Abstract Downhole Gas Compression (DGC) is the new form of Artificial Lift Technology used to increase the productivity of gas wells. Surface compressors are commonly used to reduce the pressure at the wellhead, which in turn reduces flowing bottom hole pressure, and boost the well productivity for a gas well especially during its decline phase when average reservoir pressure falls to a value equal to the pressure in the wellbore imposed by the sales line at the surface, plus the pressure losses that occur in the gathering system and the tubing. This conventional technique is not very efficient for the gas wells that produce significant amount of liquid (water or condensate), since this liquid needs to be separated before reaching the gas compressor. In addition, it also requires additional space for compressor assembly into the well, which may be very challenging for wells in offshore and subsea environment. As an alternative to surface compressors, down hole gas compressors technique can be applied to increase the well productivity, especially gas wells in offshore and subsea environment. Some study claimed that this new technology could: increase more than 30% of gas production; resolve many multiphase related issues; and delay the onset of liquid loading. However, numerous challenges associated with design, development and implementation of this new technology are not well understood or documented. This study has been focused to understand the key concepts of the technology and explore its potential application for increasing well productivity of gas wells through sensitivity studies.

This paper presents principles mechanisms including theoretical background of DGC techniques, and results of sample case studies based on sensitivity analysis with aims to identify key factors to be considered for successful deployments of DGC into a gas well for natural gas reservoir. The paper also summarizes key findings which may be used as potential guidelines while considering for possible implementation of DGC technique during field development planning. Introduction Many forms of artificial lift methods, such as Electric Submersible Pump (ESP), Jet pump and Beam Pump or gas lift are commonly used to enhance the well productivity, especially during the decline phase of a reservoir when its pressure no longer provides sufficient bottomhole flowing pressure necessary to support fllowing pressure gradient and surface backpressure imposed at the bottomhole through wellhead. The technologies associated with such conventional arficial methods are explicitely designed to deal with oil wells. This technology may not be feasible for gas wells due to many limitations including physical limitations of dealing with gas phase. Generally for gas wells, central gas compression and/or wellhead compression are used, usually at the surface of a low pressure gas wells to minimize wellhead pressure by reducing the surface backpressure resulting in decreasing the flowing bottomhole pressure or increasing the drawdown, and thereby increases the reservoir inflow capabilities. This mechanism would provide an extra lift capacity of a well especially for depleted gas reservoir. This method is not as effective as conventional artificial lift methods applied in an oil well; and is limited by the suction capability of the compressor down the length of the production tubing, where it is required to overcome significant amount of flowing pressure gradient. As a result the well may require declaring early abandoned with leaving at least 30-40% of the original gas in the reservoir.

IPTC 16982

Potential Application of Downhole Gas Compressor to Improve Productivity for Gas Reservoir Md Mofazzal Hossain, SPE, MIEAust, Curtin University, and Mohd Dali bin Mohd Ismail, Curtin University

Copyright 2013, International Petroleum Technology Conference This paper was prepared for presentation at the International Petroleum Technology Conference held in Beijing, China, 26–28 March 2013. This paper was selected for presentation by an IPTC Programme Committee following review of information contained in an abstract submitted by the author(s). Contents of the paper, as presented, have not been reviewed by the International Petroleum Technology Conference and are subject to correction by the author(s). The material, as presented, does not necessarily reflect any position of the International Petroleum Technology Conference, its officers, or members. Papers presented at IPTC are subject to publication review by Sponsor Society Committees of IPTC. Electronic reproduction, distribution, or storage of any part of this paper for commercial purposes without the written consent of the International Petroleum Technology Conference is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of where and by whom the paper was presented. Write Librarian, IPTC, P.O. Box 833836, Richardson, TX 75083-3836, U.S.A., fax +1-972-952-9435

