NORWEGIAN UNIVERSITY OF SCIENCE AND TECHNOLOGYFaculty of Engineering Science and Technology Department of Petroleum Engineering and Applied Geophysics Natural Gas TPG 4140 Semester Project Downhole Gas Compression Mohammad Ostadi Maya Kusmaya Milad Kazemi Hatami Orkhan Ismayilov Kazeem Adetayo Awolola Trondheim ‐ November 2011 Abstract In all wells, reservoir pressure declines with the time. Boosting pressure becomes important to acquire high recovery and/ or accelerate production. Downhole Gas Compression (DGC) is one of the latest technologies for pressure boosting. It has a number of benefits as an artificial lifting system. DGC allows increasing potential production, therefore prolongs the lifetime of field production. Currently this technology is on the trial stage and is expected to enable gas extraction from otherwise uneconomic sites. The project summarizes the current status of this technology and shows its application in fields by simulation case studies. Both from literature and our case studies it was established that having a compression system as close to the reservoir as possible boosts the gas production and increases the ultimate gas recovery. ii List of Contents Abstract ii 1 Introduction ……………………………………………………….…..………….. 1 2 Gas well production limitations and challenges…………………….…......……… 2 3 Artificial lifting systems during gas production …………………………………. 3 3.1 Conventional compression ………….……………………………………. 3 3.2 Subsea compression at seabed ……………………………………………. 4 3.3 Downhole gas compression……………………………………………….. 4 4 DGC and it’s working principles............................................................................. 4 5 Downhole gas compression design and specifications ………………............…… 6 6 5.1 Challenges and obstacles............................................................................... 6 5.2 Design solutions via advanced engineering................................................. 6 Case study ………………………………………………………………….…….. 7 6.1 Deliverability profile of the well ………………………………………….. 9 6.2 DGC application as a solution …………………………………...........…… 12 6.3 Increasing reservoir recovery by DGC installation …………………...…… 12 6.4 Potential economic gain …………………………………………....…….… 13 7 Conclusions ………………………………………………………………………. 14 8 Nomenclatures …………………………………………………………………… 15 9 References ……………………………………………………………………….. 16 10 Tables…………………………………………………………………………….. 17 11 Figures……………………………………………………………….…………… 18 12 Appendices…………………………………………………………………………29 12.1 Natural gas properties equations ………………………………..……….… 29 12.2 Reservoir deliverability/inflow performance …….....................................… 31 12.3 Wellbore performance/tubing performance …......................................….… 32 12.4 Choke performance………………………………………………………… 32 12.5 Pipeline performance…………………………………………………..…… 35 List of Tables Table 6.1: Reservoir conditions ....................................................................................... 17 Table 6.2: Natural gas properties ..................................................................................... 17 Table 6.3: Well tubing specifications ............................................................................... 17 Table 6.4: Choke, separator and pipeline data ................................................................ 17 iii List of Figures Figure 2.1: Production profile of field life cycle…………………………………......……18 Figure 3.1: Different types of artificial lifting for oil extraction........................................ 18 Figure 3.2: Downhole hydraulic pump.............................................................................. 19 Figure 3.3: Water injection back to reservoir…………………………………….......……19 Figure 3.4: Offshore alternative gas compression……………………………….......….…20 Figure 3.5: Subsea processing projects installed or announced……..............................… 20 Figure 3.6: Åsgard subsea compression layout……………………………………....……20 Figure 3.7: Åsgard subsea compression main equipments……………………………… 21 Figure 3.8: Siemens PG’s Eco II centrifugal compressor…………………………..…… 21 Figure 3.9: Downhole compressor module…………………………………………….… 22 Figure 4.1: Potential yield improvements from utilizing downhole gas compression...... 22 Figure 5.1: Possible application range of DGC.................................................................. 22 Figure 6.1: Screenshot of HYSYS model…………………………………………….….. 23 Figure 6.2: System performance without DGC ……………………………………..…… 24 Figure 6.3: Velocity profiles inside the tube at the different wellhead pressures………… 24 Figure 6.4: Pressure loss profiles inside the tube at the different wellhead pressures…… 25 Figure 6.5: Gas velocity profile inside the tube at various locations of DGC ................... 25 Figure 6.6: The ability DGC to increase the tubing transport capacity……………..…… 26 Figure 6.7: The performance in the first two year with and without DGC ……………… 26 Figure 6.8: The performance with and without DGC at WHFP 195 psia ……………..… 27 Figure 6.9: The performance with and without DGC at WHFP 195 psia (5 year) ……… 27 Figure 6.10: Well Production profile with and without DGC at WHFP 195 psia………… 28 iv It has been long recognized by all parties in oil and gas sectors that pressure boosting in the gas field located as close as possible to the reservoir has the most advantage. and provide practical information through simulated case studies. The increasing demand for natural gas forces oil and gas operators to boost deliverability of their gas wells and extract available gas as much as possible. This technology is still at development phase. Dynamic behavior of well flow characteristics makes this task rather challenging. There are limited players that involved in technology development of the downhole gas compression. It talks about gas well production limitations. However. Downhole Gas Compression (DGC) offers unique opportunity of extracting available gas from previously unextractable reserves. they made a joint industrial program (JIP) to carry out further technology development including field trial in an operated mature asset located in Southern Italy (Di Tulio. equipment construction and pilot scale test in a replicating downhole conditions (SPE 116406). commercialization stages of this technology are expected to come in the near future. DGC can be utilized during various phases of the well’s production life in order to overcome the increased reservoir drawdown pressure and to extend the life time of the well. The most recent is downhole gas compression system. design challenges. Together with Eni. Corac Group Plc is one of the pioneers in designing and testing of this type of compressors. 