Shale Gas An Unconventional Resources Of Energy

National Conference on Modern Mining & Petroleum Production Techniques

(NCMMPPT 24 Th-25 Th April - 2017)

Bhagwant Unversity,Ajmer, Rajasthan

IMPORTANCE OF WATERFLOODING IN CRUDE RECOVERY Ankita Agarwal1, Harsh patel2, Chandrakant Mishra3, Abhishek Agarwal4 1,2,3,4

Department of Petroleum Technology, BU Ajmer, Rajasthan, India

ABSTRACT In the oil industry, water flooding or water injection is where water is injected into the oil field, usually to increase pressure and thereby stimulate production. Water injection wells can be found both on- and offshore, to increase oil recovery from an existing reservoir. Water is injected to support pressure of the reservoir (also known as voidage replacement), and also to sweep or displace oil from the reservoir, and push it towards a well. Normally only 30% of the oil in a reservoir can be extracted, but water injection increases that percentage (known as the recovery factor) and maintains the production rate of a reservoir over a longer period. The level of effectiveness of a water flood depends on the mobility ratio between the oil and water, and the geology of the oil reservoir. Water flooding is effective because almost all reservoir rocks are either water-wet or mixed-wet. Hence, the principal reason for water flooding of an oil reservoir is to increase the oil production rate and ultimately oil recovery

Keywords: Flooding Patterns, Areal displacement in water flood, vertical displacement in water flood, microscopic efficiency and macroscopic displacement efficiency 1.INTRODUCTION Water flooding is the method being used to increase the production from oil reservoirs by injecting the water. Use of water to increase oil production is known as "secondary recovery" and typically follows "primary production," which uses the reservoir’s natural energy (fluid and rock expansion, solution-gas drive, gravity drainage, and aquifer influx) to produce oil. The principal reason for water flooding an oil reservoir is to increase the oil-production rate and, ultimately, the oil recovery. This is accomplished by "voidage replacement"—injection of water to increase the reservoir pressure to its initial level and maintain it near that pressure. Thus the

Paper ID: 101

NCMMPPT 24Th-25 Th April - 2017



Bhagwant Unversity,Ajmer, Rajasthan water displaces oil from the pore spaces, but the efficiency of such displacement depends on many factors (e.g., oil viscosity and rock characteristics). Other key factors that drove water flooding’s development and increasing use are:   

Water is inexpensive Water generally is readily available in large quantities from nearby streams, rivers, or oceans, or from wells drilled into shallower or deeper subsurface aquifers Water injection effectively made production wells that were near the water-injection wells flow or be pumped at higher rates because of the increased reservoir pressure.

The optimum parameters to start water flooding are :



 

Reservoir oil viscosity :- Reservoir oil viscosity is minimum value at bubble point. High oil viscosity gives better sweep efficiency. It is viable option to start water flooding at this point. Free gas saturation :- Less gas saturation are preferred for water flooding projects. Saturation of gas is less at bubble point hence its viable option to start waterflooding here. Cost of injection equipment :- Low pressure of reservoir is desirable as cost of pumping can be reduced. Overall life of reservoir :- Flooding should be started as early as possible to reduce operating cost of reservoirs.

2. WATERFLOODING CONSIDERATIONS Unit displacement efficiency is how water displaces oil from a porous and permeable reservoir rock on a microscopic scale. This is the level of analysis that is applied when water-/oil-flow measurements are made on small core-plug samples in a laboratory. Calculations for determining how well water flooding will work on a reservoir scale must include the effects of geology, gravity, and geometry (vertical, areal, and well-spacing/-pattern arrangement). The formula for overall water flood oil-recovery efficiency ER might be simply and stated as the product of three independent terms:

...................(1) Where, ED = the unit-displacement efficiency, EI = the vertical-displacement efficiency, and EA = the areal-displacement efficiency. Of course, assuming independence of these three factors is not valid for real oil reservoirs.

Paper ID: 101




Bhagwant Unversity,Ajmer, Rajasthan Oil properties are important to technical and economic success of a water flood. The key oil properties are viscosity and density at reservoir conditions. In a porous medium, the mobility of a fluid is defined as its endpoint relative permeability divided by its viscosity; hence, a fluid with a low viscosity (≤ 1 cp) has a high mobility unless its relative permeability is very low. Similarly, a low-API crude oil (≤ 20°API) has a high viscosity and a very low mobility unless it is heated to high temperatures. Because water’s viscosity at reservoir temperatures generally is much lower than or, at best, equal to that of the reservoir oil, the water-/oil-viscosity ratio is generally much greater than 1:1. The water-/oil-mobility ratio is a key parameter in determining the efficiency of the water/oil displacement process, with the recovery efficiency increasing as the water-/oilmobility ratio decreases.

3. FLOODING PATTERNS The flooding patterns used in water flooding are :

Irregular patterns :- In this the wells are not uniformly located. The faulting, localized variations may lead to irregular patterns. And in case of marginal fields, limited number of wells is available. As per productivity few low producing wells randomly converted to the injection wells.  Peripheral injection patterns :- The injection wells are located at external boundary of reservoir. And gives good oil recovery with minimum produced water and thus the low injector to producer ratio causes long time to fill up reservoir volume which delays the production. The injection wells should be nearby to prevent by passing of oil.  Regular injection patterns :- The regular injection pattern consists of two drives and they are :1. Direct line drive :- In this the line of injection wells and production wells is opposite to each other. And the distance between the two wells is same as distance between injector and producer well. 2. Staggered line drive :- In this the injector and producers are not exactly opposite to each other instead place at distance of a/2. Where, ‘a’ is distance between two wells. This line drive consists of various spots such as five spot, seven spot and nine spot. 3. Five spot :- The distance between all like wells is constant i.e a=2d, where ‘d’ is the distance between line of injectors and producers. 4. Seven spot :- The injection wells are located at the corner of hexagon. 5. Nine spot :- Eight injectors surrounding one producer.  Cristal and Basal injection patterns :- The injection wells are at the top of dipping reservoir in case of gas injection. The injection wells are at the bottom of the dipping reservoir in case of water injection.

Paper ID: 101





4. MICROSCOPIC EFFICIENCY OF WATERFLOODING At the pore level (i.e., where the water and oil phases interact immiscibly when moving from one set of pores to the next),wettability and pore geometry are the two key considerations. The interplay between wettability and pore geometry in a reservoir rock is what is represented by the laboratory-determined capillary pressure curves and water/oil relative permeability curves that engineers use when making original oil in place (OOIP) and fluid-flow calculations. This article discusses these basic concepts and their implications for initial water- and oil-saturation distribution, relative permeability, and how initial gas saturation will affect water/oil flow behavior.

Fig. Is a schematic diagram of the water/oil displacement process. 

Fig. – Saturation profile during a water flood.

5. MACROSCOPIC DISPLACEMENT EFFICIENCY IN A LINEAR WAYERFLOOD This discusses the mathematical aspects of water/oil displacement for homogeneous linear systems. The mathematical aspects are given by two methods they are : Unsteady state processes :- The displacement of oil by water from a porous and permeable rock is an unsteady-state process because the saturations change with time and distance from the injection point (see schematic diagram of Fig. 1). These saturation changes cause the relative permeability values and pressures to change as a function of time at each position in the rock. Fig. 2 illustrates the various stages of an oil/water displacement process in a homogeneous linear system. The mathematical derivation of fluid flow equations for porous media begins with nthe simple concept of a material – balance calculations.

Paper ID: 101





Fig. 1 – Saturation profile during a waterflood

Fig. 2 – Saturation distribution during different stages of a waterflood. L = length, ft; x = x-direction length, ft; andx/L is dimensionless and varies from 0 to 1.  Buckley – Leverett solution :- In this mathematical manipulation of these equations obtains the Buckley-Leverett equation or frontal-advance equation. To derive this equation, it is assumed that the fractional flow of water is a function only of the water saturation and that there is no mass transfer between the oil and water phases. Fractional flow equation is used to determine water cut at any point in the reservoir assuming that water saturation is known at that point. Fractional flow equation,

Paper ID: 101





Where, Kro – Relative oil permeability, md Krw – relative water permeability, md µrw - viscosity of water, cp µro – viscosity of oil, cp A straight line on semi – log papers, the relative permeability ratio may be expressed as function of Sw. 

Fig. 3 – Determination of flood-front saturation. fwf = fractional flow of water at the flood front, = average water saturation behind the flood front at water breakthrough, and Swf = water saturation at the flood front. Frontal Advance equation is designed to determine water saturation profile in reservoir at any given time during water injection. (X)SW = ( 5.615 * Winj / Ø * A ) ( dfw / dSw )SW Where, (X ) SW = distance from the injection for any given saturation Sw, feet Paper ID: 101




Bhagwant Unversity,Ajmer, Rajasthan Winj = cumulative water injected, bbl Ø = porosity t = time, day Equation suggests that the position of any value water saturation Sw at any given water injected Winj is proportional to dfw / dsw at any Sw.

6. Areal Displacement in waterflood Before computer modeling was common, the 3D aspects of a waterflood evaluation were simplified so that the technical problem could be treated as either a 2D-areal problem or a 2Dvertical problem. To simplify 3D to 2D areal, either the reservoir must be assumed to be vertically a thin and homogeneous rock interval (hence having no gravity considerations) or one of the published techniques to handle the vertical heterogeneity and expected gravity effects within the context of a 2D-areal calculation must be used. The primary areal considerations for a waterflood involve the choices of the pattern style (see Fig. 1) and the well spacing. Maximizing the ultimate oil recovery and economic return from waterflooding requires making many pattern- and spacing-related decisions when secondary recovery is evaluated. This has been particularly true for onshore oil fields in the US in which a significant number of wells were drilled for primary production. For offshore oil fields where the maximum number of wells is limited, the optimal waterflood injectionwell/production-well layout is best determined by the use of 3D numerical reservoir simulation.

Paper ID: 101





Fig. 1 – Common waterflood-pattern configurations.

7. Vertical Displacement in a water flood The vertical displacement in a water flood shows the impact of vertical variations in permeability and the effect of gravity on simple 2D reservoir situations in which the areal effects are ignored. Gravity effects always are present because for any potential water flood project, oil always is less dense than water, even more so after the gas is included that is dissolved in the oil at reservoir conditions. Parameters affecting vertical displacement efficiency are controlled by : gravity segregation caused by difference in density, mobility ratio, vertical to horizontal permeability variation and capillary forces. Gravity segregation occurs when density between two phases is more. When the injected fluid is less dense than the displaced fluid, gravity segregation occurs and lighter fluid overrides the displaced fluid ex. In – situ combustion. Gravity segregation occurs when the injected fluid is denser than displaced fluid ex. Water flood.

Paper ID: 101




Bhagwant Unversity,Ajmer, Rajasthan Vertically variation in permeability reservoirs is relatively common. The vertical variation in permeability leads to poor vertical sweep efficiency at breakthrough owing to uneven flow in different layers.

8. Limitations of Water flood technology Water flooding can increase the volume of oil recovered from a reservoir; however, it is not always the best technology to use and it can have complicating factors. When evaluating how best to produce a particular oil reservoir, a petroleum engineer should include water flooding in the options that are analyzed, both technically and economically. Those evaluations should include such potentially complicating factors as:    

Compatibility of the planned injected water with the reservoir’s connate water Interaction of the injected water with the reservoir rock (clay sensitivities, rock dissolution, or generally weakening the rock framework) Injection-water treatment to remove oxygen, bacteria, and undesirable chemicals The challenges involved in separating and handling the produced water that has trace oil content, naturally occurring radioactive materials (NORMs), and various scale-forming minerals.

9. Conclusion Water floods are the dynamic processes the performance of which, as production wells respond to the injection of water, can be improved by modification of operations by the technical team. Such modifications include changing the allocation of injection water among the injection wells and the water flooded intervals, drilling additional wells at infill locations, and/or modifying the pattern style. Water flooding has been used successfully in oil fields of all sizes and all over the world, in offshore and onshore fields.

10. References 1. Craig Jr., F.F. 1971. The Reservoir Engineering Aspects of Waterflooding, Vol. 3. Richardson, Texas: Monograph Series, SPE. 2. Willhite, G.P. 1986. Waterflooding, Vol. 3. Richardson, Texas: Textbook Series, SPE. 3. Rose, S.C., Buckwalter, J.F., and Woodhall, R.J. 1989. The Design Engineering Aspects of Waterflooding, Vol. 11. Richardson, Texas: Monograph Series, SPE. 4. Fettke, C.R. 1938. The Bradford oil field, Pennsylvania and New York. Mineral Resources Report M21, Pennsylvania Geological Survey, Harrisburg, Pennsylvania, 298–301. 5. Scheihing, M.H., Thompson, R.D., and Seifert, D. 2002. Multiscale Reservoir Description Models for Performance Prediction in the Kuparuk River Field, North Slope Paper ID: 101




Bhagwant Unversity,Ajmer, Rajasthan of Alaska. Presented at the SPE Western Regional/AAPG Pacific Section Joint Meeting, Anchorage, 20–22 May. SPE-76753-MS. 6. Ebanks, W.J., Jr., Scheihing, M.H., and Atkinson, C.D. 1993. Flow Units for Reservoir Characterization. In Development Geology Manual, D. Morton-Thompson and A.M. Woods, No. 10, 282–285. Tulsa: AAPG Methods in Exploration, American Association of Petroleum Geologists.