2 IPTC 16982

This conventional approach is also not very convenient in offshore environments. Different techniques are available for deep offshore gas well, where high capacity conventional compressors are used either at the wellhead or on the fixed platform or at the floating production system. Such compressors require high operating and servicing or intervention costs. As an alternative to conventional method of compression system, subsea compression system has been attracted considerable attention by the industry mainly due to reduced power requirements, since in such case compressor are installed near wellhead in subsea. This technique is found to be cost effective as compared to conventional platform based compression system. However, despite its relatively low power requirements or cost effectiveness, this technique poses many challenges in regards to installation, service requirement, and initial investment. Initial investment, operating and servicing cost are usually extremely high, which makes this techniques unattractive. A new form artificial lift technology introduced by Corac Group known as Downhole Gas Compressor (DGC) is specifically design for gas wells to increase productivity and maximize recovery factor of the reservoir. This DGC technology was claimed to be offered the opportunity to increase the production by 30~50%, and improve reserves significantly. This technology can accelerate early production; extent the production plateau in new gas developments; rejuvenate mature gas reservoirs characterized by low reservoir pressure in a costeffective manner; and maximize recoverable reserves by optimizing the gas well production performance (Liley and Oakely 2007, Liley and Verbeek 2004).

DGC is comprehensively different from the common compression as it is installed with the completion string like Electric Submersible Pump (ESP) completion. It can be placed as close to the well perforation as possible allowing gas production at a minimum abandonment pressure of the reservoir, and maximization of ultimate gas recovery. The DGC may give 20 – 40% gain of production which can be used anytime during production. The compression can be serviced using conventional workover operation similar to ESP servicing. This study, however, aims to establish the theoretical basis of DGC technology that may be used to analyse the performance of a well completed with DGC system for a natural gas reservoir; and evaluate the potential application of this technology based on sensitivity studies. This paper presents the theortically derived analytical model, detail parametric studies for vaious scenerios and investigates the effect of various parameters associated with reservoir conditions and well operating conditions on the production gain, when a well is completed with a DGC system.

An Overview and key features of DGC The DGC technology works following the same principles of artificial lift pump used in a conventional oil or liquid producing well. The flowing fluid experiences the pressure loss as it traverses through the tubing from bottom to the surface. The available bottom hole inflow flow pressure (BHIFP) has to support this flowing pressure loss plus the wellhead pressure as required to be maintained to support backpressure of surface facilities for a given operating condition. If this available BHIFP is less than the required flowing pressure loss plus wellhead pressure, the well will be ceased to flow. In such situation, DGC can provide extra pressure drawdown or necessary pressure support to make the well flow with a very low BHIFP at a desired rate. DGC is found to be applicable for both wet and dry gas fields, which have low average reservoir pressure deliverability and friction dominated tubing performance (Liley 2005). The DGC technology is also capable of optimizing the production system by minimizing flowing pressure gradient, and supporting the higher wellhead pressure. The flowing pressure gradient consists of three components: (i) pressure loss due to friction; (ii) hydrostatic pressure loss due to density of fluid; and (iii) well pressure loss due to acceleration of fluid. The last component is generally not significant as compared to other two components, and is usually neglected in calculation. The flowing fluid also requires overcoming necessary wellhead pressure imposed into the well from the downstream gathering systems. However, the frictional pressure gradient for single phase laminar flow condition increases proportionately with velocity but this proportionality will be complex in case of turbulence flow. It is also a function of the relative roughness of production tubing. In other words, the higher the velocity of fluid causes a higher pressure loss across the tubing. The hydrostatic pressure loss depends on the density of the gas, and the vertical distance between the wellhead and the point of interest in the well bore (usually bottomhole). The wellhead pressure is constrained by requirements of surface facilities or gathering systems and is determined based on pressure required to support the backpressure of gathering systems. The lifting capacity or overall gas production rate can be increased considerably by reducing any of the pressure components discussed earlier. The DGC is able to do this by compressing the low pressure gas entering the tubing immediately after it departs the bottomhole. As a result, the density of this compressed gas will be increased allowing a decrease in gas velocity for the same mass flow rate (volumetric flow rate for given tubing size); and hence minimizes the frictional pressure loss (Liley, and Verbeek, 2004); and boost the overall gas production rate. This will also help reduce tubing erosion inside the production tubing by minimizing the risk of occurring turbulence flow of gas.