1 . The main economic advantage is gained when downhole compression is implemented during the “plateau” production period. This is mainly because the design of this compressor demands advanced technology in many aspects. And also. natural gas fields are still vast and widely dispersed geographically. Most of oil and gas operators prefer to invest for new gas wells instead of prolonging production and increase the ultimate recovery in wells. Several efforts in the development of this kind of artificial lifting technology has been carried out.1 Introduction One of the main tasks of the upstream gas industry is the selection of an optimum artificial lifting system to enhance gas production. It leads to increase the well deliverability and recovery beyond that is achieved by using conventional gas compression system alone. ConocoPhillips and Repsol-YPF. This report tries to give the reader an overall introduction to DGC technology. DGC increases both the production and recovery factors of gas wells. The joint industrial program has completed design. 2009). By reduction in FBHP. All those methods are discussed in next section. for the same bottom hole and wellhead conditions. Critical velocity is the maximum velocity to avoid erosion effect in a specific tubing diameter. Indeed for keeping flow rate of gas. There are several artificial lifting methods such as subsea compression and downhole gas compression. The result is liquid accumulation in the reservoir. By reduction in reservoir pressure after some years. The most important issue at exploitation operation is to keep production level high at each stage. Tubing and well can be damaged because of the erosion at this condition. the gas density inside the tubing is low due to compressibility of the gas at constant flow rate.1). pressure is required. In order to demonstrate these stages special charts are used (Figure 2. There are several constrains to reach this target. To achieve desired deliverability from a particular field. Therefore artificial lifting by boosting pressure becomes very important. the velocity of gas which goes through the well starts to decrease. This required pressure is called Reservoir Pressure. This condition is not expected. At the primary stages of extraction the limitations include: fines migration. plateau and decline. As the pressure of the reservoir decreases it reaches to a point that liquid forms in the reservoir. Each part illustrates one of the production stages. Liquid formation during the field life is another challenge. wear due to erosion. This pressure decreases along production period (Jahn 1998). Pressure losses increase at higher gas velocity. At low flow rates. Each reservoir has a unique pressure. that may exceed the critical limit. It reaches to a point that makes reservoir unextractable. FBHP is the pressure at the bottom hole of the well. the right flow rate of gas is needed. the gas does not have the capacity to transport liquid droplets to the surface. surface facility and gathering system capacity. In order to achieve maximum production FBHP should be kept as low as possible in production period. However a main problem to have a low FBHP is critical gas velocity particularly in tubing constrained gas wells. The flowing bottom-hole pressure (FBHP) is another parameter for deliverability of gas. typically they are build up. The amount of reservoir pressure is a key parameter for deliverability of gas and should be enough to push the gas up to the surface. At lower gas density gas velocity is higher.2 Gas Well Production Limitations and Challenges Production life of oil and gas field can be divided into three main stages. 2 . In order to avoid this problem production rate should be decreased (Tullio 2009). When gas is sucked from wellhead. operators should utilize some methods to stabilize the pressure. hydraulic pumping. Conventional compressors are usually used at wellhead in onshore gas fields to maintain the required pressure.6 and 3.3 Artificial lifting systems during gas production Artificial lift method applies when the pressure of gas reservoir begin to reduce. Erosion in tubing as mentioned before could occur by utilizing of this type. Floating production system is the second alternative and utilizes the same compressors as fixed platforms. 3. Some of main techniques are briefly described below. Boosting pressure is more often used in oil wells rather than gas wells. especially in deep water gas fields.com 2011) . Ormen Lange. 2006). In onshore fields it is easier to compress gas than in offshore. oil and gas industry are turning into subsea compression systems (Figure 3. These methods are developed during previous years because of inherently less pressure in oil reservoir. In both cases. Åsgard and Snøhvit (Figure 3. Because of this benefit and also development of subsea facilities suppliers. In order to boost pressure for gas extraction. Oyewole 2008). Oyewole 2008) and (www.4). gas wells began to develop.1) (www. Power requirement for the compressor becomes less when the compressor is installed near the wellhead. 3 . compressors are installed at sea level and far from wellhead and this mean more powerful compressors and more demand for energy. There are a variety of techniques to offset the reduction of flow of gas due to declining of the reservoir pressure. In offshore. investment on developing of these ways is reasonable (Peter O.3) (Peter O.M.rigzone. the pressure of the well decreases.2 Subsea compression at seabed Subsea compression system is other alternative with substantial advantages.5). some techniques are used in latest years. downhole hydraulic pump (Figure 3. Since oil has a better relative value and price among other energy resources. By increasing demand for natural gas as a clean source of energy.pdhengineer.2) and water injection (Figure 3. gas lift.7) (Sirevaag 2009) and (Bass R. electric submersible pump (Figure 3. Several methods that are used for boosting pressure in oil production are beam Pump. different techniques are available to stabilize pressure during the production (Figure 3. Currently subsea compression is widely used and being developed by Statoil and its partners in some fields such as Gullfaks. Over time. 3. One way is to use conventional compressors in fixed platforms (Sirevaag 2009).com 2011).1 Conventional Compression Conventional Compression is used both in onshore and offshore fields. DGC is purely designed to increase well potential and ultimate recovery which are the functions of both factors –reservoir drawdown and tubing friction. DGC offers a good solution when the most significant ‘bottleneck’ to higher productivity is below ground (in the wellbore/tubing).com 2011).8) is used in subsea processing facilities at Statoil’s Tordis field in the Norwegian sector. As explained earlier. In addition subsea gas compressors are providing the possibility of development of stranded gas fields which are far from infrastructures (www. the compressor attempts to draw on a vacuum.M. 3. DGC compress the gas inside the tubing just after the gas leaves the bottom hole. the conventional compression system which is installed at the well head has a limitation. when a gas reservoir pressure declines. When the pressure losses are too much in the production tubing. 