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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, research and growth in the area of Petroleum Engineering. Timely publication, honest communication, comprehensive editing and trust with authors and readers have been the hallmark of our journals. STM Journals provide a platform for scholarly research articles to be published in journals of international standards. STM journals strive to publish quality paper in record time, making it a leader in service and business offerings. The aim and scope of STM Journals is to provide an academic medium and an important reference for the advancement and dissemination of research results that support high level learning, teaching and research in all the Scientific, Technology and Medical domains. Finally, I express my sincere gratitude to our Editorial/ Reviewer board, Authors and publication team for their continued support and invaluable contributions and suggestions in the form of authoring writeups/reviewing and providing constructive comments for the advancement of the journals. With regards to their due continuous support and co-operation, we have been able to publish quality Research/Reviews findings for our customers base. I hope you will enjoy reading this issue and we welcome your feedback on any aspect of the Journal.

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Journal of Petroleum Engineering & Technology

Contents

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

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

3. Effects of Fracture Properties on Oil Recovery in Tight Reservoirs Fuseinatu Latif, Victus Kordorwu, Kwabena Okyere-Nyako, Joel Teye Tetteh, Quaye Carl Anthony

4. Well Injectivity Management during Geological Carbon Sequestration Activity R.M. Benashor, A. Nourian, G. Nasr, A.J. Abbas

5. Two-Phase Flow Modelling in Clay Rich Shale H. Bashir, Y. Wang, A. Abbas

6. Construction/Assembling of a Low Cost Adsorption Apparatus for Cored Clay Shales H. Bashir, Y. Wang, A. Abbas

7. Study the Effect of Variation of Crude Assay on the Design of Distillation Column Mohamed Abusin, Abdelgadir Basheer, Moh. Hamed, Moh. Abdlaziz

8. Comparative Study between Smart Controls and Conventional Bottom Hole Completions Perez Antwi Boafo, Victus Kordorwu, Joel Teye Tetteh, Kwabena Okyere-Nyako

Journal of Petroleum Engineering & Technology ISSN: 2231-1785(online), ISSN: 2321-5178(print) 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 twophase 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, selfcontained 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

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Journal of Petroleum Engineering & Technology ISSN: 2231-1785(online), ISSN: 2321-5178(print) 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

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Journal of Petroleum Engineering & Technology ISSN: 2231-1785(online), ISSN: 2321-5178(print) 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 halflength, 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

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Journal of Petroleum Engineering & Technology ISSN: 2231-1785(online), ISSN: 2321-5178(print) Volume 6, Issue 3 www.stmjournals.com

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.

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Journal of Petroleum Engineering & Technology ISSN: 2231-1785(online), ISSN: 2321-5178(print) 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 3dimensional (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 coexist in shale reservoirs: inorganic medium,

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Journal of Petroleum Engineering & Technology ISSN: 2231-1785(online), ISSN: 2321-5178(print) 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

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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 31.2Â°đ??ś to 198.3Â°đ??ś (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 9.1â&#x20AC;&#x201C;11.8%. As a result of that atmospheric residue decreases from 63.8â&#x20AC;&#x201C;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

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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.

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