IPTC 16982 3

Furthermore, the placement of the DGC plays an important role in reducing total pressure losses. By placing the DGC closer to the perforation of the well, the suction pressure it receives would be relatively high requiring a minimal compression ratio that can provide significantly higher discharge pressure from the compressor. The compression near the reservoir allows more gas to flow from the reservoir into the well by reducing the following bottomhole inflow pressure (BHIFP). The overall benefit achievable by installing DGC is that it reduces the FBHIP due to the suction pressure of the compressor resulting in a higher drawdown, which in turn lowers the abandonment pressure, and hence increases the recoverable gas reserves (Liley, Verbeek and Rijswijk, 2004). The other production benefit from the DGC is that it is a cost effective way to be used on mature gas wells (Bybee, 2009). For new gas wells, it can also be used to accelerate production rate and extend the life of the gas well (Tullio et al, 2009). While this innovative technology was being able to operate in downhole condition, various challenges needed to be addressed in order to come up with the right design for the compressor. One of the challenges is to design a compressor which can work in limited sized tubing with high temperature and pressure condition. In addition, a high speed motor needs to be designed in order to drive the compressor. The method of power distribution between the surface and the compressor is also needed to be taken into consideration. Other obstacle is the lubricant system of the compressor which needs to be worked out as a conventional system cannot be used in harsh downhole condition.

Similar to multistage ESP, DGC contains a number of compressoin modules arranged in series. Each module consists of a high speed compressor driven by permanent magnet motor supported on gas bearings, and powered by individual high frequency solid state inverters designed for a downhole environment (Geary et al, 2008). Electrical power is delivered downhole by a low loss DC link enabling up to 0.5 MW(670 hp) of wellbore compression power. From the first feasibility study on the DGC conducted by Liley et al, (Liley, and Verbeek, 2004), optimum compression power was found to be 0.5 MW (670 hp) for a well casing diameter of 9 5/8 inch. To be able to achieve the targetted power within available space, five modules of permanent magnet electric motor was placed in series with maximum output of 100KW(135 hp) per module. Figure 1 shows the compressor modules in series. Each module provide moderate pressure ratio with high flow rate. Three blade rows were also used to reduce the blade velocity and erosion. Low solidity blade design also helps, when one or more of the compressor module is shut down. Gas is still able to flow between suction and discharge section, thus flow is not constraint when the system fails. Consideration was also taken towards the change of reservoir condition over time, which leads towards an independent modular control with wide compressor operating range. This help in extending the operability of the DGC.

Figure1: Compressor Module Stack up (Liley, and Verbeek, 2004) As reported by Geary (2008), the one of the major elements in the technology of DGC is the low loss electrical power delivery system using downhole power invertors. The system consists of two sections, which is the electronic package located at the compressor inlet and the surface power feed located near the well head. These two sections are connected by a cable located outside of the production tubing which relay signals and power to the compressor. A supply transformer was used to transfer electrical energy from the supply to downhole system. Voltage dips was prevented by adding a pre-charge and pre-magnetisation inside the system. Permanent magnet motors were used rather than induction motor as its ability to operate at