4 DGC and it’s working principles DGC is a new artificial lifting technology developed particularly to overcome the common erosional problem in natural gas wells. and being economically effective just for large fields (Bass R. In spite of considerable advantages of subsea compression.rigzone.com 2011).ior. Thus. central gas compression and/or wellhead compression are generally utilized to extend productive life. this kind of new technology has challenges ahead. at which point flow stops. the well production is down and it may no longer be economical to be extracted. it reduces to the extent that it is insufficient to overcome the friction in the production tubing of the well.3 Downhole gas compression Downhole gas compressor (DGC) (Figure 3. In gas fields. need for special facilities and material to run at seabed. Subsea gas compressors are cost-effective and save 30-40% of energy compared to their platform-based counterparts. For instance. In this condition.senergyltd. This new technology is expected to be a driver to boost the gas production rate and increase the ultimate gas recovery.9) is the recent alternative to deal with the problem of pressure decline in gas reservoirs. it increases the gas density along the tubing and decreases the gas velocity for the same mass flow rate of the gas. Some of the challenges are high relative investment and service cost. This type of compressor is not in commercial use and is just in testing stage. Siemens PG’s Eco II compact compressor (Figure 3.Utilization of commercial and standard available types of compressors in subsea modules is another interesting issue. 4 . However. 2006). More details about DGC are mentioned in the following section (www. since the DGC can operate at lower FBHP than other compression technologies. it significantly increases the ultimate recovery. It occurs when the upward gas velocity falls below a critical value required for gas to move liquid droplets up to the surface. Compression close to the source reservoir is more effective in lowering the field abandonment pressure and hence increasing ultimate recovery.1. Therefore DGC is able to deliver more gas than is produced using conventional central gas compression alone. The lower FBHP results in more drawdown rate of gas from reservoir to bottom hole which itself accelerates gas production. DGC technology uses a compressor placed as near as possible to the point where gas is flowing from reservoir into the wellbore. A modest increase in tubing pressure obviously results in an increase in tubing transport capacity. 5 . As the reservoir pressure declines a further problem is the liquid loading process. This figure shows a graph of well flow potential (in thousand sm3/day unit) plotted against reservoir pressure for central compression. DGC solves this problem by extending the period of liquid droplet transport at the higher wellhead flowing pressure. DGC is estimated to increase the production gain by 32 – 41%. DGC decreases the reservoir abandonment pressure thus maximizes the recoverable reserves from the well reservoir (Liley 2004) The advantages of DGC to increase gas production and ultimate recovery are illustrated in Figure 4. it sucks more gas from the bottom hole and reduces the FBHP. It represents additional recovery of 14 – 20 Bscf per well over 5 years operation.al. By placing DGC near the bottom of the well. in this graph mentioned as DHGC (blue. Central gas compression and well head gas compression systems are placed at a considerable distance from the reservoir. well head gas compression (WGC) and downhole gas compression. And also. All in all. DGC system brings the opportunity to develop stranded and sub-economic gas fields. By lowering FBHP. The figure clearly shows that DGC at the same reservoir pressure accelerates gas production particularly at higher reservoir pressures where the production driving force is big. (2009). Based on a comprehensive feasibility study done by Liley et. both compression technologies are facing the suction tubing high pressure losses due to friction and erosional problem which hinders the production acceleration . The theoretical absolute open flow (AOF) potential of the well which is our objective is shown in the black line. yellow and green lines respectively). Thus.This reduces pressure losses due to friction and also reduces erosion problem inside the well tubing. entrained contaminants. To have high flow rates the compressor requires high speed motor. Conventional lubrication systems can not work in this environment. The third challenge is the lubrication system. 5. But it is not that easy. To improve production. these challenges enhance technology. It requires innovative technologies to overcome the physical barriers downhole. Supplying AC current from the surface results in significant losses due to the long distance. For every instrument to withstand and operate in these conditions there are some specifications.1 Challenges and obstacles As you may imagine.000 rpm (Reed 2009). The harsh conditions are typically 20-60 bara in pressure and in excess of 100 °C in temperature (plc 2011). the gas flow requires a moderate increase in pressure. and second.2 Design solutions via advanced engineering As mentioned before. 