Paper ID: 101


Th

National Conference on Modern Mining & Petroleum Production Techniques (NCMMPPT 24 -25

Th

April - 2017)


DRILL BIT Chandan Kumar1, Karan Singh 2, Harish Chandra Maurya3 , Kavita Deric4 1,2

Department of Petroleum Technology, BU Ajmer, Rajasthan, India 3 3

Department of CSE, BU Ajmer, Rajasthan, India

Department of English, DPS Beawar, Rajasthan, India

ABSTRACT The result was the Hercules™ roller cone bit platform, which is designed to with- stand the harshest and most challenging drilling environments. Hercules roller cone bits provide a combination of durability, control and speed that enhances the efficiency of any operation. Field-proven design philosophies provide stable and reliable directional performance in inter bedded and intrusive formations, to drill harsh directional sections faster and more consistently. Each bit is equipped with a premium bearing system and designed with optimized hydraulics for increased cleaning and efficient drilling. Our Solution: Greater stability - reduces g-forces, improves cutting structure life, and provides higher instantaneous and average ROP Efficient cone cleaning and cuttings removal - ensures the bit engages new rock on every rotation Increased durability - more effective seal life and bearing reliability Better steer ability - reduced length decreases bit-to-bend, enhancing directional capabilities and lower.

Paper ID: 102


Th


Th

April - 2017)


 NTRODUCTION A drilling bit is the cutting tool which is made up on the end of the drill string. The bit drills through the rock by scraping, chipping, gouging or grinding the rock at the bottom of the hole. Drilling fluid is circulated through passageways in the bit to remove the drilled cuttings. There are however many variations in the design of drill bits and the bit selected for a particular application will depend on the type of formation to be drilled. The drilling engineer must be aware of these design variations in order to be able to select the most appropriate bit for the formation to be drilled. The engineer must also be aware of the impact of the operating parameters on the performance of the bit.  Selection of Bit Weight and Rotary Speed The weight applied to the bit and the rotational speed of the drilling sting have a major effect on the both the penetration rate and the life of the bit. 1. Consideration must be given to the following items when selecting the bit weight and rotary speed. 2. The effect of the selected operating conditions on the cost per foot for the bit run question and on subsequent bit runs. 3. The effect of the selected operating conditions on crooked hole problems. 4. The max. desired penetration rate for the fluid circulating rate and mud processing rates available and for efficient kick detection. 5. Equipment limitations on the available bit weight and rotary size.  Types of drill bit 1.Drag Bits 2.Roller cone Bits 3.Diamond Bits. 4.Natural diamond bits 5.PDC bits 6.TSP bits.  Figure of drill bits

Paper ID: 102


Th


Th

April - 2017)


1.DRAG BITSDrag bits where the first bits used in rotary drilling bit are no longer is common use. A drag bit consist of rigid steel blades shaped like a fish-tail which rotate as a single unit. 2.ROLLER CONE BITS Roller cone bits (Rock bits) are still the most common types of bit use world wide. The cutting action provided by cones which have either steel teeth or tungsten carbide insert. These cones rotate on the bottom of the holes and drill hole predominantly with a grinding and chipping action. Rocks bits obviousare classified as milled tooth bits or insert bits depending on the cutting surface on the cone.

Paper ID: 102


Th


Th

April - 2017)


3.DIAMOND BITS

Diamond has been used as a material of cutting rock for many years. Since it was first used how ever the types of diamond and the way in which it is set in the drilling bit have changed. 4.NATURAL DIAMOND BITSThe hardness and where resistance of diamond made iy an obvious material to be used for a drill bit. The diamond bit really a type of drag bite since it has no moving cones and operates as a single unit. Industrial diamonds have been used for many years in drill bits and in core heads. The cutting action of a diamond bit is achieved by scraping away the rock. 5.PDC Bits A new generation of diamond bits known as polycrystalline diamond compact (PDC) bits where introduce in the 1980. These bits have the same advantage and disadvantage as natural diamond bits but use small discs of synthetic diamond to provide the scraping cutting surface. 6.TSP Bits

Paper ID: 102


Th


Th

April - 2017)


A future development of the PDC bit concept was the introduction in the later 1980 of the thermally stable polycrystalline (TSP) diamond drilling bit. These bits are manufactured in a similar fashion to PDC bits but are tolerant of much higher temperature than PDC bits.  perating Conditions The bit weight and rotary speed have a tremendous effect on rate of penetration. As shown in the fig,  No significant penetration rate is obtained until the threshold bit weight is applied (Point a).  Penetration rate then increases rapidly with increasing values of bit weight for moderate values of bit weight (Segment ab).  A linear curve is often observed at moderate bit weight, subsequent increase in bit weight causes only slight improvement in the penetration rate (segment cd)  In some cases, a decrease in penetration rate is observed at extremely high values of bit weight (Segment de). This behavior is called bit floundering. It is due to less efficient bottom whole cleaning at higher rates of cutting generation. CONCLUSION Technology to drill holes and to excavate tunnels and openings in rock is vital for the economic, environmental, and scientific well-being of the United States. Drilling is a key technology in several applications of strategic or societal importance, including energy and mineral production, environmental protection, and infrastructure development. During this century, U.S. technology has dominated the worldwide drilling industry and much of the excavation and comminution industries. In the committee's view, this U.S. dominance is likely to erode without continued technological advances. Although incremental improvements in the component processes in the present state of the art can continue to make drilling more productive, it is the basic conclusion of this committee that revolutionary advances are within reach through the introduction and concerted development of smart drilling systems. A smart drilling system is one that is capable of sensing and adapting to conditions around and ahead of the drill bit to reach desired targets. This system may be guided from the surface, or it may be self-guided, utilizing a remote guidance system that modifies the trajectory of the drill when the parameters measured by the sensing system deviate from expectations.

Paper ID: 102


Th


Th

April - 2017)


REFERENCES 1. A1-Ameen S I, Talks M G, Waller M D, Tolley F P, Moreton G, Lomas M A and Yardley E D (1992), “The Prediction and Reduction of Abrasive Wear in Mining Equipment”, Final Report on ECSC Research Project No. 7220-AE/821, University of Nottingham and British Coal TSRE, Bretby. 2. Ambrose D (1987), Diamond Core Bit Performance Analysis, Unpublished Ph.D. Thesis, University of Nottingham. 3. Ashton S M (1984), “Slim Hole Drilling in the Canning Basin: Philosophy and Application”, Perth, pp. 521-531. 4. Atkins B C (1983), “The Utilization and Catagorisation of Manufactured Diamond Materials within the Mining Industry of Western Europe”, February, Geodrilling. 5. Barr M V and Brown E T (1983), “A Site Exploration Trial Using Instrumented Horizontal Drilling”, 5th Congress of International Society for Rock Mechanics, Melbourne, Australia.

Paper ID: 102



(NCMMPPT 24Th-25 Th April - 2017)


Drilling Engineering of Hydraulic optimization Jauhar Ali1, Jitendra Singh2, Nalin Chaudhary3, Kavita Deric4 1,2

Department of Petroleum Technology, BU Ajmer, Rajasthan, India 3 Department of CSE, DPS Beawar, Rajasthan, India 4

Department of English, DPS Beawar, Rajasthan, India ABSTRACT

These were necessary to increase bottom hole cleaning in deep wells. Generally to jet nozzles, the fluid course in bits was a hole bored into the middle of the bit and the drilling fluid leave from the drillstring directly into the annulus. These “conventional water courses” did not have the energy needed to lift the cuttings and help in the drilling process. Both roller cone bits and PDC bits have recesses to install various size jet nozzles in order to get proper hydraulics. Mostly roller cone bits used three or four jet nozzles, while PDC bits usually contain six to nine. The flow field of all jets must be estimated individually then added together. In order to increase a hydraulics power program, all areas concerning drilling fluids and the associated drilling equipment must be considered. The first component in any hydraulic optimization design is the surface equipment and the hydraulic horsepower obtained from them. There are two necessary factors on the surface of hydraulic horsepower. Keywords: Hydraulic power,optimization,drilling 1.INTRODUCTION

Energy is the rate of doing work. A Experimental aspect of power is that it can be transferrred or transformed from one form to another (e.g., from an electrical energy form to a mechanical energy form by a motor or engine). A loss of energy always occurs during transformation . In drilling fluids, energy is called hydraulic energy or commonly hydraulic horsepower.The basic equation for hydraulic energy isfurther described as below where H = hydraulic horsepower, p = pressure (psi or kPa), q = flow rate (gal/min or L/min), and 1,714 is the conversion of (psigal/min) to hydraulic horsepower [ or (kPa•L/min) = 44 750] . Rig pumps are the source of hydraulic energy carried by drilling fluids. This energy is commonly called the total hydraulic horsepower or pump hydraulic horsepower: RTENOTITLE

Paper ID 103





where H1 = total hydraulic energy (hydraulic horsepower) and p1 =actual or theoretical rig pump pressure (psi). (See prior equation for metric conversion.) Note that the rig pump pressure (p1) is the same as the total pressure loss or the system pressure loss. H1 is the total hydraulic energy (rig pump) required to counteract all friction energy (loss) starting at the Kelly hose (surface line) and Kelly, down the drillstring, through the bit nozzles, and up the annulus at a given flow rate (q). Bit hydraulic energy, Hb, is the power needed to counteract frictional power (loss) at the bit or can be expressed as the energy expended at the bit. 2. SURFACE HORSEPOWER In order to increse a hydraulics horsepower program, all aspects concerning drilling fluids and the associated equipment must be considered. The first component in any hydraulic design is the surface equipment and the hydraulic horsepower available from them. There are two essential factors on the surface hydraulic horsepower. The first is thefluid flow rate range. As discussed earlier, the flow pattern in the annulus should be laminar flow , therefore the maximum limit for the flow rate is a Reynolds Number of 2000. The maximum velocity in the annulus will be around the collars, and this velocity can be obtained by calculating the “critical velocity” over that section. In addition, running the pumps at that maximum range is not always advisable because there will be more wear and tear on the pumps and turbine much more fuel consumption. The lower limit is a range where there is enough sufficient hole cleaning. This is determined by using the velocity around the drillpipe and the largest annular section (normally the upper hole section or drillpipe/riser section). A normal range is around 50 ft/min. The second factor is the operating pressure of the mud pumps. Most mud pumps can produce the required pressure with little problem. However, because of the various components associated with the surface system (standpipe, rotary hose, pulsation dampener, etc.) the maximum upper surface pressure is usually limited to some value less than the maximum rated pump pressure. The available “surface horsepower” is then determined by: where: Hp = Surface Horsepower P = Pump Pressure (psi) Q = Pump Flow Rate (gal/min) Once the surface horsepower has been determined, the horsepower distributions can be made: where: Hpc = Circulation Horsepower Hpb = Bit Horsepower Hps P Q× 1714 = ------------HpsHpcHpb = + 1-50 Baker Hughes INTEQ Confidential 80270H Rev. B / December 1995 Drilling Fluids And Hydraulics Drilling

Paper ID 103





3. HYDRAULIC HORSE POWER Hydraulic horsepower is define on the basis of theory that cuttings are best removed from beneath the bit by delivering the most power to the bottom of the hole. The amount of pressure lost at thedrill bit, or bit pressure drop, is necessary in determining the hydraulic horsepower. drill Bit pressure drop is determined by: where: MD = Mud Density (lb/gal) Vn = Nozzle Velocity (ft/sec) From the bit pressure loss, hydraulic horsepower can be calculated: To optimize Bottom Hole Cleaning and Bit Hydraulic Horsepower, is essential to choose a circulation flow rate and nozzle sizes which will cause 65% of the pump pressure to be expended forcing the fluid through the jet nozzles of the bit. 4. FIXED CUTTER BIT HYDRAULIC The hydraulics horsepower for fixed cutter bits is based on the drilling fluids ability to flow remove cuttings beneath the cutters and to cool the drill bit. drilling Fluid volume is critical to PDC bit performance. drilling Fluid volume and drilling fluid velocity is critical to diamond dril bit performance.The major components of fixed cutter bit hydraulics are: 1. flow rate - Q (gal/min) and V (ft/min) 2. drilling fluid characteristics - MD (lb/gal), YP (lbs/100ft2) and PV (cps) 3. pressure loss - across the bit face (diamond bit) or through the jet nozzles (PDC bit) 4. the Total Flow Area (TFA) - instead of nozzle sizes A very important parameter in fixed cutter bits is “Hydraulic Power Per Square Inch” or HSI. It is calculated using Hhp (hydraulic horsepower): where: Hhp = Hydraulic Horsepower A = Bit Area (square inches)* Hif MD Q V × × n 1930 = ------------------------------Hif 0.48 Hps = × HSI H

Paper ID 103





5. PDC BIT HYDRAULIC Since PDCdrill bits are formation of specific (best used in plastic formations), the formation properties will determine the hydraulic energy and power required. The drilling fluid will dictate the HSI, for water-based drilling fluids it will be between 2.5 and 4.5, while for oil-based drilling fluids it will be between 1.5 and 3.0. The HSI, calculated at the jet nozzle orifices, will have various properties which will directly affect hydraulic energy and hydraulic horse power. 1. the drilling fluid velocity decreases abruptly once it went out the nozzles 2. high vertical velocity and low horizontal velocities are achieved across the bit face 3. for higher volumes of drilling fluid pumped, horizontal velocities will maximize, but not necesseraly HSI The increased horizontal velocities gives better cuttings removal, better cooling, and possibly better drilling rates. Nozzle velocity is calculated in the same way as with rollercone drill bits. 6. DIAMOND BIT HYDRAULIC The horizontal fluid velocity is the key element in diamond bit life and bit performance. It can be determined using: The fluid courses assist this by directing the drilling fluid across the bit to cool the diamonds and to remove the cutting. Vel=0.32*Q/TFA The fluid courses assist this by directing the drilling fluid across the bit to cool the diamonds and to remove the cuttings. 7. DIAMOND BIT FLOW PATTERN There are two major flow patterns in diamond hydraulic bits: 1. Cross Pad Flow System (feeder/collector system) a) the fluid travels along the high pressure “primary fluid courses” (those which connect to the crowfoot), to a point where “low pressure collectors” draw the drilling fluid flow across the diamond pad b) this assure that the diamondsdrill bit towards the outer diameter are cleaned and cooled c) The HSI should be between 1.5 and 2.5. 2. Radial Flow System a) gives a “high pressure primary fluid course” for each diamond row b) to allow fluid to travel in front of, and back each diamond pad to provide cuttings removal and cooling c) maintains uniformity horizontal drilling fluid velocity by tapering fluid course depth as they reached the outside diameter d) The HSI should be between 2.0 to 3.0. Paper ID 103





