gas field [1]. Well
completion focuses on; designing tubular
purposely to be installed in the well; the
design and the installation in the well of the
various components used to allow efficient
production, pressure integrity testing,
emergency of reservoir fluids, reservoir
monitoring, barrier placement, well
maintenance and well kill; the installation of
safety devices and equipment which
automatically shuts a well in the event of a
disaster. The perfect completion design
program thus, is the most cost effective well
completion, which will match up the demand
placed on the well during its lifetime of
production. This is because an evaluation of
the performance of a well determines the
economic viability of drilling and completing
that particular well. Productivity index (PI) is
often a reliable method, which is used to
evaluate the productivity of a well throughout
its lifetime [2].
Study Objectives
The main aim of this project was to compare
the performance of the reservoir under various
bottom hole completion techniques and
Intelligent Well Technology (IWT). This aim
was achieved by
 Using PERFORM software to generate
Vertical Flow Performance tables, thus
obtaining natural flow rates for different
BHC techniques by plotting IPR and TPR
curves.

Journal of Petroleum Engineering & Technology vol 6 issue 3

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Journal of Petroleum Engineering & Technology vol 6 issue 3