6 . Therefore there are two challenges to face with the electrical part: first. a higher economic benefit will be obtained. One of the challenges is to provide 250-500 kW of compressor power 2-3 km below ground. a lot of electronic equipment should be packed in a limited size. The last challenge is the delivery of electricity to the unit downhole. compressor speed is in excess of 60. there is a need to cool these electrical parts (Reed 2009).5 Downhole gas compression design and specifications 5. Therefore centrifugal or axial compressors would be an ideal option. And if these challenges are met. Gas flow. temperature and rubbing speeds of the seal surfaces degrade conventional lubrication system. operating downhole is full of challenges. the compressor should operate within the size of the tubing which is typically 7-9 inches. The motors require alternating current (AC) power supply. The compressor system comprises of two to six independent compressor units arranged in series and mounted in a standard length of production tubing (Reed 2009). But if we look at the bright side. downhole conditions can get very harsh. Within 7-inch-diameter tubing. because they are suitable for high flow rates and moderate pressure ratios. The second challenge is to design a high speed motor to drive compressor. The power requirement of the compressor depends on the gas flow rate at same casing diameter. Currently. the higher the power requirement. 2. Instead well gas acts as lubricant. The compressor is driven by motor on single shaft and there are no gear boxes. It has been demonstrated that it can operate in wells with high liquid-gas ratios (greater than 27% by mass) with inlet temperature of 105 °C (Reed 2009). the performance of the compressor depends on the gas temperature. Corac Group Plc. The higher the flow rate.The optimum depth to locate DGC inside the well tubing. Thus. It runs at 45. The electricity is transmitted downhole as a direct current instead of alternating current. the gas flow is used to cool it. 7 .To overcome the problem of high rotational speed. Currently. the technology is capable of operating with an inlet gas temperature of 105 °C (Reed 2009). the technology is available for casing diameters of 5.DGC compression work required to maintain the production 3. couplings or seals (plc 2011). the whole motor drive and inverter are placed downhole. In our case study in the next chapter the flow rate is not in the range of this figure (it is lower).000 -60. But there is a disadvantage to this. has developed and patented high speed permanent magnet motor.000 rpm.The deliverability profile of the well. 6 Case study The objective of this case study is to evaluate the advantages of the DGC system by making comparison between the production profiles with and without DGC system over the depletion period.5 inches or above. This lubrication system offers a very low-friction support system. the motor is cooled by the well gas flow around the outside of the motor. As the consequences. The motor is supported on gas bearings that do not require oil lube.1. flow rate. maximum inlet gas temperature and pressure ratio given by Corac Group Plc is shown in Figure 5. There are no liquid cooling circuits. The range of applications of DGC technology related to the overall tubing diameter. The gas bearings ensure no wearing surfaces during operation. Instead. it is difficult to have separate cooling system for electronic equipment inside the tubing. This is to minimize transmission losses. Commercial HYSYS simulator and Microsoft Excel are utilized to analyze and calculate the followings: 1. Due to space limitation. the reservoir conditions are assumed to be 27. single completion string. The same well tubing dimensions as Di Tulio et. 1.28 of specific gravity (γg) and specific heat ratio (k). The specific gravity value is taken from Di Tulio et. wellhead flowing pressure (WHFP) at or below 20 bars. (2009) which are: 1. (2009) in which candidate well selection criteria is described. However. medium to high productivity. stabilizing well bore flow regime.28 is typical for natural gas (Guo 2007). calculating the DGC power required and optimum depth of DGC location inside the tubing. 4. In actual fields these numbers are taken from the well tests. flowing bottom hole temperature (FBHT) less than 110 oC. the conditions of the well follow the requirements mentioned by Di Tulio et. the choke and pipeline data are assumed and shown in the Table 6. The reservoir conditions for the case study are described in Table 6.1. In addition to this study. used for their study in 2009 is selected. 8 .4.al. All those parameters are the basis for calculating the deliverability of the well. the gas composition for this study is assumed to be 99% methane and 1% ethane to get the same specific gravity of 0.56 and 1. In the case study the gas has 0. Wet or dry gas well with minimum 178 mm (7 “) casing outer diameter. To evaluate the DGC application and advantages in depleted wells. There was no information about the gas composition in that article. al. For the case study. and low liquid production. not a real one. 2. integrating the DGC system with the conventional central/surface compression system. the C-constant and nexponent in backpressure Inflow Performance Relations (IPR) are assumed to be 0. Increase ultimate recovery by increasing the tubing unloading capacity and lowering the abandonment pressure.86 respectively. Electricity available on well site 3. This is an artificial well.3.al. The gas properties and conditions are described in Table 6.Comparison between cost and energy requirements of DGC to that of conventional compression system is also briefly discussed.3 bar in pressure and 74 oC in temperature (Tullio 2009). in which data are taken from several sources with different assumptions. For the specific heat ratio (k). Production benefits are achievable by: increasing well drawdown.2.09 Mcf/d-psi2n and 0. Meanwhile.56. respectively. All these dimensions data are shown in Table 6. The Microsoft Excel is used to apply these equations and approaches. with the input data taken from Table 6. Meanwhile the outflow performance relationship is a mathematical tool used in production engineering. the gas properties and compositions as explained earlier are inputs of the simulation. The calculations obtained from HYSYS simulation and the Excel show small deviations. Meanwhile. It helps to assess the performance of the completion string by plotting the surface production rate against the flowing bottom hole pressure (FBHP). Its results are used in determining the economics of producing a well. a valve. Correlation line resulted from this equation is called inflow performance. a DGC unit is modeled as a compressor and is located in between of the two pipe segments. To find out more about the calculations involved in the simulation. The production is maintained by installing