Paper ID 103





8.CONCLUSION The final results o this project. estimation of optimum weight on bit isf optimization show the meaningful of very important in drilling operation as this parameter can be vary during drilling operation. The optimization of weight on drill bit will optimize the whole drilling operation as a whole. maximize rate of drilling will decrease the time need for drilling those drcrease the cost for drilling operation: C The constants a1 until a8 representing formation strength under compaction, normal compaction, pressure differential, weight on bit, rotary speed, bit tooth wear and jet impact force are obtained using multiple regression analysis. C Bourgoyne and Young Model produce reliable rate of penetration model. Data number 9, 10, 12, 15, 16, 20, 23 and 25 predicted accurate rate of penetration compare with the actual rate of penetration obtained from the field areas. C Optimization for weight on bit found that for depth at 6592 ft optimize weight on bit is 23888 lbs compared to 30000 lbs at 6679 ft optimize value of weight on bit is 23888 lbs compared to 5000 lbs. For 9660 ft optimize value are 8575 lbs compare to 30000 lbs. The results of this project provide guidance for next drilling operation near the drilled well. The optimized values can be used as reference to obtain optimum drilling performance those decreas drilling charges. 9.REFERENCES 1.Chia, R. and Smith, R. 1986. A New Nozzle System To Achieve High ROP Drilling. Presented at the SPE Annual Technical Conference and Exhibition, New Orleans, Louisiana, 5-8 October.SPE-15518-MS. http://dx.doi.org/10.2118/15518-MS. 2.Kurosaki, H, Nakano, S. (2007). A New Approach to Synthetic Education as Disaster Prevention for Next Great Earthquake and Tsunami, Journal of Coastal Engineering Japan No. 54 , 1361-1365, 2007. Kurosaki, H, Nakano, S. (2008). Advanced Disaster Management Education for Students about Mega-Thrust Earthquakes Generating Tsunamis. International Workshop on Coastal Disaster Prevention No. 5 , 29-30. For cited journals the format is: 3.Jena, H.M, 2010. Hydrodynamics of Gas-Liquid-Solid Fluidized and Semi-Fluidized Beds.Ph.D. Thesis, National Institute of Technology, Rourkela. [4]. Miura, H., Takahashi, T., Kawase, Y., 2001. Effect of pseudo plastic behavior of liquid in co-current three- phase fluidized beds on bed expansion. Chemical Engineering Science, Vol-56. [5.] Sokol, W., 2001. Operating parameters for a gas-liquid-solid fluidized bed bioreactor with a low density biomass support. Biochemical Engineering Journal, Vol-8, 203-212. 4. Costa, N.; De Lucas, A.; Garcia, P., 1986. Fluid Dynamics of Gas- Liquid-So1id Fluidized Beds.Ind. Eng. Chem. Process Des.Dev. 5.Allia, K., Tahar, N., Toumi, L., Salem, Z., 2006. Biological treatment of water contamination by hydrocarbon in three-phase gas-liquid-solid fluidized bed. Global NEST Journal, Vol-8 (1), 9 – 15

Paper ID 103





Measurement while drilling Jogendra Singh Bhati1, Hitendra Singh Deora2, Manoj Kumar3, Saurabh Mishra4 1,2 Department of Petroleum Technology, BU Ajmer, Rajasthan, INDIA 3 Department of CSE, BU Ajmer, Rajasthan, INDIA 4 Department of MCA, BU Ajmer, Rajasthan, INDIA

Abstract A Measurement While Drilling (MWD) system is now available to provide more downhole measurements than ever before. The measurements currently made near the bit, while drilling is in progress, include: o formation radioactivity o formation resistivity , annular temperature downhole weight on bit o hole deviation o azimuth o tool face angle These geological and engineering measurements are transmitted via a continuous pressure wave through the mud inside the drill pressure wave through the mud inside the drill pipe. The signals are detected at the surface, pipe. The signals are detected at the surface, where they are processed by an on-site computer. Information is plotted in real time on continuous multi-scale logs, presented digitally on video displays, printed out in hard copy, and stored on magnetic tape. This paper briefly discusses the MWD system that provides these downhole measurements in real time during drilling. Citing actual logs, the paper focuses on specific examples of how these measurements are being used to aid in formation evaluation and to improve drilling control at the well site. Introduction

A drilling rig is used to create borehole or wells (also called a wellbore) in the earth's subsurface, for example in order to extract natural resources such as gas or oil. During such drilling, data is acquired from the drilling rig sensors for a range of purposes such as: decision-support to monitor and manage the smooth operation of drilling; to make detailed records (or well log) of the geologic formations penetrated by a borehole; to generate operations statistics and performance benchmarks such that improvements can be identified, and to provide well planners with accurate historical operations-performance data with which to perform statistical risk analysis for future well operations. The terms Measurement While Drilling (MWD), and Logging While Drilling (LWD) are not used consistently throughout the industry. Although, these terms are related, within the context of this section, the term MWD refers to directional-drilling measurements, e.g., for decision support for the smooth operation of the drilling, while LWD refers to measurements concerning the geological formation made while drilling.[1] MWD typically concerns measurement taken of the wellbore (the hole) inclination from vertical, and also magnetic direction from north. Using basic trigonometry, a three-dimensional plot of the path of the well can be produced. Essentially, a MWD Operator measures the trajectory of the hole as it is drilled (for example, data updates arrive and are processed every few seconds or faster). This information is then used to drill in a pre-planned direction into the formation which contains the oil, gas, water or Paper ID:104





condensate. Additional measurements can also be taken of natural gamma ray emissions from the rock; this helps broadly to determine what type of rock formation is being drilled, which in turn helps confirm the real-time location of the wellbore in relation to the presence of different types of known formations (by comparison with existing seismic data). Density and porosity, rock fluid pressures and other measurements are taken, some using radioactive sources, some using sound, some using electricity, etc.; this can then be used to calculate how freely oil and other fluids can flow through the formation, as well as the volume of hydrocarbons present in the rock and, with other data, the value of the whole reservoir and reservoir reserves. Directional survey measurements are taken by three orthogonally mounted accelerometers to measure inclination, and three orthogonally mounted magnetometers which measure direction (azimuth). Gyroscopic tools may be used to measure Azimuth where the survey is measured in a location with disruptive external magnetic influences, inside "casing", for example, where the hole is lined with steel tubulars (tubes). These sensors, as well as any additional sensors to measure rock formation density, porosity, pressure or other data, are connected, physically and digitally, to a logic unit which converts the information into binary digits which are then transmitted to surface using "mud pulse telemetry" (MPT, a binary coding transmission system used with fluids, such as, combinatorial, Manchester encoding, split-phase, among others). This is done by using a downhole "pulser" unit which varies the drilling fluid (mud) pressure inside the drillstring according to the chosen MPT: these pressure fluctuations are decoded and displayed on the surface system computers as wave-forms; voltage outputs from the sensors (raw data); specific measurements of gravity or directions from magnetic north, or in other forms, such as sound waves, nuclear wave-forms, etc. Types of information transmitted Directional information MWD tools are generally capable of taking directional surveys in real time. The tool uses accelerometers and magnetometers to measure the inclination and azimuth of the wellbore at that location, and they then transmit that information to the surface. With a series of surveys; measurements of inclination, azimuth, and tool face, at appropriate intervals (anywhere from every 30 ft (i.e., 10m) to every 500 ft), the location of the wellbore can be calculated. By itself, this information allows operators to prove that their well does not cross into areas that they are not authorized to drill. However, due to the cost of MWD systems, they are not generally used on wells intended to be vertical. Instead, the wells are surveyed after drilling through the use of multi-shot surveying tools lowered into the drillstring on slickline or wireline. The primary use of real-time surveys is in directional drilling. For the directional driller to steer the well towards a target zone, he must know where the well is going, and what the effects of his steering efforts are. MWD tools also generally provide toolface measurements to aid in directional drilling using downhole mud motors with bent subs or bent housings. For more information on the use of toolface measurements, see Directional drilling. Drilling mechanics information MWD tools can also provide information about the conditions at the drill bit. This may include: 

Rotational speed of the drillstring

Paper ID:104





    

Smoothness of that rotation Type and severity of any vibration downhole Downhole temperature Torque and weight on bit, measured near the drill bit Mud flow volume

Use of this information can allow the operator to drill the well more efficiently, and to ensure that the MWD tool and any other downhole tools, such as a mud motor, rotary steerable systems, and LWD tools, are operated within their technical specifications to prevent tool failure. This information is also valuable to Geologists responsible for the well information about the formation which is being drilled. Formation properties Many MWD tools, either on their own, or in conjunction with separate LWD tools, can take measurements of formation properties. At the surface, these measurements are assembled into a log, similar to one obtained by wireline logging. LWD tools are able to measure a suite of geological characteristics including density, porosity, resistivity, acoustic-caliper, inclination at the drill bit (NBI), magnetic resonance and formation pressure. The MWD tool allows these measurements to be taken and evaluated while the well is being drilled. This makes it possible to perform geosteering, or directional drilling based on measured formation properties, rather than simply drilling into a preset target. Most MWD tools contain an internal gamma ray sensor to measure natural gamma ray values. This is because these sensors are compact, inexpensive, reliable, and can take measurements through unmodified drill collars. Other measurements often require separate LWD tools, which communicate with the MWD tools downhole through internal wires. Measurement while drilling can be costeffective in exploration wells, particularly in areas of the Gulf of Mexico where wells are drilled in areas of salt diapirs. The resistivity log will detect penetration into salt, and early detection prevents salt damage to bentonite drilling mud. Data transmission methods Mud-pulse telemetry This is the most common method of data transmission used by MWD tools. Downhole, a valve is operated to restrict the flow of the drilling fluid (Mud) according to the digital information to be transmitted. This creates pressure fluctuations representing the information. The pressure fluctuations propagate within the drilling fluid towards the surface where they are received from pressure sensors. On the surface, the received pressure signals are processed by computers to reconstruct the information. The technology is available in three varieties: positive pulse, negative pulse, and continuous wave. Positive pulse Positive-pulse tools briefly close and open the valve to restrict the mud flow within the drill pipe. This produces an increase in pressure that can be seen at surface. The digital information can be encoded in the pressure signal using line codes or pulseposition modulation. Negative pulse

Paper ID:104





Negative pulse tools briefly open and close the valve to release mud from inside the drillpipe out to the annulus. This produces a decrease in pressure that can be seen at surface. The digital information can be encoded in the pressure signal using line codes or pulse-position modulation. Continuous wave Continuous wave tools gradually close and open the valve to generate sinusoidal pressure fluctuations within the drilling fluid. Any digital modulation scheme with a continuous phase can be used to impose the information on a carrier signal. The most widely used modulation scheme is continuous phase modulation. When underbalanced drilling is used, mud pulse telemetry can become unusable. This is usually because, in order to reduce the equivalent density of the drilling mud, a compressible gas is injected into the mud. This causes high signal attenuation which drastically reduces the ability of the mud to transmit pulsed data. In this case, it is necessary to use methods different from mud pulse telemetry, such as electromagnetic waves propagating through the formation or wired drill pipe telemetry. Current mud-pulse telemetry technology offers a bandwidths of up to 40 bit/s. [2] The data rate drops with increasing length of the wellbore and is typically as low as 1.5 bit/s[3] – 3.0 bit/s.[2] (bits per second) at a depth of 35,000 ft – 40,000 ft (10668 m – 12192 m). Surface to down hole communication is typically done via changes to drilling parameters, i.e., change of the rotation speed of the drill string or change of the mud flow rate. Making changes to the drilling parameters in order to send information can require interruption of the drilling process, which is unfavorable due to the fact that it causes non-productive time. Electromagnetic telemetry

These tools incorporate an electrical insulator in the drillstring. To transmit data, the tool generates an altered voltage difference between the top part (the main drillstring, above the insulator), and the bottom part (the drill bit, and other tools located below the insulator of the MWD tool). On surface, a wire is attached to the wellhead, which makes contact with the drillpipe at the surface. A second wire is attached to a rod driven into the ground some distance away. The wellhead and the ground rod form the two electrodes of a dipole antenna. The voltage difference between the two electrodes is the receive signal that is decoded by a computer. The EM tool generates voltage differences between the drillstring sections in the pattern of very low frequency (2–12 Hz) waves. The data is imposed on the waves through digital modulation. This system generally offers data rates of up to 10 bits per second. In addition, many of these tools are also capable of receiving data from the surface in the same way, while mud-pulsebased tools rely on changes in the drilling parameters, such as rotation speed of the drillstring or the mud flow rate, to send information from the surface to downhole tools. Making Paper ID:104





changes to the drilling parameters in order to send information to the tools generally interrupts the drilling process, causing lost time. Compared to mud-pulse telemetry, electronic pulse telemetry is more effective in certain specialized situations, such as underbalanced drilling or when using air as drilling fluid. It is capable of transmitting data up to ten times faster. However, it generally falls short when drilling exceptionally deep wells, and the signal can lose strength rapidly in certain types of formations, becoming undetectable at only a few thousand feet of depth. Wired drill pipe Several oilfield service companies are currently developing wired drill pipe systems. These systems use electrical wires built into every component of the drillstring, which carry electrical signals directly to the surface. These systems promise data transmission rates orders of magnitude greater than anything possible with mud-pulse or electromagnetic telemetry, both from the downhole tool to the surface and from the surface to the downhole tool. The IntelliServ[4] wired pipe network, offering data rates upwards of 1 megabit per second, became commercial in 2006. Representatives from BP America, StatoilHydro, Baker Hughes INTEQ, and Schlumberger presented three success stories using this system, both onshore and offshore, at the March 2008 SPE/IADC Drilling Conference in Orlando, Florida.