conventional compression system at the downstream of the separator to reduce the surface pressure.1 Deliverability Profile of the Well After some years in operation. a pipeline module in HYSYS is used to represent the tube inside the well. Inflow performance relationship of a well is a relationship between its producing bottom-hole pressures and its corresponding production rates under a given reservoir condition. Inflow and outflow performance and DGC compression works are determined by the simulation.6. Pipeline units. the C-constant and n-exponent are backpressure Inflow Performance Relations (IPR) constants. the gas well production rate is reduced. P is reservoir pressure and Pwf is FBHP (both in psia). The fluid composition and behavior of the fluid phases affects the shape of the curve. Several equations used are explained below to show how simulator calculates the inflow and outflow performance. The bottom hole of the well is selected for the solution node in this study. The reservoir conditions.1. It indicates the producing characteristics of a well. HYSYS simulator used is a black-box calculation tool. Flowing bottom hole pressure (FBHP) is calculated by the following equation: q C ( P 2 P 2 wf ) n Where q is gas flow rate (Mscfd). Each of the pipe segments represents the tubes at lower and upper parts of the compressor. For natural flow case (without DGC). all equations and approaches (Guo 2007) to determine the inflow and outflow performance curves are described in Appendix 1. HYSYS simulated model representing production line from the reservoir to the conventional compression system is shown in Figure 6. 9 .3. separator and conventional compressor are added at the downstream. For DGC case. The simulations are done in steady state conditions. Since the bottom hole of the well is selected as node. CD is choke characteristic constant. if the flow is at sub sonic condition.5 D GT f LZf Where the main variables are: Q for flow rate. D is pipe diameter. flow rate and pipeline dimensions are calculated by this equation: T Q 77. and k is the specific heat ratio. The separator pressure is maintained constant at allowable operating pressure of the conventional compressor.0375 g L cos zT 10 . Pup (k 1) gTup Pup Where. P2 for separator pressure which is maintained at constant value.67 104 Exp ( s ) 1 f M q 2 z 2T 2 d 5i cos 0.248CD A2 Pup ( ) k ( ) k . L is the length of pipe and Z is the average compressibility of the gas. then this equation should be applied: Pdn 2 Pdn k 1 k qsc 1. A is the choke nozzle area. pressure at upstream of the pipe (P1) can be determined.54 b Pb P 21 P 2 2 2. pressure in the upstream of the choke/valve at the well head is determined by the following equations: If the flow in the valve is at sonic condition: Qsc 879CD Apup ( k 2 kk 11 )( ) g Tup k 1 While. and well tubing back to the bottom hole point. the outflow performance is calculated starting from the separator system through the long pipeline. After having pressure at upstream of the choke (the same as well head pressure. Thus. choke (valve). Pressure. Phf). After calculating P1. for a certain flow rate. f is friction losses along the pipe. final step to determine outflow performance is to calculate bottom hole pressure by this equation: P 2 wf s Exp ( s ) P 2 hf 6. Pdn and Pup are pressures at downstream and upstream of the choke. But in the second year. This is resulted from in intersection of IPR 1 and NF 247 lines in the figure. The possibility of having noise and erosion problems inside the tubing and pipeline rises as the gas flow velocity exceeds 60 ft/s [API RP 14E.2. This is the case when the well is operated at lower pressure. One way to avoid erosion is raising the wellhead pressure but it decreases the production rate and increases the un-exploited reservoir drawdown. the lower well head pressure might not be economical to be applied. Figure 6. For more detailed equations and units used in this case study see Appendix 1.4 shows higher pressure losses for lower the well head pressures due to higher flow velocity. well deliverability is then determined by the intersection of the inflow and the outflow (tubing) performance curves.This tubing string correlation is called Average Temperature and Compressibility Factor (TZ) Method. The lower well head pressure. Correlation line between FBHP (Pwf) and flow rate (q) resulted from this equation is called as outflow performance. Excessive gas velocity in the upper part of the tubing is a problem when low wellhead flowing pressure is required for the optimal gas production (Tullio 2009) . the well head pressure should be decreased further. Three well head pressures used are 247 psia. It is assumed that the system allows the wellhead pressure to go down to a minimum of 131 psia limited by operational condition of conventional compression system at the downstream facility. but at the same time. Thus. The future well deliverability (or minimum FBHP) over the depletion is also determined by the intersection of both curves. Figure 6. 1991]. The HYSYS simulation result for the well deliverability projection is shown in Figure 6.This leads to erosion corrosion problems inside the tubing.3 is HYSYS simulation result to show the impact of the well head pressure adjustment (to boost the well deliverability) to the velocity profile inside the tube. the higher velocity inside the tube. In this case the well head pressure should be at 195 psia. 195 psia and 131 psia. It is in US field units. the wellhead operates at about 247 psia to produce 1100 Mscfd of gas. The production rate can be increased to 1600 Mscfd by lowering the well head pressure to 131 psia. The expected production rate cannot be achieved as in previous year with the same well head pressure of 247 psia. the reservoir pressure decrease to 365 psia and the inflow performance curve changes to IPR 2. 11 . To maintain the same or even higher rate from the previous year. the more production rate. Since the energy efficiency is a key figure in oil and gas industry. In the first year. At the same time. By placing the DGC as close as possible to bottom hole of the well.6. the desired production rate can be maintained without causing any erosion problem inside the tubing. The electrical power required at higher gas rate will determine the compressor power to install (Tullio 2009). For this condition. It is due to the erosion problems and limitations in operational range of the compressor at the downstream. With a particular inflow performance. 