Retrievable tools

MWD tools may be semi-permanently mounted in a drill collar (only removable at servicing facilities), or they may be self-contained and wireline retrievable. Retrievable tools, sometimes known as Slim Tools, can be retrieved and replaced using wireline through the drill string. This generally allows the tool to be replaced much faster in case of failure, and it allows the tool to be recovered if the drillstring becomes stuck. Retrievable tools must be much smaller, usually about 2 inches or less in diameter, though their length may be 20 ft (6.1 m) or more. The small size is necessary for the tool to fit through the drillstring; however, it also limits the tool's capabilities. For example, slim tools are not capable of sending data at the same rates as collar-mounted tools, and they are also more limited in their ability to communicate with, and supply electrical power to, other LWD tools. Collar-mounted tools, also known as fat tools, cannot generally be removed from their drill collar at the wellsite. If the tool fails, the entire drillstring must be pulled out of the hole to replace it. However, without the need to fit through the drillstring, the tool can be larger and more capable.

Paper ID:104





The ability to retrieve the tool via wireline is often useful. For example, if the drillstring becomes stuck in the hole, then retrieving the tool via wireline will save a substantial amount of money compared to leaving it in the hole with the stuck portion of the drillstring. However, there are some limitations on the process.

Limitations

Retrieving a tool using wireline is not necessarily faster than pulling the tool out of the hole. For example, if the tool fails at 1,500 ft (460 m) while drilling with a triple rig (able to trip 3 joints of pipe, or about 90 ft (30 m) feet, at a time), then it would generally be faster to pull the tool out of the hole than it would be to rig up wireline and retrieve the tool, especially if the wireline unit must be transported to the rig. Wireline retrievals also introduce additional risk. If the tool becomes detached from the wireline, then it will fall back down the drillstring. This will generally cause severe damage to the tool and the drillstring components in which it seats, and will require the drillstring to be pulled out of the hole to replace the failed components; this results in a greater total cost than pulling out of the hole in the first place. The wireline gear might also fail to latch onto the tool, or, in the case of a severe failure, might bring only a portion of the tool to the surface. This would require the drillstring to be pulled out of the hole to replace the failed components, thus making the wireline operation a waste of time. Conclusion   

MWD as developed quickly compared to wireline technology. The technique is widely used in deviated wells and where rig rates are high. In vertical wells and low rig day rates wireline is more economical.

References 1. Dowell, Iain; Andrew Mills; Matt Lora (2006). "Chapter 15 - Drilling-Data Acquisition". In Robert F. Mitchell. Petroleum Engineering Handbook. II - Drilling Engineering. Society of Petroleum Engineers. pp. 647–685. ISBN 978-1-55563-1147. 2. "Mud-pulse telemetry sees step-change improvement with oscillating shear valves". 2008. Retrieved 23 March 2009. 3. "Orion II MWD System". 2009. Retrieved 23 March 2009. 4. "Intelliserv Network". 2008. Retrieved 13 March 2008. 5. "T.H. Ali, et al., SPE/IADC 112636: High Speed Telemetry Drill Pipe Network Optimizes Drilling Dynamics and Wellbore Placement; T.S. Olberg et al., SPE/IADC 112702: The Utilization of the Massive Amount of Real-Time Data Acquired in Paper ID:104





Wired-Drillpipe Operations; V. Nygard et al., SPE/IADC 112742: A Step Change in Total System Approach Through Wired-Drillpipe Technology". 2008. Retrieved 13 March 2008.

Paper ID:104





Gas Sweetening Akash Rana1, Vasani Hitesh kumar2, Patel Dhrupad Kumar3 , Saroj Chauhan4 1,2,3,4

Department of Petroleum Technology, BU Ajmer, Rajasthan, India

ABSTRACT Amine gas treating (also called sweetening) is good accuracy method for removing H2S, CO2 from a gas stream, and is commonly used in natural gas plants, petrochemical plants, and refineries. An amine unit typically consists of two towersa contactor to allow the selected amine to remove the acid gases by using the absorbers and strippers also to use the reboier,heat exchanger,filters. The proper design and operating of the gas sweetening plant is difficult and expensive and need to many man power. There are multiple potential problems that can result in an foaming, amine sweetening plant, including in adequate hydraulic capacity of the tool, damaged tools, nonoptimal operating conditions, heat stable salts, and less amine quality. Determining the damage of a sweetening plant is difficult because the investigating engineer can either confused the root cause of the problem, or fail to identify all of the effecting factors to the primary problem. Deductive intellection is a critical element in the review of the potential effect of the problem. This paper is shows the steps of process to sweet the gas using the gas sweetening plant . The steps include removing contaminants, adsorption , separation ,cooling, heating, stripping, filtration and also re-boiling..

Keywords: Adsorption, filtration, preheating, stripping.

1.INTRODUCTION Natural gas is consist a huge amount of acid gas concentrations, from parts per million to 50 volume percent and higher, depending on the complexion of the rock formation from where it comes. The corrosiveness of H2S and C02 is due to presence of water and due to toxicity of H2S and the law heating value of C02, sales gas is required to be sweetened to contain less than a Paper ID:105





quarter grain H2S per 100 standard cubic feet (4 parts per million) and to have always heating value greater than 920 to 980 Btu/SCF, depending on the required. The most widely process are used to sweet the natural gas are alkanolamines, and of the alkanolamines the two most common are monoethanolamine (MEA) and diethanolamine (DEA).

2. The Amine Sweetening Process The mono ethanolamine and di-ethanolamine sweetening processes are similar in their flow schemes and operations. They are used as aqueous solvents to selectively absorb H2S and C02 from sour natural gas streams. The sour gas is introduced at the bottom of an absorber and flows up the tower countercurrent to an aqueous amine stream. Within the tower the acid gases are absorbed by the amine. The amine is described as being lean in acid gas as it enters the top of the absorber, and rich as it exits the bottom, loaded with acid gas. From the absorber the rich amine is directed to the top of a stripping tower where a drop in pressure and application of heat enables the solvent to be stripped of the acid gases. The amine, again lean, is circulated back to the absorber for sweetening.

Inlet Gas Knockout Before entering the absorber, the gas is passed through an inlet separator where entrained droplets or slugs of liquid are removed from the gas stream by impaction devices (Figure 2). Baffles remove a portion of the liquids. Mist eliminator pads, located near the gas outlet of the tank, trap the rest. Typical contaminants in natural gas streams may be liquid hydrocarbons, salt water, sands, well treating compounds, pipeline treating chemicals, and compressor oils. It is important that these contaminants be removed before the gas reaches the absorber. Once in the sweetening system, these contaminants can cause a number of operational problems including foaming, equipment fouling, and high corrosion rates, usually resulting in solvent loss and difficulty in meeting sweet gas specifications. Inlet Gas Knockout Before entering the absorber, the gas is passed through an inlet separator where entrained droplets or slugs of liquid are removed from the gas stream by impaction devices (Figure 2). Baffles remove a portion of the liquids. Mist eliminator pads, located near the gas outlet of the tank, trap the rest. Typical contaminants in natural gas streams may be liquid hydrocarbons, salt water, sands, well treating compounds, pipeline treating chemicals, and compressor oils. It is important that these contaminants be removed before the gas reaches the absorber. Once in the sweetening system, these contaminants can cause a number of operational problems including foaming, equipment fouling, and high corrosion rates, usually resulting in solvent loss and difficulty in meeting sweet gas specifications.

Paper ID:105





Absorber The sour gas, freed of entrained liquids by the inlet separator, enters the bottom of the absorber. Usually the absorber is a tray column; although packed columns are also used. In either case, the objective is to provide intimate contact between the gas and the amine solvent so that the H2S and C02 molecules can transfer from the gas phase to the solvent liquid phase. In tray columns, a liquid level is maintained on each tray by a weir usually 2 or 3 inches high (Figure 3). The gas passes up from underneath the trays through openings in the trays such as perforations, bubble caps, or valves, and disperses into bubbles through the liquid, forming a froth. The gas disengages from the froth, travels through a vapor space, providing time for entrained amine solution to fall back down to the liquid on the tray, and passes through the next tray above. Nearly all absorption of H2S and C02 takes place on the trays, and not in the vapor space between the trays. n packed columns the liquid solvent is dispersed in the gas stream, by forming a film over the packing, providing a large surface area for C02 and H2S transfer from the gas to the liquid solvent. The degree of sweetening achieved is largely dependent on the number of trays or the height of packing available in the absorber. Twenty trays or the equivalent height in packing are common, and are often a standard design. A water wash consisting of 2 to 5 trays at the top of the absorber can be used to minimize vaporization losses of amine, and is often found in low pressure mono ethanolamine systems (1). In most cases a mist eliminator pad is installed near the gas outlet of the absorber to trap entrained solvent, and an outlet knockout drum, similar to the inlet separator for the gas feed, is provided to collect solvent carryover.

Three Phase Flash Tank In many units the rich amine solution is sent from the absorber to a flash skimmer tank to recover hydrocarbons that may have dissolved or condensed in the amine solution in the absorber. The pressure of the solution is dropped as it enters the tank, allowing the lightest of the hydrocarbons to flash. The heavier hydrocarbons remain as a liquid, but separate from the aqueous amine, forming a separate liquid layer. Because the hydrocarbons have a lower density than the aqueous amine, they form the upper liquid layer, and can be skimmed off the top. The aqueous amine, freed from the hydrocarbon, is drained from the bottom of the tank. Not only is the flash tank valuable in recovering lost hydrocarbon product, it is also beneficial in maintaining the condition of the amine solution and the amine sweetening system. Hydrocarbon contamination in aqueous amine solutions often promote foaming. Equipment fouling may be more severe and occur at a faster rate in the absence of a flash separator. Sulfur plant operations may be hindered if hydrocarbons are volatilized in the amine regenerator. Paper ID:105





Lean/Rich Heat Exchanger The rich solvent is preheated before entering the stripper. Because the lean amine exiting the reboiler must be cooled before entering the absorber, there is an opportunity to exchange heat from the lean to the rich stream, thereby reducing the heat load on the re-boiler. This is usually done in a shell and tube lean/rich heat exchanger with the rich solvent passed through the tubes, which are usually made of stainless steel. A recommended maximum velocity to minimize corrosion in the tubes is 3 or 3.5 feet/sec.

Regenerator Like the absorber, the stripper is either a tray or packed column with approximately 20 trays or the equivalent height in packing. To minimize amine vaporization loss, there may be a water wash section at the top of the column with an additional four to six trays (1). The preheated rich amine enters near the top of the column and flows down countercurrent to a gas stream of steam, H2S, and C02. The steam is generated in the re-boiler, lowering the partial pressure of H2S and C02 in the gas stream, enhancing driving force of the acid gases from the amine solution. The overhead gas passed through a condenser to recover water and the small amount of amine that is vaporized in the regenerator. The overhead condenser, the re-boiler tube bundle, and the upper third of the stripping column shell are all susceptible to high corrosion rates, and may need to be manufactured out of stainless steel (4). Thermal degradation, which can contribute to corrosion, can be minimized by designing the re-boiler to use a low temperature heating medium such as low pressure steam. The re-boiler heat duty includes 1) the sensible heat required to raise the temperatures of the rich amine feed, the reflux, and the makeup water to the temperature of the re-boiler, 2) the heat of reaction to break chemical bonds between the acid gas molecules and the amine, and 3) the heat of vaporization of water to produce a stripping vapor of steam. The ratio moles of steam to moles of acid gas in the overhead gas upstream of the condenser, called the reflux ratio, commonly ranges from 1.5:1 to 4:1, depending upon the required degree of regeneration.

Filtration A filtration scheme of mechanical and activated carbon filters is important in maintaining good solution control. Mechanical filters such as, cartridge filters or precoat filters remove particulate material while call filters remove chemical contaminants such as entrained hydrocarbons and surface-active compounds.