12 . the source of energy will be electrical power.2 DGC application as a solution Installing new conventional compressor at the surface to suck more gas from the well would not be an option when we have noise.000 m. the well depth is about 2. DGC effectively introduce an energy required by gas to flow at the desired flow rate.900 – 2. the DGC system appears to be a good solution.5 is HYSYS simulation result for optimum DGC location. As common in other wells. Without DGC. lower compression power for DGC is required. Therefore the abandonment reservoir pressure would be higher. the wellhead and bottom hole flowing pressures cannot be reduced further to increase the production. 6. The results show that the lowest gas velocity in the tubing occur when the DGC is placed nearly at the bottom hole of the well (in this case at the depth of 1. erosion and high velocity problems at the wellhead. If the well is operated at lower gas rate. DGC is also decreasing the flowing bottom hole pressure that results in higher drawdown of the gas from the reservoir. DGC delivers more gas compared to natural flow sucked by conventional compressor at same well head pressure. The DGC increases the density of gas inside the tubing (at its discharge) and increases the wellhead flowing pressure. This unique DGC ability can be used to increase and/or maintain the deliverability of the depleted well.358 m).6. Therefore it is concluded that the DGC can be a solution to increase and/or maintain the deliverability rate of the depleted well without causing erosion problem in the well tubing. It enables a greater quantity of gas to be delivered to the processing facilities without suffering from erosion and potential energy losses (pressure losses). Figure 6. The DGC ability to increase the tubing transport capacity is shown in Figure 6. The gas velocity increases as the DGC is placed nearer to the well head.3 Increasing Reservoir Recovery by DGC Installation Abandonment reservoir pressure with and without the DGC installation will be different. o. Installation cost for a single DGC unit has not been established so far. considering the vast potential revenue remaining in the well. From this Figure.7. The minimum bottom hole flowing pressure can be further reduced to 3 bars (43. As mentioned earlier.e of the gas produced. this additional operating cost does not have a significant impact on the revenue from the produced gas.10.076 B. Apart from the potential economic gain. Power consumed by a 15 kWDGC is about 1. the yearly gas production with and without DGC can be calculated and compared. DGC driver unit which is installed inside the well is supplied by 15 kW of electrical power.o. 6.9 during 5 years of depletion period.al. it is revealed that DGC increases the reservoir recovery to an average of 70%. Based on inflow performance curves.e. (2009) claims that DGC is still economically feasible by operational cost of 50 cent USD/B. DGC has an additional operating cost for the power consumption.4 Potential economic gain It is rather difficult to estimate the exact economic gain of the DGC technology.Inflow and outflow performance curves with and without DGC resulted from HYSYS simulation are compared in Figures 6.10.o. This result is shown in Figure 6. decreases the abandonment pressure from 223 psia to 132 psia. This cost in 5 years operation is 26.5 psia) according to the operational limitations set by (Tullio 2009). the potential economic gain seems very attractive since this technology brings the opportunity to increase the production and reservoir recovery. This increase of production is equivalent to 130. since it is in its testing stage and has not been commercially implemented. Careful assessment of gas production. However. Di Tulio et. 13 . and prolongs the well production life.e. The well head is set at fixed pressure of 195 psia to have sufficient operational margin for the conventional compressor at the surface. gas price and operating expenditure should be made before implementing DGC in a gas well. DGC will bring bright future to the upstream gas industry by providing it with more gas to process. 6.280 USD at assumed 12 USD/mmbtu of gas price and it is about 20 cent USD/B. From Figure 6. it can be seen that the well production increase by 730 MMscf in 5 years of DGC operation.8 and 6.2 MMBtu/day. 7 Conclusions 1.Installing DGC into the well tubing decreases the abandonment pressure and increases ultimate reservoir recovery. The gas velocity and pressure drop increases as the DGC is placed nearer to the well head. The challenge at the end of the production life is to create the lowest achievable flowing bottom-hole pressure in order to improve the wells unloading capacity. . . it is insignificant compared to the potential revenue obtained.DGC appears to be a potential candidate as a means to increase or maintain the deliverability rate of the depleted well without causing erosion problem in the well tubing. DGC will bring bright future to the upstream gas industry by providing it with more gas to process. 2. 3.Installation of DGC adds an additional operating cost. Several observations can be drawn from the case study using HYSYS simulation: . However.DGC placed as close as possible to the bottom hole of the well gives optimum result in terms of lower gas velocity and pressure drop inside the well tubing. . 14 . 8 Nomenclatures NF = Natural Flowing Boe = Barrel oil equivalent DGC = Downhole Gas Compressor or Compression FBHP = Flowing Bottom Hole Pressure HP = Horse Power or DGC shaft power IPR = Inflow Performance Relation KW = Kilo Watt P = Pressure T = Temperature WHFP = Wellhead Flowing Pressure JIP = joint industrial program 15 . C. H. Offshore technology conference. James F. 13. "Statoil: Subsea Compression Boosts Gas. SPE Annual Technical Conference and Exhibition.com. (2007). Liley J. Artificial-Lift Selection Strategy for the Life of a Gas Well With Some Liquid Production.N. L. Petroleum Production Engineering. Denver. ELSEVIER. www. W. and GRAHAM.asp?a_id=108151. 6. Eni S." from http://empedia.com.A. (2011). USA. B. 11. Verbeek. E&P Division. J.info/images/resource/698/large.com/issue13/research-development/smes/corac/. H. COOK. Subsea Compression . 