Paper ID:105





Filters are located in the rich line in some plants, and in the line in others. One manufacturer recommends filters in both rich and lean lines (5). Locating the filters in the rich line upstream of the lean rich heat exchanger will protect both the heat exchanger and the stripper from plugging, and reduce the erosion/corrosion rate in the heat exchanger. The carbon filter will protect the sulfur plant from hydrocarbon contaminate and reduce the tendency of the amine solution in the stripper to foam. However because the amine solution is heavily loaded with acid gas, drops in pressure enable acid gas to flash from the solvent, causing gas pockets to form in filter resulting in reduced or completely blocked flow (6). In terms of safety for the workers who dismantle, inspect and clean out the filters, it is far more hazardous to locate the filters in the rich line than in the lea line. In many plants, it is specifically for this safety reason that the filters are placed in the lean line. Regardless of the line in which the filters are located, the mechanical filter should be positioned upstream of the carbon filter. In the absence of a mechanical filter, the carbon filter will remove both partic matter and chemical contaminants. This is, however, a costly way to operate because the carbon may plug up with solid material long before its chemic capacity is exhausted, requiring frequent change outs of activated carbon. A 10 to 20 micron mechanical filter should be adequate for particulate removal. If cotton filters are used, the cotton should be virgin cot ton rather than recycled. Recycled cottons may contain fibers with coatings which may be the source of amine solution foaming problems. Circulation rates through mechanical filters range from 5% of the circulating system to full fl depending on the degree of contamination. Recommendations for flow t carbon filters range from less than I percent to 5 to 10 percent (7,8,6) and some units have been built with full flow (5). The life of a carbon filter will vary depending on the level of contaminants and the flow rate of the amine through the bed. A typical life may be 4 to 6 months, although in some cases beds have lasted for many months longer than that. In determining when a carbon bed should be changed following criteria can be used as a guide: 1) a high pressure drop across the bed, caused by solids plugging the voids; 2) a color comparison between a sample taken from the outlet of the filter and a plant sample run through fresh carbon in the lab. Active carbon will remove color; 3) an increase in foaming tendency in the plant, or the start of a foaming problem.

Amine Reclaimer Monoethanolamine solutions are purified by semi-continuous distillation in a reclaimer as part of the gas sweetening process (Figure 4). At the beginning of the reclaiming cycle, the reclaimer is Paper ID:105





filled with lean amine solution. During the filling, a strong base such as sodium carbonate (Na2CO3) or sodium hydroxide (NAOH) is added to the reclaimer to neutralize the stable amine salts present in solution. Heat stable salts are reaction products of the amine with strong acids such as formic acid, acetic and sulfuric acid. The amine cannot be released from these strong acids under the conditions in the regenerator; however, with the addition of a stronger base than the amine, the amine is recovered. Heat is then added to the kettle and water vapor and MEA are distilled off the top, leaving the contaminants in the bottoms. A slipstream of I to 3 percent of the lean amine circulation continuously fed to the reclaimer until the liquid temperature in the reclaimer, which rises as the contaminants accumulate, reaches 300F. The operation is then stopped and the reclaimer is drained, terminating the cycle. The 300F temperature limit is set to minimize thermal degradation of the amine. Typical contaminants which are removed from the MEA solution by the reclaimer are the degradation products, 1-(2-hydroxyethyl)imidazolidone-2 and N-(2hydroxyethyl)ethylenediamine, and nonvolatiles such as inorganic ions, iron sulfide, high boiling hydrocarbons, and heat stable salts. Diethanolamine has a higher boiling temperature than monoethanolamines, requiring other methods of reclaiming such as vacuum distillation in order to prevent thermal degradation of the amine. Moreover, diethanolamine has a slow degradation rate. Consequently, in most cases it is not practical, economical, or necessary to reclaim DEA solutions. Solution purification is maintained by mechanical and carbon filtration, and by caustic or soda ash addition to the system to neutralize the heat stable amine salts

3. Operating Difficulties. Amine gas sweetening plants can experience operating difficulties including foaming, failure to meet sweet gas specification, high solvent losses, corrosion, fouling of equipment, and contamination of the amine solution. Often one operating difficulty is the cause of another. Not all plants experience the same problems to the same degree, and what may be a continual problem in one plant may occur only rarely in another. Foaming Pure aqueous amine solutions do not foam. It is only in the presence of contaminants such as condensed hydrocarbons, small suspended particulate matter, or other surfaceactive agents such as some pipeline corrosion inhibitors or compressor oils, that a foaming problem may develop. Foaming usually occurs in the absorber or the stripping tower, and is accompanied by a sudden noticeable increase in the differential pressure across the column. Other indications of a foaming condition may be a high solvent carryover, a drop in liquid levels, and the detection of off-specification gas. An immediate method to control a foaming problem is the addition of an antifoam at a location just upstream of the foam. Effective foam inhibitors for amine sweetening systems are silicone antifoams and polyalkylene glycols. Paper ID:105





Also widely used are high-boiling alcohols such as oleyl aIcohol and octylphenoxyethanol (1). It is advisable to test the antifoam on a plant sample in the laboratory before applying it in the field to verify that it will break the foam. In the event that one antifoam is ineffective, switching to another antifoam may solve the problem. The silicone antifoams have proven to be quick and effective in controlling foaming problems in the gas treating industry. When using a silicone antifoam, the antifoam should be added downstream of the carbon filters because carbon filters will adsorb the silicone. Care should be exercised with respect to the amount of silicone antifoam added to a system. The silicone antifoams should be used only in small quantities, as recommended by the manufacturer. It is important to be aware that silicone antifoams used in excessive quantities have the potential to promote the formation of foam. The use of an antifoam may only be a temporary solution to a continuing problem. The objective in controlling foaming should be to minimize the level of contaminants in the amine solution. Of critical importance is the prevention of entrained contaminants in the feed gas from entering the amine system. The inlet separator, equipped with a demister pad and possibly filters, is instrumental in trapping most contaminants, and should be monitored to insure that it is operating efficiently and not being overloaded. Mechanical and carbon filters are necessary in maintaining a clean solution. In order to prevent hydrocarbons from condensing in the absorber, the lean amine feed temperature should be held between 10'F and 20'F above the temperature of the feed gas.

Failure to Meet Gas Specification Difficult in meeting the sweet gas specification may be the result of poor contact between the gas and the amine solvent, which may in turn be caused by foaming or mechanical problems in the contacting equipment. In the case of foaming, the gas remains trapped in bubbles, unable to contact the rest of the solvent, resulting in poor mass transfer of acid gas from the gas to the amine solution. In terms of mechanical damage, if trays are broken or have fallen, there may not be enough contact zones (trays) for adequate sweetening. If the trays are plugged, there is less contact between the gas and liquid on each tray, resulting in poorer sweetening. Other explanations for off-specification gas may be related to the amine solution: the circulation rate may be too low, the amine concentration too low, the lean solution temperature may be too high, or the acid gas loading in the lean solution may be too high. Monoethanolamine systems usually run with solution concentrations between 10 and 20 weight percent MEA, and a lean loading of 0.1 moles acid gas/mole of MEA. Diethanolamine systems are between 20 and 30 weight percent DEA, with lean loadings of 0.02 to 0.05 moles acid gas/mole DEA. In order to reach these lean loadings, regeneration resulting in a steam-to-acid gas ratio ranging from 1:1 to 3:1 (moles steam: moles acid gas) in the stripper overhead gas is usually required (1). In some cases, Paper ID:105





even higher ratios may be necessary to bring the loading down, as in low-pressure treating applications. One way to estimate the overhead steam-to-acid gas ratio, knowing the stripper overhead temperature and pressure, is to use steam table data and Raoult's law: PPH2 0 = x H2O psat where: PPH20 = partial pressure of water in the overhead gas; XH20 = mole fraction of water in the amine solvent; psat = vapor pressure of pure water at the temperature of the overhead gas. Approximating the overhead gas as an ideal gas containing water, H2S and C02, the partial pressure of the acid gases can be obtained by subtracting the partial pressure of water, calculated from Raoult's law, from the stripper overhead pressure: PPacid gas = Poverhead – PPH2O The ratio of water partial pressure to acid gas partial pressure is equal to the mole ratio of steam to acid gas. As an example calculation of the steam-to-acid gas ratio, a stripper with an overhead temperature and pressure of 200'F and 20 psia, carrying a 27 weight percent (6 mole percent) DEA solvent, has a corresponding water vapor pressure of 11.5 psia as obtained from the steam tables. From Raoult's law, the partial pressure of water is 10.8 psia: PPH2 0 = (0.94) (11.5) = 10.8 psia The partial pressure of acid gas would be 20 psia less 10.3 psia or 9.19 psia, and the overhead steamto-acid gas ratio would be 1.2 moles steam/mole acid gas (10.8 -t 9.19). Monitoring the overhead pressure and temperature, and thereby monitoring the overhead steam-to-acid gas ratio, is one method that can be used to control heat input to the reboiler to maintain specification gas.

Solvent Losses Amine losses are largely through entrainment, caused by foaming or excessive gas velocities, and by leakage due to spills or corrosion. In MEA units the reclaimer bottoms disposal significantly adds to the makeup requirement. On a much smaller scale are vaporization losses from the absorber, the overhead condenser, and the flash tank, and degradation losses by chemical and thermal degradation.

Corrosion Corrosion is a problem experienced by many alkanolamine gas sweetening plants. When loaded with C02 and H2S, aqueous amine solutions can become corrosive to carbon steel. Corrosion rates are increased by high amine concentration, high acid gas loading, high temperatures, degradation products, and foaming. Also corrosive are acid gases flashed from solution. Monoethanolamine is more reactive than diethanolamine and similarly more corrosive. As a result, the concentration of MEA is restricted to 10 to 20 weight percent, while DEA strengths range from 20 to 30 weight percent. Rich solution loadings are normally limited to the range of 0.25 to 0.45 moles acid gas/mole MEA, while in DEA systems loadings may range from 0.5 to 0.6 moles acid gas/mole DEA. The corrosiveness of a loaded amine solution is strongly Paper ID:105





influenced by the relative proportion Of C02 to H2S in the feed gas. C02 is more corrosive to carbon steel than is H2S in aqueous systems. Thus, for gases containing a higher ratio Of C02 to H2S, the rich acid gas loading should be maintained at the lower end of the recommended loading range. In cases where the feed gas is predominantly H2S, loadings at the higher end of the loading range may be acceptable. In terms of design, a number of measures can be taken to minimize corrosion. Solution velocities should not exceed 3 or 3.5 ft/sec (1,2,3). The rich solution should be on the tube side of the lean/rich heat exchanger, and pressure should be maintained on the exchanger to prevent acid gases from flashing, creating an erosion/corrosion cycle. A low temperature heating medium should be used in the reboiler, thereby preventing accelerated corrosion rates and thermal degradation of the amine. All equipment should be stress relieved. There are certain areas of amine sweetening plants which are more susceptible to corrosion than others, and, as a result, are often constructed of corrosion-resistant materials such as Type 304 stainless steel. These areas include 1) the lean/rich heat exchanger tube bundle, 2) the reboiler tube bundle, 3) the stripping column, particularly the upper section and overhead gas line, 4) the reflux condenser, and 5) the rich solvent let-down valve and subsequent piping to the stripper.

Fig.1 Simplified Amine Gas Sweetening Process Flow Diagram

Paper ID:105





Paper ID:105





Fig.2 Natural Gas Sweetening Plant

Fig.3 Tray Tower Adsorber

Paper ID:105





Fig.4 Reclaimer Flow Diagram

Paper ID:105





4.Product Stewardship When considering the use of any Dow products in a particular application, you should review Dow’s latest Material Safety Data Sheets and ensure that the use you intend can be accomplished safely. For material Safety Data Sheets and other product safety information, contact your Dow representative or the nearest sales office at the numbers listed below. Before handling any other products mentioned in the text, you should obtain available product safety information and take necessary steps to ensure safety of use. No chemical should be used as or in a food, drug, medical devise, or cosmetic, or in a product or process in which it may contact a food, drug, medical device, or cosmetic until the user has determined the suitability and legality of the use. Since government regulations and use conditions are subject to change, it is the user’s responsibility to determine that this information is appropriate and suitable under current, applicable laws and regulations. Dow requests that the customer read, understand, and comply with the information contained in this publication and the current Material Safety Data Sheet(s). The customer should furnish the information in this publication to its employees, contractors, and customers, or any other users of the product(s), and request that they do the same.

5.CONCLUSION We have studied about the gas sweetening process in which to obtain the sweet gas after removing the H2S , CO2. There is also we used the different basic heating,cooling for ton accurate results in the processing chamber for the good product. There is important to know 2-5% gas may be remaining in the sweet gas which is removed in the refinery further process.

6.REFERENCES 1. Kohl, A. L. and F. C. Riesenfeld, Gas Purification, 3rd Ed., Gulf Publishing Co., Houston, TX t'1979)02. Campbell, J. M., Gas Conditioning and Processing, Vol. 2, Campbell Petroleum Series,Form@an,@Oklahoma @19/9). 3. Ballard, D., "Cut Energy Costs for Arnine Units", Proceedings of 59th GPA convention. 4. Butwell, K. F., D. J. Kubek and P. W. Sigmund, "Alkanolamine Treating", Hydrocarbon Processing, March (1982). 5. Perry Engineering Corporation, "Activated-Carbon Filter", Brochure. 6. Gas Conditioning Fact Book, Dow Chemical Co., Midland, Michigan, (196@. 7. Scheirman, W. L., "Filter DEA Treating Solution", Hydrocarbon Processing August (1973). 8. Calgon Corporation, "Purification of Amines with Granular Activated Carbon", Brochure. Paper ID:105





IMPROVING HEAVY OIL RECOVERY PERFORMANCE Akash Rana1, Ravi Baliyan2 , Rahul Kumar3, Manoj Kumar4 1,2,3

Department Of Petroleum Technology (Bhagwant University Ajmer, India) Department Of Petroleum Technology (Bhagwant University Ajmer, India)

4

ABSTRACT Primary production technic do not recover an adequate amount of fraction of the HCS initially in place (HIIP). Experimental data has shown that, at the point when the natural energy resources and gases in a heavy oil reservoir is nearly or altogether decaying, the recovery factor or fraction does not increased about 20%. Some heavy oil reservoirs do not produce at all by natural drive mechanisms and technology. This often needed adopting a production enhancment strategy to augmented recovery. Prior to implementing an improved oil recovery technic (either secondary or tertiary) in the resrvoir field, it is very important to investigate and evaluate its potential for successful operation. Reservoir simulation is an integral part of a continuous implementing and improving process used to gain insight into the feasibility and applicability of improved oil recovery technic. In this project, GEM compositional reservoir simulator has been used to study the efficiencies and effectivness of different improved oil recovery strategies, ranging from waterflooding to solvent injection. The drainage volume investigated and evaluated is a hypothetical box-shaped heavy oil reservoir composed of three different permeable layers.

KEYWORDS Simulator Heavy Oil, Ior, Reservoir, Drainage Area 1.INTRODUCTION Projection of the oil import and export by the Organization of the Petro-leum crude oil demanding (OPEC) will reach 111.1 million barrelsper day by 2040, with a 23.1% increased compared to current data[1]. Oftenly the consumption of conventional light oils has resulted in depletitionof reserves of these resources of oil and gas. As fossil fuel will remain to be the major energy source for the upcoming years, there is a need to exploit alternative fossil fuel resources of oil and gas. Therefore,continuous research and efforts have been devoted to the effective and improved production of heavy and much-heavy (i.e., natural bitumen or oil sandsand shale) oils from reservoirs, which account for ca.70% of total world oil reserves[2,3].Compared to the production of conventional oils, heavy oil recovery is more problem and Paper ID:106





challenging due to the inherent characterstics, suchas high level viscosity or even immovable, high carbon/hydrogen (C/H)ratios proportions and high heteroatom contents [4,5]. Complex formation and fraction con-figuration could also add additional problem in the oil production.Not withstanding, the key mechanism and technic for effective recovery of oil and gas has been investigated to be the oil viscosity decreases and the resulting improved oil movability. With this in mind, according to the temperature changes-viscosity correlation affected, several external energy sources are provide to heat up the heavy oils, which provide easiest their flow and extraction from the underground depth. customily, oil production is divided into three major steps: primary, secondary and tertiary recoveries. In the production of heavy oils and gases , primary and secondary recoveries are defined by cold production and water flooding,water injection as in the cases of oil sands, heavy oils and Continental Shelf. These recovery methods are however either limited to relatively shallow reservoirs or only effective eavaluated to lighter heavy oils [6]. To analyse a high recovery factor, tertiary recovery, or more generally known as enhanced oil recovery (EOR), is rather critical and essentially to extract much oils leave behind by the primary and sec-ondaryrecovery.Until recently, a various of EOR techniques have been used and well developed, which can be easily distinguishes into thermal,chemical and gas injection [6,7]. Among these methodsandtecniques, thermal injection is identified as an important one with high recovery factors up to 70% of the original oil in place (OOIP). Generally thermal recovery consists steam-assisted gravity drainage mechanism, cyclic steam stimulation and in-situ combustion process. However, these successful methods are still challenged both economically as well as environmentally because of high expense of heat supply along with maximum carbon dioxide (CO2) emission and expensively post-treatment and maintenance [8]. Chemical and gas injection are also, to some extent, commercially viable, especially the CO2 flood-ing, which is gaining more significant interest recently due to its capabilities for CO2 seggregation. Unfortunately, these methods are mostly possesed from poor movability control and severe viscous fin-gering, resulting in inadequates sweep and displaced efficien-cies. Due to the high interfacial tension and pressure (IFT) and different viscosity contrast between displacing fluid and oil, particularly properties of bitumen or oil sands, these methods are usually ineffec-tive and far from commercial purposes [4]. The above-mentioned problem thus have become the driving pressures behind the needed for a good recovery solution and results.Simultaneous recovery and upgrading of heavy oils in reservoirs using thermal recovery along with injection of active catalystsand agents are giving as a promising technology that comprises the advantages of both thermal recovery and in-situ catalysis agents [9–11]. increasing ideas are being devoted to search the feasable and reliable of apply-ing active chemical agent for in-situ heavy oil recovery, metallic nano small particle helped recovery techniques [12]. The application of nanotechnology with improved heavy oil recovery could provide a good ideas and have the potential to obtain higher recovery efficiency and good recovery factor

2.HEAVY OIL AND EXTRA -HEAVY OILS 2.1) Definition Heavy or more heavy oils are highly viscous containing charaterstics that can not easily allow to flow to production wells at simple reservoir situation.‘‘Heavy” is defined because the density and volume or Paper ID:106





specific gravity is much than that of lighter oils (i.e., conventional oils). It is large scale accepted to adopt the specific gravity and viscosity as two siginificant criteria to classify light, heavy and extra-heavy oils, which are examples in Table 1 [2,4,5]. Specific gravity is measured on the basis of American Petroleum Institute in units called API degrees (°API); the lower the number of API degrees, the higher the specific gravity of the oil. Viscosity is measured in centipoises (cP) that represents the oil’s resistance to flow through pipes; the higher the value, the highe the viscosity factor.

2.2)RECOVERY TECHNOLOGIES Cold production and surface drilling are low-risk primary recovery method for heavy oils, but they are to the well depth of reservoirs and relatively light quality inside [13,14]. Water flood-ing, as a famous secondary recovery method, is also not useable due to the high viscosity changes between water and oils, directing to low swept efficiency [8]. OR is necesseraly to be following. It is useful that oil vis-cosity is nearly composed with temperature. Oil viscosity reduces with the increment of temperature. Accordingly, outer thermal sources can be used to heat the oil and decreases the viscosity, which are generally known as steam-based thermal injection. In order to enhace the moved efficiency, recovery method using chemicals and gases have also been successfully used. All these technologies including the hybrid methods ones illustrated in the next segment .To obtain a high recovery factor.

3.ENHANCE OIL RECOVERY METHODS 3.1)CYLIC STEAM STIMULATIONS(CSS) Cyclic steam stimulation (also known as huff n' puff) was accidentally discovered in Eastern Venezuela in 1959. In this process, steam is injected under maximum pressure and temperature. The high injection pressure dilutes or fractures the reservoir rock and the maximum temperature asists to decrease oil viscosity. The cyclical injection takes place in three level: injection time, soaking time, production time. At the starting, oil is produced at maximum rates, which generally start to fastly reduces. The cycle can be revised various times, whilst still economically viable. This process has as main benefits the fast return during early production. However oil recovery can be as low as 10 or 20% of the original oil volume [7]. This process can use horizontal and vertical wells [8], depending on the reservoir layes sizes. The cyclical steam injection has been used in various oil fields with success, like in Alberta, Canada, where oil viscosity is about 100.000 cp. In heavy oil fields of Venezuela and Brazil this thermal recovery process has also been applied with success. In California, it is applied as a first stage before continuous steam injection. Recently, this technology has also been used in horizontal wells. Dominant techniques in heat transfer rate are: conduction and forced convection methods during injection, conduction and a minimum convection impacts during the soaking time , and counter current of convection conduction during the production time. It is important to highlight that in cyclical steam injection the reservoir can contain such viscous oil that can be considered solid. The steam role is "to dissolve that solid" and to permit it to flow through the Paper ID:106





reservoir [9]. One of the operational stages in that process is related to the steam required to maximize the reservoir temperature to a certain level, taking into account the heat losses. The soaking time after steam injection can changes from a few days to weeks. There are various ideas regarding optimization of the soaking time. In various cases, mechanical and operational considerations will favour a short closing time in the steam injection. The operated well is then put in production and should produce by natural lifting mechanism, with its own reservoir energy, during days. This is desirable, because the imposed bottom well pressure tends to prevent water flashing at high temperatures. In the following time, the well will have to be pumped the high pressures. In various cases, sand control becomes the main operational challenges. Frequently, oil rate falls in subsequent cycles. If the cyclical injection is to be followed by a continuous injection - as investigate in recent times - it will be desirable to determine the number of cycles that will increased the oil recovery for the cyclical injection and steam injection. Sometimes maximum cumulative oil can be achieved, with 8 or 9 cycles, but the response for a cyclic steam injection varies conditionally with the reservoir properties. Fractured reservoirs identified show the importance of capillary imbibition on the process. Fracture frequency has very minimal effect in the process. As an example, for highly tilted and thick California reservoirs, gravity drainage is dominant and many cycles are possible, since low viscous, hot oil continue to flow down in the direction of the producing well. unidentified of the reservoir type, the cyclic injection becomes usually lower efficient with increment number of cycles. This fact is evident in several production statistics and analysis. The average and maximum rates as long as total oil recovery decrease in the last cycles [10].

3.2)POLYMER FLOODING When operating polymer flooding, a polymer with high moleculer density and much viscosity is used into the water phase to less the movability of water and thus improve the swept efficiency [55]. The ideas of mobility control lays the base of polymer flooding process [56]. Generally, mobility ratio proportions is defined as the changability of displacing phase (i.e., water in waterflooding) divided by the degree of freedom of the swept phase (i.e., oil).A less value of mobility ratio (61) is favored because that mean the swept oil has a maximum ability to displace than the moving water. Therefore, the concepts that water flows through more permeable channels and bypasses the viscous oils is significantly decreased, resulting in maximize volumetric sweep efficiency

Paper ID:106





. FIG.1 3.3)CHEMICAL INJECTION The injection of several chemicals, usually as less concentrate solutions, have been used to aid changability and the decreases in surface tension. Injection of alkaline or caustic solutions into reservoirs with oil that have organic acids naturally found in the oil will result in the production of soap that may reduced the interfacial tension suficient to maximum production.[12][13] Injection of a less concentrate solution of a water-soluble polymer to maximize the viscosity of the injected water can the volume of oil recovered in some formations. light solutions of chemicals such as petroleum sulfonates or biosurfactants such as rhamnolipids may be injected to less the interfacial tension or capillary pressure that imposed oil droplets from moving through a reservoir. mainly formulations of oil, water and chemicals microemulsions, can be particularly results in this. Application of these processes is generally limited by the cost of the chemicals and their absorbed and decreased into the rock of the oil composing formation. In all of these rules the surfacants are injected into various wells and the production occurs in other nearby wells. Paper ID:106 NCMMPPT 24Th-25 Th April - 2017




FIG.2 3.4)THERMAL INJECTION In this process, several techniques are used to heat the crude oil in the formation to decrease its viscosity and/or vaporize part of the oil and thus reduces the mobility proportions ratios. The maximize heat decreases the surface tension and maximize the permeability of the oil. The heated oil may also vaporize and then condense and cool forming significant oil. process include cyclic steam injection, steam flooding and firing process. These rules enhance the sweep efficiency and the swept efficiency. Steam injection has been used commercially since the 1960s in California fields.[10] In 2011 solar thermal enhanced oil recovery projects were begins in California and Oman, this process is similar to thermal EOR but applying a solar array to produce the steam.

3.5)IN-SITU COMBUSTION (ISC) This method was first experimented in Pennsylvania in the early 1950s. Over 200 in situ combustion field tests and commercial operations have been performed out overworld, but only a less are still in operation. The in situ Combustion process start with the injection of heated air into the oil reservoir. Heat is produced as a result of oil oxidation, increment the temperature. Continuing the Oxidation, the temperature eventually increased the so-called "ignition point", when the combustion is takes place. At Paper ID:106





that point it is essential to inject cold air to gives continuity to the method. The combustion front moves any trapped reservoir fluids (including injected gases and those resulting from combustion), up to the producing well. In this method care should be taken with variables such as combustion temperature and gravitational seperation of the gases that leads to early combustion zone breakout in the producers., carbonate rocks are contains the most of heavy crude oils. Running in-situ combustion method in carbonate reservoirs may be risky due to the probability of transformation of the rock and production of carbon dioxide at high temperatures. While decomposition occurs in dolomite or limestone, the rock will change in to a powder like material that will definitely cause plugging. The effect of fractures could be sometimes very special way. Since fractures may lead to oxygen breakthrough and failed of the process. Besides all these ideas economy and instrumentation need are other considerations that should come in to account. Usually, long term research and studies are conducted before selecting a reservoir for this method. One of the most important parts of these studies is the feasibility study

FIG.3

Paper ID:106





CONCLUSION Thermal oil recovery techniques are used specially in heavy oils or bituminous sands with the purpose of decreasing oil viscosity in the reservoir, maximize its degree of freedom and gives better swept volume to the producing wells. The choosed techniques always on the basis of reservoir properties, reservoir drilling fluids, volume and area and knowledge from similar reservoirs. Due to its difficulty, numerical analyses, reservoir modeling and profitability analyses are always required in order to estimate which methods is more effective inreducing the volume of injected fluids. Heavy oil production beneficialy by steam injection is a performing operation. Steam injection parameters are being developed for reservoirs that were take account vast condition for steam injection only a few time ago. This has been possible because of latest in horizontal well technology, and powerful computers managment. Steam injection is veru expensive, and careful design and heat management are the keys to economic operation. In situ combustion is a special method that may be able to applying sometimes where steam is not applicable (e.g. thin and deep formations, bottom water, etc.).