17. I.com." from http://www. .html. W. Jahn. A ComputerAssisted Approach.. Downhole Gas Compression. "Subsea compression opens options for stranded deepwater gas. 8. Hydrocarbon Exploration and Production. Reed. J. "Gas Pipeline Hydraulics." from http://www.uk. www. 8-11 June 2009. www. Bernatt N.. 16 . F. (2011) "Artificial lift systems benefiting by new technology." from http://www. (2011). U. Subsea Processing and Boosting-Technical Challenges and Opportunities. W. (2011). Wellbore pressure boosting enhances recovery from natural gas wells. P.htm. B.ior.co. "Water injection well. 10. www. S. Downhole Gas Compression: World's first installation of a new Artificial Lifting System for gas wells. www.senergyltd. (2011). R. (2006). www. Colorado. a.com (2011) "How Does Artificial Lift Work?".ior.. L. Texas. 12. Nelson. Lea. S.p. S.S. Offshore Technology Conference Guðmundsson. Shell E&P BV (2004). Offshore Technology Conference. (2011). BP. Lea.. Houston. J. .. Guo.M. M.rigzone. 14.senergyltd." Introducing developments in natural gas well dewatering. Oyewole. What’s new in artificial lift. (2011). 7. 5.rigzone.jpg.rigzone. E. 18. Ghalambor. The Netherlands. Sirevaag. S. . G. J." Peter O.9 References: 1.from idea to reality? Tullio. N. EUROPEC/EAGE Conference and Exhibition. PL Tech LLC (2008). "Downhole Cas Compressor. 16. E.com/index/petroleum/display/253470/articles/offshore/volume66/issue-4/norway/subsea-compression-opens-options-for-stranded-deepwater-gas.. Amsterdam. 2." 69. T. Society of Petroleum Engineers plc. Texas.com.. Corac Group Plc.dukeswoodoilmuseum. Houston. (2011). M. Corac Group plc (2009).A.pdhengineer." from www. NATURAL GAS PRODUCTION ENGINEERING. 4.. and James F. Fornasari. Texas Tech University (2010) "PRODUCTION TECHNOLOGY.E. Society of Petroleum Engineers: 8-11. A. C. P. M. 9. P. (2009) "Downhole Gas Compression – A New Artificial Lift Technology for Gas Wells. Bass R. SPE. P. Liley. 15. D.com/news/article. .pennenergy. Ravaglia D. (2009). T. 3. . (1998). Elseiver Science & Technology Books.com/pages/O-5001. .offshore-mag.pdhengineer. 441 0.4: Choke.3 74 0.3: Well tubing specifications (Tullio 2009) Properties Tubing inside diameter (D) Tubing absolute roughness (ε) Tubing relative roughness (ε/D) Measured depth at tubing shoe (L) Inclination angle (Ѳ) Unit In In m Degrees Value 2.358.85 0 Table 6.142 Bar o C In mile In Bar o C 9 27 10 1000 0.86 Table 6.1: Reservoir conditions (Tullio 2009) Properties Reservoir pressure Bottom hole temperature C-constant in back pressure IPR model n-exponent in backpressure IPR model Unit bar o C Mcf/d-psi2n Value 27.0003 0.0001229 2.2: Natural gas properties (Tullio 2009) Properties Gas specific gravity (γg) Gas specific heat ratio (k) Pseudocritical pressure (Pc) Pseudocritical temperature (Tc) Unit Bar o C Value 0.09 0.0006 1 27 .28 46.56 1.4 -80.93 Table 6.10 Tables: Table 6. separator and pipeline data Properties Choke data Upstream pipe diameter Choke diameter Choke cross-sectional area Separator & pipeline data Separator pressure Separator temperature Pipeline diameter Pipeline length Absolute internal pipe roughness Base pressure Base temperature 17 Unit Value In In in2 10 2 3. 1: Production Profile of Field Life cycle (Guðmundsson 2011).11 Figures: Figure 2.1: Different types of artificial lifting for oil extraction. (Nelson 2011) 18 . (Jahn 1998) Figure 3. 3: Water injection back to reservoir (www.2: Downhole hydraulic pump (James F.Figure 3.dukeswoodoilmuseum. Lea 2010) Figure 3.co.uk 2011) 19 . Figure 3. 2006) Figure 3.M.5: Subsea processing projects installed or announced (Bass R.6: Åsgard subsea compression layout (Sirevaag 2009) 20 .4: Offshore alternative gas compression (Sirevaag 2009) Figure 3. 8: Siemens PG's Eco II centrifugal compressor.7: Åsgard subsea compression main equipments (Sirevaag 2009) Figure 3.offshore-mag.com 2011) 21 . (www.Figure 3. 1: Possible application range of DGC (Reed 2009) 22 .9: Downhole compressor module (www.ior.ior.com 2011) Figure 5.senergyltd.Figure 3.com 2011) Figure 4.1: Potential yield improvements from utilizing downhole gas compression (www.senergyltd. Figure 6.1: Screenshot of HYSYS model used for representing the reservoir to the conventional compression system 23 . NF = Outflow performance without DGC. ft/s 60 50 40 30 20 10 0 0 500 1000 NF 131 1500 2000 qsc.Pwf.2: System performance without DGC (IPR = Inflow Performance Relation.3: Velocity profiles inside the tube at the different wellhead pressures (NF = Outflow performance without DGC. Mscf/d NF 247 2500 NF 195 3000 NF 131 Figure 6. the numbers refer to WHFP values. psia System Performance at Bottom Hole 500 450 400 350 300 250 200 150 100 50 0 0 500 IPR 1 1000 IPR 2 1500 2000 qsc. the number refer to year. the numbers refer to WHFP values. Mscf/d NF 195 2500 3000 NF 247 Figure 6. psia) 24 . psia) Gas Velocity Profile Inside the Tube 70 Gas Velocity. the numbers refer to WHFP values. Mscf/d NF 195 2500 3000 NF 247 Figure 6. psia) Well depth (m) Figure 6.Pressure loss. psia Pressure Losses Inside the Tube 200 180 160 140 120 100 80 60 40 20 0 0 500 1000 NF 131 1500 2000 qsc.5: Gas velocity profile inside the tube at various locations of DGC from the wellhead 25 .4: Pressure loss profiles inside the tube at the different wellhead pressures (NF = Outflow performance without DGC. psia 300 250 200 150 100 50 0 0 500 IPR 1 1000 1500 2000 qsc. Mscfd DGC 131 NF 131 2500 3000 IPR 1 Figure 6.Increasing Tubing Capacity by DGC 400 350 Pwf.6: The ability DGC to increase the tubing transport capacity (IPR = Inflow Performance Relation. NF = Outflow performance without DGC. psia 300 250 200 150 100 50 0 0 500 1000 1500 2000 qsc. Mscf/d IPR 2 NF 195 2500 3000 DGC 195 Figure 6. psia) Inflow Performance Curve 400 350 Pwf. the number refer to year. the numbers refer to WHFP values.7: The performance in the first two year with and without DGC at WHFP 195 psia 26 . 8: The performance with and without DGC at WHFP 195 psia in the middle of DGC operation period Inflow Performance Curve 400 350 Pwf. psia 300 250 200 150 100 50 0 0 IPR 3 500 1000 IPR 4 1500 2000 qsc. psia 300 250 200 150 100 50 0 0 500 1000 1500 2000 qsc. Mscf/d IPR 2 IPR 3 NF 195 2500 3000 DGC 195 Figure 6.Inflow Performance Curve 400 350 Pwf.9: The performance with and without DGC at WHFP 195 psia in the end period of DGC operation for the case study (5 year) 27 . Mscf/d IPR 5 NF 195 2500 3000 DGC 195 Figure 6. Yearly Gas Production (at WHFP 195 psia) Production. 10^3 Mscf 600 500 400 300 200 100 0 1 2 DGC 3 Year 4 5 NF (without DGC) Figure 6.10: Well production profile with and without DGC at WHFP 195 psia 28 . Rankine) from known gas specific gravity (γg).5) 240 y N 2 83.08 10 9. 1954 involves a two-step procedure: The gas viscosity at temperature and atmospheric pressure is estimated first from gas.12 Appendices: 12.2 Determine pseudoreduced properties: PPr P Ppc Tpr T Tpc 1.specific gravity and inorganic compound content.08 103 log( g )] yCO 3 3 2 2 1H S [3.1 Natural gas properties equations (Guo 2007) 1.188 103 6.1 Determine pseudocritical temperature and pressure (psia.24 10 9. Ppc 678 50( g 0.15 103 log( g ) (1.7( g 0.3 yCO2 133.73 10 8.59 103 8. The atmospheric value is then adjusted to pressure conditions by means of correction factor on the basis of reduced temperature and pressure state of the gas.062 106 g )T 1N [9.5) 206.3 y H 2 S 1.7 y N 2 440 yCO2 606.3 Determine gas viscosity Correlation of Carr et al.49 10 log( g )] yH S 3 2 3 2 29 .48 103 log( g )] yN 2 2 1CO [6.709 103 2. The atmospheric pressure viscosity (μi) can be expressed as 1 1HC 1N 1CO 1H S 2 g 1 Tpr 2 2 e r 1HC 8.7 y H 2 S TPC 326 315. 00060958 1. the following derivative is needed.4 Determine the gas compressibility.80860949 a 5 3.36037302 a 7 0.00441016 a12 0.01044324 a 8 0. df (Y ) 1 4Y 4Y 2 4Y 3 Y 4 2 BY CDY D 1 4 dY (1 Y ) 30 .14914493 a11 0.02033679 a15 0.7 242.08393872 a13 0.97054714 a 2 0.49803305 a 6 0.39643306 a10 0.4t 2 r ) D 2.18640885 a14 0.2tr 42.79338568 a 9 1.82tr and Z Ap pr Y Where Y is the reduced density to be solved from f (Y ) Y Y 2 Y3 Y 4 Ap pr BY 2 CY D 0 3 (1 Y ) If the Newton and Raphson iteration method is used to solve the above equation for Y. r ln( g T pr ) a 0 a1 Ppr a 2 P 2 pr a 3 Ppr 3 T pr ( a 4 a 5 Ppr a 6 P 2 pr a 7 P 3 pr ) 1 T 2 pr ( a 8 a 9 Ppr a10 P 2 pr a11 P 3 pr ) T 3 pr ( a12 a13 Ppr a14 P 2 pr a15 P 3 pr ) a 0 2.46211820 a1 2.2(1tr ) 2 B tr (90.00805420 a 4 2.28626405 a 3 0.06125tr e 1.18 2. many methods are available but Hall and Yarborough give a more accurate estimation: Hall and Yarborough Method A 0. 2 10 Bg ln( ) s Dq rw When P 3 Bg= 31 3000 .6 Formation Volume Factor of gas ( ) Gas formation volume factor is defined as the ratio of gas volume at reservoir condition to the gas volume at standard condition.1.472re 141.0283 Vsc PTsc Z sc P 1.1 Flow Analytical Method q kh( P 2 P 2 wf ) 0.5 Gas Density ( g ) 2.3 Bg ZT 12. E 1 P 35. that is. Bg P TZ V zT sc 0.7 Gas Expansion Factor ( ) It is normally used for estimating gas reserves.7 g P zT 1.472re 1424 zT ln( ) s Dq rw When P 3000 q= k= md h= ft P= psi T= Rankine rw= ft D= s= skin factor q kh( P Pwf ) 0.2 Reservoir deliverability/inflow performance (Guo 2007) 2. 277 .0375 g L cos zT The Darcy-Wisebach(Moody) friction factor f M fM 0. Where C and n are empirical constants that can be determined based on test points.277 .C n 2 2 2 P P wf 1 P P 2 wf 1 log( 2 ) P P 2 wf 2 log( 12.1 Critical Pressure Ratio Poutlet 2 kk1 ( )c ( ) Pup k 1 where Poutlet is the pressure at choke outlet. The value of the k is about 1. For air: k=1.40 Critical P ratio 0.224 fM 0.67 104 Exp ( s ) 1 f M q 2 z 2T 2 d 5i cos 0.2 Subsonic flow 32 .5 and 1.28 for natural gas. for di d i 0. Pup is the upstream pressure.4 Choke performance (Guo 2007) 4. and k= is the specific heat ratio.164 4.28 Critical P ratio 0. for di 4.5494 When the actual ratio Critical ratio then subsonic flow exist When the actual ratio Critical ratio then sonic flow exist (the flow is choked at the valve) 4. q1 ) q2 q1 n .01750 .b) Empirical Method q C ( P 2 P 2 wf ) n . Or 1 fM 1. d i 0.1 Average TZ Method P 2 wf Exp ( s ) P 2 hf s 6. The value of n is usually between 0.5283 For NG: k= 1.3 Wellbore performance/tubing performance (Guo 2007) 3.01603 .74 2 log( 2 s ) d i 2 12. in.3167 0. in. Mscf/d Pup= upstream pressure at choke. 4.ft/lbm. psia A2= cross-sectional area of choke. 32.4 Choke flow coefficient CD d 2 0. or v 44. d 2 = choke diameter.7 lb. °R g= acceleration of gravity. in. Thus. Pup Pup Where qsc= gas flow rate.248CD A2 Pup k (k 1) gTup Pdn 2 Pdn k 1 ( ) k ( ) k .76 Tup v v 2up 2 g c C pTup 1 zoutlet k 1 The choke flow coefficient CD is not sensitive to the Reynolds number for Reynolds number values greater than 106.025 log N Re 4 .3 Sonic flow Qsc 879CD Apup ( k 2 kk 11 )( ) g Tup k 1 Maximum flow zup 2 ( ) .6 2 d 1 Where d1 = upstream pipe diameter. d1 d 0. 2 Velocity of the gas v v up 2 g c C pTup 1 zup Pdown kk1 ( ) .Rn for air) 4.2 Tup= upstream temperature.qsc 1. the CD value at Reynolds number of 106 can be assumed for CD values at higher Reynolds numbers.2 ft/s2 γg= gas-specific gravity related to air N Re 20qsc g d2 Where is gas viscosity in cp. zdn Pup Where C p = specific heat of gas at constant pressure (187. N Re = Reynolds number based on d 2 33 . 5 Temperature at Choke Tdn Tup zup zoutlet ( Poutlet kk1 ) Pup 34 .Find CD by the graph The choke discharge coefficient CD can be determined based on Reynolds number and choke/pipe diameter ratio 4. 7 psia) P2 = downstream pressure. °R G = gas specific gravity (Air=1. psia Tb = base temperature.5 Q 77. dimensionless With considering the elevation T Q 77. Re = Reynolds number of flow.12. ft Always use absolute pressures. °R (usually 60+460=540 °R) T f = average flowing temperature of gas. dimensionless f = friction factor. psia Pb = base pressure.pdhengineer.00) Z = gas compressibility factor at flowing temperature and pressure. dimensionless H1 = upstream elevation.2 Weymouth Equation Tb P 21 e5 P 2 2 2. dimensionless D = pipe inside diameter e = absolute internal roughness of pipe.54 b Pb Le P 21 e5 P 2 2 GT f Le Zf 0.5 . dimensionless 5.667 Q 433.5 D 2. 1 e 2.5 Pipeline performance (www.51 ) 2 log10 ( 3.7 D Re f f f = friction factor. not gauge pressures. ft H 2 = downstream elevation. in.0375G ( H 2 H1 ) Tf Z s = elevation adjustment parameter.5 E ( )( )D Pb GT f Le Z E = Efficiency pipeline factor (0-1) 35 .1 General Equation Without considering elevation Tb P 21 P 2 2 2. mi D = inside diameter of pipe. in.com 2011) 5.54 D Pb GT f LZf Q = gas flow rate standard ft3/day (SCFD) L = pipe length. psia(usually 14. P1 = upstream pressure. L(e5 1) s s 0. 6182 D ) ( 0. °R Z = gas compressibility factor at pipeline conditions.5394 2.2 5. °R P = gas pressure. psia 36 .87 E ( Equation B: Q 737 E ( Tb 1.02 P 21 e5 P 2 2 0. psia T= gas temperature.3 Panhandle Equation Equation A: Q 435.8T f Le 0.51 2.6 Erosional velocity V 100 ZRT 29GP Z = gas compressibility factor.667 )( ) D Pb G 0.9 E ( Tb P 21 e5 P 2 2 0. °R G = gas gravity (air=1.8539 ) Pb G T f Le Z Tb 1. dimensionless 5.00) P = gas pressure.555 2. in.5. psia Tb = base temperature. Pb = base pressure.961 ) D Pb G T f Le Z 5.0788 P 21 e5 P 2 2 0.4 IGT (Institute Gas Technology) Q 136.002122( Pb ZT Qb )( )( ) Tb P D 2 V = average gas velocity.53 ) ( 0. dimensionless R = gas constant= 10. ft/s Qb = gas flow rate.5 Velocity V 0.73 ft3 psia/lb-mole R T = gas temperature. standard ft3/day (SCFD) D =inside diameter of pipe.