REFERENCES: 1.Briggs PJ, Beck DL, Black CJJ, Bissell R (1992) Heavy Oil from Fractured Carbonate Reservoirs. SPE Reservoir Engineering 7: 173-179. 2.Clark PD, Hyne JB. Chemistry of organosulphur compound types occurring inheavy oil sands: 3. Reaction of thiophene and tetrahydrothiophenewithvanadyl and nickel salts. Fuel 1984;63(12):1649–54.900 K. Guo et al. / Fuel 185 (2016) 886–902 3.Farouq A, Meldau PB (1983) Improved oil recovery. Chapter VII Interstate Oil Compact Commission Oklahoma City Oklahoma. 4.Nasr TN, Ayodele OR (2005) Thermal techniques for the recovery of heavy oil and bitumen. SPE International Improved Oil Conference in Asia Pacific held in Kuala Lumpur Malaysia 5-6 December technical paper SPE 97488. 5.Tabasinejad F, Karrat R, Vossoughi S (2006) Feasibility Study of In-Situ Combustion in Naturally Fractured Heavy Oil Reservoirs. SPE 103969 6.Sedaee Sola B, Rashidi F, Amir-Kabir (2006) Application of the SAGD to an Iranian Carbonate Heavy-Oil Reservoir. SPE 100533. 7.Dreher KD, Kenyon DE (1986) Heat Flow during Steam Injection into a Fractured Carbonate Reservoir. Paper SPE 14902 presented at the SPE/DOE Symposium on Enhanced Oil Recovery Tulsa April 20-23 8. Batycky JP, Leaute RP, Dawe BA (1997) A Mechanistic Model of Cyclic Steam Stimulation. Paper SPE 37550 Proc Thermal Operations & Heavy Oil Symposium Bakersfield CA 323-336.

Paper ID:106





Paper ID:106





Challenges During Drilling Operations In Coalbed Methane (CBM) Wells Ravi Baliyan1 , Akash Rana2 , Rishabh Chand3 1,2,3

Department Of Petroleum Engineering, Bhagwant University, Ajmer- INDIA

Abstract: This paper summarizes a study on challenges during drilling operations in CBM wells for the analysis of basic problems that arises during drilling operations in coalbed methane wells, includes the various technical and non technical challenges. There were varieties of challenges faced by drilling engineers during drilling operations in such type of an Unconventional energy resource formation. Technical challenges comprises of Multilateral wells drilling, Cementing Failures, Horizontal well drilling, Lost Circulation damage, presence of corrosive gases (CO2 or H2S) in CBM Reservoirs, While Non Technical challenges includes site selection for drilling and transportation of disassembled and huge drilling rig components. Thus the basic aim for this paper is that how to evaluate several challenges in any unconventional energy bearing reservoir and also distinguishes between the technical and non technical challenges on the basis of their work functions, properties, parameters, criteria, locations etc. Keywords: Multilateral & Horizontal Wells Drilling, Lost Circulation, Fishing, sloughing shale, corrosive gases, site selection for drilling.

INTRODUCTION Increasing global energy demand, at a time when more assets are maturing and declining, is challenging the industry as never before. In response, technology is increasing the ability to discover and access hydrocarbon resources once thought Paper ID:106





to be inaccessible or unrecoverable. Technology is also enabling mature fields to be a significant source of production for many more years than initially planned. What follow are key industry challenges where our technology, experience, and commitment to service excellence are helping meet the demands of the future. Certain challenges are very precisely and accurately descriptive in this paper and allow us to understand the several challenges in drilling industry which is faced by drilling engineers. THECHNICAL CHALLENGES  Multilateral Wells Drilling: Drilling multilateral wells for exploration of methane gas is one of the most effective way for its production from the cleats of coal, generally carries several operation. But also the fact that in India the most coal seam blocks or formation have a sufficiently enough amount of methane gas, which is processed only through the vertical drilling operation, hence no need to drill the multilateral wells as it poses a great challenge to drill these types of wells.

 CEMENTING FAILURES:

Paper ID:106





Cement and casing failures and sand production problems while drilling lead to reduced well performance and the loss of many production and injection wells each year. A variety of insulated and corrosion resistant cement systems that are tailored to endure high steam temperatures and low pH and still provide effective zonal isolation for longer than conventional cements. These better engineered thermal cementing programs can help improve casing and cement design, resulting in longer lasting wells. Indeed, the life of the well is extended 5 to 10 years by the reduction in cement and casing failures. It is also critical that the chosen cement sealant for a heavy oil well is designed efficiently for both placement and optimized hydraulic modeling, and also for the life of the well.  HORIZONTAL WELL DRILLING: Drilling horizontal wells in CBM reservoir is the technique which involves hydraulic fracturing, as we know hydraulic fracturing is done to enhance the production, but sometimes in coal beds this hydraulic fracturing causes a severe challenge during drilling, as when fracking occurs the surrounding coal seam beds form,ation zone displaced and as a result of it collapsing of zone occurs. So, it also poses a challenge in CBM wells during drilling.

Paper ID:106





 LOST CIRCULATION: If a very porous, cavernous, or highly fractured zone is encountered while drilling, an excessive amount of drilling mud is lost to that zone during lost circulation. The zone is called a thief or lost circulation zone. A pill mixed with the drilling mud and pumped down the well to clog up the lost circulation zone. Lost circulation additives are fibers, flakes, granular masses, or mixtures. They include ground pecan hulls, redwood and cedar shavings, hay, pig hairs, shredded leather, mica flakes, laminated plastic, cellophane, sugar cane hulls, ground coal, and ground tires. After the lost circulation zone has been drilled, it can be isolated by running and cementing a string of protection casing into the well.  FISHING: A common drilling challenge is that something breaks in or falls down the well during drilling. For example, the drill string twists off and falls to the bottom. A cone can break off the tricone bit, or a tool such as a pipe wrench can fall from the rig floor into the well. This is called a fish or junk and cannot be drilled with a normal drill bit. Drilling is suspended and a special tool called a Fishing tool is leased from a service company to grapple for the fish in a process called Fishing.  SLOUGHING SHALE: Sloughing shale is soft shale along the wellbore that adsorbs water from the driiling mud. It expands out into the well and falls to the bottom of the well in large balls that are not easily removed by the circulating drilling mud.  CORROSIVE GASES: In some areas, corrosive gases such as CO2 and H2S can flow out of the rocks and into the well as it is being drilled. These gases can cause hydrogen sulfide embrittlement and weaken the steel drill string. To prevent corrosion, a drill string made of more resistant and expensive steel can be used, and chemicals can be added to the drilling mud. As a resultit also acts as a challenge while drilling.

Paper ID:106





NON-THECHNICAL CHALLENGES  SITE SELECTION FOR DRILLING: When surveying the site which contains a sufficient quantity of CBM gas in the Reservoir formation zone, then it must ensure that the location of site is far away from city or villages. If the site situated near the villages then it may sometimes lead to a great protest against the drilling operation, as the villager’s demand is that the land where the drilling operation is carried out is the part of their own shelters and would cause a great impact on their livelihoods and one more reason behind their protest and disagreement is that the operating drilling services would cause a great vibration leads to noise pollution, which is quite unacceptable for them to approved. Thus it is also becomes one of the major non technical drilling challenge in CBM wells.  LOGISTICS/TRANSPORTATION OF DRILLING RIG SETUP: After the site selection for drilling, it’s time to setup a drilling rig for start the drilling operation. As the drilling rig assembly is transported as applied logistics chain which brings to the site of location, faces variety of problems and challenges during transportation through roads.

CONCLUSION There are number of technical and non technical challenges associated with unconventional hydrocarbon extraction however, given the extensive experience of the oil and gas industry, none of these are seen as insurmountable. CBM Wells are under pressured and methane does not flow naturally, Which contrasts with the situation found in conventional gas wells. Therefore, it should be easier to deal with the abandonment of unconventional oil and gas wells, provided regulations are adhered to and monitoring is implemented.

Paper ID:106





REFERENCES

    

http://www.majordrilling.com http://en.wikipedia.org http://www.petrowiki.org http://www.rigzone.com http://www.halliburton.com

Paper ID:106





Shale Gas An Unconventional Resources Of Energy 1

Rahul Kumar Singh, Manoj Kumar2 , Karan Singh3

1,3

Department of Petroleum Engineering, Bhagwant University Ajmer-INDIA 2

Department of CSE, Bhagwant University Ajmer-INDIA

Abstract: This paper summarizes the brief description on the shale gas an unconventional resources of energy which shows us that on modern society, the oil and gas industry needs to be more pessimistic on an alternative unconventional energy source for energy as one day is absolutely come when manmade needs another form of energy for daily use. This paper also presents that how the formation of shale gas occurs in deep inside earth’s reservoir and the geochemical analysis for the perception of the occurrence, composition, and its basic chemical and physical changes which has its primarily most prosperous way for the use in modern in society. Thus the most vulnerable form of the unconventional energy comprises shale gas, gas hydrates, coalbed methane. Keywords: Shale Gas, Sandstone limestone reservoir, Organic and Inorganic carbonate minerals, Kerogen, Geochemical analysis, Residual Gas, Lost Gas.

Introduction: Shale are the most abundant form of sedimentary rock on earth. They serve as the source rocks of hydrocarbon migrating Paper ID:108





Into permeable reservoirs and act as seals for trapping oil and gas in underlying sediments. Until recently, the oil and gas industry generally regarded them as nuisances to be tolerated While drilling to target sandstone limestone reservoirs. But geologists and engineers have begun to view a specific type of shale – organic –shale –with a newfound appreciation. If endowed with the right characteristics, Organic-rich shale have the potential to serve not only as sources of hydrocarbons but also as reservoirs to be produced. Finding and producing gas from shale formations, initially a North American phenomenon, has become a global pursuit for many exploration is the Barnett Shale in Texas. It took 20 years of experimenting before the play was considered economically viable. Two technologiesfracture stimulation and horizontal drilling- were developed and applied at the right time to enable

Unconventional Resources: Organic –rich shale deposits with potential for hydrocarbon production are referred to as both unconventional reservoirs and resource plays. Unconventional gas reservoirs refer to lowto ultralow-permeability sediments that produce mainly dry gas. Reservoirs with permeability greater than 0.1mD are considered conventional, and those with permeability below that cutoff are called unconventional , although there is no scientific basis for such a designation. Paper ID:108





According to a more recent definition, unconventional gas reservoirs are those that can be produced neither at economic flow rates nor in economic volumes unless the well is stimulated by hydraulic fracture treatment or accessed by a horizontal wellbore, multilateral wellbores or some other technique to expose more of the reservoir to the wellbore. This definition includes formations composed of tight gas sands and carbonates, as well as resource plays such as coal and shale. The term resource play refers to sediments that act as both the reservoir and the source for hydrocarbons. Unlike conventional plays, resource plays cover a wide areal extent and are not typically confined to geologic structure

How is shale gas formed: Organic rich shale formed under high level of organic matter and low level of oxygen. Material settles at the bottom of ocean or lakes, in anoxic environment, under pressure and temperature this material turns into kerogen. Continued pressure from burial forces most of the nature gas to migrate from the organic shale into more porous and permeable rock such as sandstone and limestone forming conventional reservoirs. Throughout the process of burial and maturation, kerogen passes through a range of pressure and temperatures. During process of ‘catagenesis’, first liquid petroleum is generated from kerogen. Kerogen passes into ‘dry gas’ as it buried deeper. This occurs during the process of ‘metagenesis’. Paper ID:108





organic materials in sedimentary rocks undergoes numerous compositional changes which are initially dictated by microbial activities and them by the thermal stresses.

Geochemical analysis of shale: Geological analysis is necessary to characterize the shale resources, and maturity.(TOC), gas volume and capacity, thermal maturity, permeability and maturity. TOC of rocks is indirect measurement of resource potential of reservoir rock. Generally TOC reservoir rocks varies between 2% to 10%. TOC above 10 % are immature rocks. Shale contains both inorganic and organic carbon. Inorganic carbon is removed by phosphoric acid wash. Then dried shale sediments are combusted temperature around 1350 degree C in oxygen rich environment. Gas volume in shale is sum of free gas and gas adsorbed on the surface of kerogen. To determine this volume, isotherm experiments are conducted. In isotherm experiments, core from a wellbore kept in canister at reservoir conditions. The volume removed from consider is measured volumetrically. Isotherm experiments gives estimated of adsorbed gas. Free gas is reservoir is estimated using petro physical logging operations (Using porosity and gas saturation). Thermal maturity is measured by ‘vitrinite reflectance’. Measurement excess of 1.5% gives an indication of dry gas generating source rock. A reflectance value below 0.6% is indication of immaturity

Paper ID:108





of kerogen. Unlikely shale reservoirs permeability value in nanodarcies,

Determining total gas content requires measurement of three components: Lost gas, Measured gas, and Residual gas Lost gas is estimated by projecting the first few hours of desorption measurements back to the time at which desorption begins. Desorption process may require two or more months to reach a point where the desorption rate becomes negligible. Become lost-gas volumes cannot be measured directly, careful measurement of sorbet gas and selection of an appropriate mathematical projection are essential in deriving an accurate estimate of lost-gas. Residual gas is not produced from the reservoir, but it is part of the total gas measured in adsorption isotherms. Unlike conventional gas sands or carbonates, which rely on geologic traps to hold the gas in place, shale is both the source and producer of gas. Paper ID:108





Usually, shale must be fractured to produce at economic volumes. Only way for the gas to flow is either though natural fractures in the rock or through fractures created by injecting high rates of fluids and prop pant into the formation under high pressure.

CONCLUSION After reviewing other studies and experiences in oil and gas producing states, as well as our own data, DENR believes that hydraulic fracturing cannot be done safely in North Carolina, even if the proper regulations are in place. This conclusion is based on the following evidence: 1. lack of data regarding long-term health effects of fracking on human health and existing evidence of current health effects; 2. exorbitant water usage and the uncertainty whether the state can meet the water needs of the industry without hurting residents and existing businesses; 3. mounting evidence of drinking water contamination caused by fracking in both groundwater supplies and aquifers; 4. promises of jobs that are limited, short-term, and uncertain; 5. the absence of both an evaluation of consumer protection concerns available for public comment and an assessment of potential environmental justice impacts. Paper ID:108





REFERENCES 1. "U.S. Energy Information Administration". Eia.gov. Retrieved 2013-08-06. 2. Stevens, Paul (August 2012). "The 'Shale Gas Revolution': Developments and Changes". Chatham House. Retrieved 2012-08-15. 3. "New way to tap gas may expand global supplies,". SNytimes.com. Retrieved 2013-08-06. 4. Staff (5 April 2011) World Shale Gas Resources: An Initial Assessment of 14 Regions Outside the United States US Energy Information Administration, Analysis and Projections, Retrieved 26 August 2012 5. ''Statement on U.S.-China shale gas resource initiative". America.gov. 2009-11-17. Retrieved 2013-08-06. 6. Carey, Julie M. (7 December 2012) Surprise Side Effect Of Shale Gas Boom: A Plunge In U.S. Greenhouse Gas Emissions Forbes magazine, Retrieved 21 February 2013 7. David J. C. MacKay and Timothy J. Stone, Potential Greenhouse Gas Emissions Associated with Shale Gas Extraction and Use, 9 Sept. 2013.

Paper ID:108





Paper ID:108





BOP ( BLOW OUT PREVENTER ) Tiwari Shubham Ravindra1, Abhishek Agarwal2, Karan Singh3 1,2,3

Department of Petroleum Engineering, BHAGWANT UNIVERSITY, AJMER, (Rajasthan)

ABSTRACT: Blowout Preventers and choke manifolds are key pieces of drilling rig equipment to prevent the uncontrolled release of potentially hazardous formation fluids to surface. The blowout prevention testing problem is that of testing BOP valves to check if they are functional or not. Several type of testing is done on these valves. This paper deals with the check if the valves are capable of holding pressure. We present a decision model that allows a structured and time saving approach to minimize the number of test sets in order to identify leakage. Recently the BOP terminology has gained prominence and public attention as a result of the blow-out and resulting oil-spill.

INTRODUCTION:  A large valve at the top of a well that may be closed if the drilling crew loses control of formation fluids.  By closing this valve, the drilling crew usually regains control of the reservoir and procedures can then be initiated the mud density until it is possible to open the BOP and retain the pressure control of the formation.  BOPs come in a variety of styles, sizes and pressure ratings. Some can effectively close over an open wellbore, some are designed to seal around tubular components in the well (drillpipe, casing or tubing) and others are fitted with hardened steel shearing surfaces that can actually cut through drillpipe.

Paper ID:109





 Blowout preventers were developed to cope with extreme erratic pressures and uncontrolled flow (formation kick) emanating from a well reservoir during drilling.

 The primary functions of a blowout preventer system are: 1) Confine well fluid to the wellbore 2) Provide means to add fluid to the wellbore 3) Allow controlled volumes of fluid to be withdrawn from the wellbore.

In performing those primary functions, blowout preventer systems are used to:  Regulate and monitor wellbore pressure  Center and hang off the drill string in the wellbore Paper ID:109





 Shut in the well  “Kill” the well

TYPES:  BOP is of two types are as follows:

I.

RAM

II.

Annular

Ram blowout preventer  A ram-type BOP is used a pair of opposing steel plungers, rams. The rams extend toward the center of the wellbore to restrict flow or retract open in order to permit flow. The inner and top faces of the rams are fitted with packers that press against each other, against the wellbore, and around tubing running through the wellbore.  Pipe rams: Pipe rams close around a drill pipe, restricting flow in the annulus between the outside of the drill pipe and the wellbore, but do not obstruct flow within the drill pipe.  Blind rams: Blind rams (also known as sealing rams), which have no openings for tubing, can close off the well when the well does not contain a drill string or other tubing, and seal it.  Shear rams: Shear rams are designed to shear the pipe in the well and seal the wellbore simultaneously. It has steel blades to shear the pipe and seals to seal the annulus after shearing the pipe.

Paper ID:109





 Blind shear rams: Blind shear rams (also known as shear seal rams, or sealing shear rams) are intended to seal a wellbore, even when the bore is occupied by a drill string, by cutting through the drill string as the rams close off the well.

(Fig: Different types of rams. (a) Blind ram (b) Pipe ram and (c) shear ram)

Paper ID:109





Annular blowout preventer  An annular-type blowout preventer can close around the drill string, casing or a non-cylindrical object, such as the Kelly.  Regulations typically require that an annular preventer be able to completely close a wellbore, but annular preventers are generally not as effective as ram preventers in maintaining a seal on an open hole. CONCLUSION This paper finally concluded us about Blowout preventers are used on land wells, offshore rigs, and subsea wells. Land and subsea BOPs are secured to the top of the wellbore, known as the wellhead. BOPs on offshore rigs are mounted below the rig deck. Subsea BOPs are connected to the offshore rig above by a drilling riser that provides a continuous pathway for the drill string and fluids emanating from the wellbore. In effect, a riser extends the wellbore to the rig. Sadly sometimes the BOP doesn't work. REFERNCES  Blowout preventer: Definition from the Schlumberger glossary  Blowout preventer: Definition from the US department of Labor, Occupational Safety & Health Administration (OSHA)  https://www.osha.gov/SLTC/etools/oilandgas/images/bop_stack.jpg Paper ID:109





https://www.osha.gov/SLTC/etools/oilandgas/drilling/wellcontrol.htm l https://web.archive.org/web/20061005223639/http://www.asmenew s.org/archives/backissues/july03/features/703oilwell.html  Photograph of subsea BOP stack linked from Oil states Offshore Products

Paper ID:109





Artificial Lift Methods Selection (Gas lift Valve String Design) Uttam Kumar1, Akash Rana2, Ravi Baliyan3 1,2,3

Department Of Petroleum Engineering, Bhagwant University, Ajmer- INDIA

Abstract: This paper provides information to help the user choose which artificial lift method may be best for a particular gas well. A selection matrix if provided that contains many of the features and limitations of the various artificial lift methods. It may be used for screening the various available methods. Information is provided on feasibility, initial cost, continuing power costs, and other issues for the various possible methods of artificial lift. A tentative selection flow chart and associated discussion is presented that could lead the user to the best method. The methods of possible artificial lift for various gas wells are evaluated. Other possible methods are recognized. Keywords: Sucker Rod Pump, gas lift, electrical submersible pump, hydraulic piston pumping, hydraulic jet pumping, plunger lift, progressive cavity pumping.

INTRODUCTION Artificial lift is a means of overcoming bottom hole pressure so that a well can produce at some desired rate, either by injecting gas into the producing fluid column to reduce its hydrostatic pressure, or using a down hole pump to provide additional lift pressure down hole. We tend to associate artificial lift with mature, depleted fields, where Pavg has declined such that the reservoir can no longer produce under its natural energy. But these methods are also used in younger fields to increase production rates and improve project economics. Paper ID:110





SUCKER-ROD PUMP Beam pumping is the most common artificial lift method. It can be used for a wide range of production rates and operating conditions, and rod pump systems are relatively simple to operate and maintain. However, the volumetric efficiency (capacity) of a rod pump is low. Its initial installation may involve relatively high capital costs. Its application is very limited for deep, inclined and horizontal wells.

GAS LIFT Gas lift involves injecting high-pressure gas from the surface into the producing fluid column through one or more subsurface valves set at predetermined depths There are two main types of gas lift: Continuous gas lift, where gas is injected in a constant, uninterrupted stream. This lowers the overall density of the fluid column and reduces the hydrostatic Paper ID:110





component of the flowing bottom hole pressure. This method is generally applied to wells with high productivity indexes. Intermittent gas lift, which is designed for lower-productivity wells. In this type of gas lift installation, a volume of formation fluid accumulates inside the production tubing. A high-pressure “slug” of gas is then injected below the liquid, physically displacing it to the surface. As soon as the fluid is produced, gas injection is interrupted, and the cycle of liquid accumulation-gas injection-liquid production is repeated.  Advantages: Gas lift can be used in deviated or crooked wellbores, and in hightemperature environments that might adversely affect other lift methods, and it is conducive to maximizing lift efficiency in high-GOR wells. Wirelineretrievable gas lift valves can be pulled and reinstalled without pulling the tubing, making it relatively easy and economical to modify the design.  Disadvantages: the availability of gas and the costs for compression and injection are major considerations. Lift efficiency can be reduced by corrosion and paraffin. Another disadvantage of gas lift is its difficulty in fully depleting low-pressure, low-productivity wells. Also, the start-and-stop nature of intermittent gas lift may cause down hole pressure surges and lead to increased sand production. ELECTRIC SUBMERSIBLE PUMP An electric submersible pumping (ESP) assembly consists of a downhole centrifugal pump driven by a submersible electric motor, which is connected to a power source at the surface  Advantages:  The most efficient lift methods on a cost-per-barrel basis.  High rate: 100 to 60,000 B/D, including high water-cut fluids.

Paper ID:110





 Work in high-temperature wells (above 350°F) using high-temperature motors and cables.  The pumps can be modified to lift corrosive fluids and sand.  ESP systems can be used in high-angle and horizontal wells if placed in straight or vertical sections of the well.  Disadvantages: ESP pumps can be damaged from “gas lock”. In wells producing high GOR fluids, a downhole gas separator must be installed. Another disadvantage is that ESP pumps have limited production ranges determined by the number and type of pump stages; changing production rates requires either a pump change or installation of a variable-speed surface drive. The tubing must be pulled for pump repairs or replacement. HYDRAULIC PUMP A hydraulic pump is identical to a sucker-rod pump except it is driven by hydraulic pressure from a liquid pumped down the well. It uses two reciprocating pumps. One pump on the surface injects high-pressure power oil or fluid (usually crude oil from a storage tank) down a tubing string in the well. The power fluid drives a reciprocating hydraulic motor on the bottom of the tubing. It is coupled to a pump, similar to a sucker-rod pump, located below the liquid level in the well. The pump lifts both the spent power fluid and the produced fluid from the well up another tubing string. The power fluid causes the upstroke, and the release of pressure causes the down stroke. This type is called a parallel-free pump. In a variation,the casing-free pump, the power fluid is pumped down a tubing string, and the produced liquid is pumped up the casing-tubing annulus. The stroke in a hydraulic pump is very similar to a sucker-rod pump stroke, except it is shorter. Hydraulic pumps can be either fixed (screwed onto the tubing string) or free (pumped up and down the well). They can be either open, with down hole mixing of power and produced fluids, or closed, with no mixing. Most hydraulic pumps Paper ID:110





are free and open. Artificial lift in the United States consists of 82% beam pumper, 10% gas lift, 4% electric submersible pump, and 2% hydraulic pump. PLUNGER LIFT A plunger lift is an artificial lift method of deliquifying a natural gas well. A plunger is used to remove contaminants from productive natural gas wells, such as water (in liquid, mist, or ice forms), sand, oil and wax. The basics of the plunger are to open and close the well shutoff valve at the optimum times, to bring up the plunger and the contaminants and maximize natural gas production. A well without a deliquification technique will stop flowing or slow down and become a non-productive well, long before a properly deliquified well. PROGRESSIVE CAVITY PUMP As the rotor turns, cavities between the rotor and stator move upward. Progressive cavity pumps are commonly used for dewatering coalbed methane gas wells, for production and injection applications in waterflood projects and for producing heavy or high-solids oil. They are versatile, generally very efficient, and excellent for handling fluids with high solids content. However, because of the torsional stresses placed on rod strings and temperature limitations on the stator elastomers, they are not used in deeper wells. CONCLUSION This paper presents information on the various methods available for the selection of the best artificial lift system for given field conditions. The discussion presents selection methods covering depth-rate feasibility maps; tables of advantages and disadvantages; expert system programs containing feasibility, technical, and economic programs; and economic analysis methods such as present analysis. Because the present-value method requires designs to meet Paper ID:110





target rates, the user is somewhat forced to evaluate harsh conditions, etc., during the course of the design. The user must then add gas separators, sand control, or whatever is necessary to meet target rates before the NPV analysis is performed. By necessity, various feasibility criteria must be considered; therefore, even if all data required for a complete economic analysis are not available, going through the analysis forces the user to consider or make best estimates of critical parameters, pointing to a better selection process. Although some fairly complete expert systems for selection exist, their use is not widespread at this time. This may be a result of the constant updating required or because other types of selection processes that use experienced personnel may work as well or better. The lack of use also may be a result of the general lack of experience with these tools and a lack of understanding about the results that may be obtained for use. REFERENCES Brown, Kermit E. (1980). The Technology of Artificial Lift Methods, Volumes 1, 2a and 2b. Tulsa, OK: PennWell Publishing Co. Brown, Kermit E. (1982). “Overview of Artificial Lift Systems.” Journal of Petroleum Technology, Vol. 34, No. 10. Richardson, TX: Society of Petroleum Engineers. Clegg, J.D., Bucaram, S.M. and Hein, N.W. Jr. (1993). “Recommendations and Comparisons for Selecting Artificial Lift Methods.” Journal of Petroleum Technology (December), p. 1128. Richardson, TX: Society of Petroleum Engineers. Moineau, Rene (1930). “Un Nouveau Capsulisme.” Extracts from doctoral thesis, University of Paris. Takács, Gabor (2005). Gas Lift Manual. Tulsa , OK : PennWell Publishing.

Paper ID:110





Weatherford International Ltd. (2003, 2005). Artificial Lift Products and Services . Houston : Weatherford International Ltd. Schmidt, Z. and Doty, D.R (1989): "System Analysis for Sucker-Rod Pumping." SPE Production Engineering (May), p. 125. Richardson , TX : Society of Petroleum Engineers. Zaba, J., (1968), Modern Oil Well Pumping. Tulsa, OK: PennWell Publishing Co.

Paper ID:110





Paper ID:110