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IPTC 16982

IPTC 16982 5

In Equation2, P1, and P2 are respectively, upstream and downstream pressure in psi within the segment of tubing of length, L

ft, with inner diameter of D inch for a given gas flow rate of q Mscf/d; at an average temperature of oR. g is the specific gravity of gas; θ is well inclination with respect to horizontal (e.g. for a vertical well, θ = 90°); and is the average gas compressibility factor. The average value of and gas viscosity are to be calculated based on PVT properties of gas considering an average temperature and pressure prevailing at the point of interest with an equation of state or an appropriate correlation. ff is the fanning frictional factor, which is to be obtained from Reynolds number and pipe surface roughness for laminar flow, or using an appropriate correlation for turbulent flow. The friction factor can be expressed in term of Moody

friction factor, fm as , which also can be obtained using Moddy friction factor diagram (Moody, 1944). For fully

turbulent flow, Katz and Lee’s (Katz and Lee, 1990) correlations may be used for a range of oilfield tubings, and give by:

.. , 4.277 (3)

.. , 4.277 (4)

Equation 2 can be used to approximate the pressure drop (P1-P2) in a single phase gas wells (natural or dry gas) over a tubing segment of interest. However, since Z factor is a strong function of pressure and temeperature that vary with the position or the length of tubing segment, Equation 2 needs to be solved iteratively using a numerical technique such as Newton–Raphson or successive substitution, and consequencely the approximate solution of Equation 2 could be erroneous, depending the length of the segement or flow distance to be considered during calculation. The longer the flow distance, the larger will be the error. To minimize the error, it is necessary to divide the well into multiple segments with as small length (measured depth) as possible. Pressure Drop across a Gas Well Completed with a DGC The standard pressure drop calculation as decribed earlier (Equation 2) is modified by adding a compressor in an arbitrary location within the production tubing. Figure 3 illustrates the typical set up in case of a well completed with DGC system, in which Equation 3 is applied to establish the relationship between compressor discharge pressure, Pd and wellhead pressure, Pwh, and is given by Equation 5:

2.685 10

1 where, .

(5)

Figure -3: Production set up with DGC Once the discharge compressor pressure Pd is calculated from known wellhead pressure, Pwh, the suction pressure, Ps is then calculated by knowing the compression ratio, R, of the compressor using Equation 6:

(6)

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L1

Pwh

Pd

Ps

Pwf

6

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(7)

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2.685 10

1 , where .

(8)

Equations 5, 7 and 8 are used to calculate the outflow performance of a natural dry gas well completed with DGC. In these equations, Z factor can be estimated by knowing pseudo-crtitical pressure (Ppc) and pseudo critical temperature (Tpc) values for a particular gas system. However, Z factor is often calculated by using Standing and Kartz chart (1954) for natural gas system, when the details of gas compostion are available. Many correlations available in the literatures are developed based on this chart to be readily adoptable for compution by personal computer. Correlation presented by Hall and Yarborough (1973) is developed based on an equation-of-state, which accurately represents the Standing and Katz Z-factor chart, and found to be more accurate to cacluale this factor for natural gas system (Ahmed 2004). In this study Hall and Yarborough correlation is used to calculate this Z factor. Since this study has been focused on natural dry gas reservoir, and exact composition of gas system is not known, correlations of natural gas systems given in Equations 9-10 (Ahmad 2004) are used to calculate pseudo critical pressure and temperature of the gas for known gas gravity.

168 325 12.5 (9)

677 15 37.5 (10)

The outflow performance equations as described above can now readily be applied to predict the production performance of a well (both naturally flowing and with DGC enable artificial lifted options) in combination of inflow performance relationship (IPR) and properties of gas using nodal analysis concept utilizing the MS Excel spread sheet program. The IPR used in this study is based on exact analytical equation for circular drainage vertical gas wells as given by Equation 11.

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As mentioned earlier, Z-factor required for Equation 11 is calculated using Hall and Yarborough correlation. The viscosity is calculated using the Carr-Kobayashi-Burrows correlation (Carr et al, 1954). The details of these correlations can be found in any standard reservoir engineering text book (e.g Ahmed, 2004). The production benefits achievable by DGC system can now easily be evailauted by inflow and outflow performance analysis, and comparing the production profiles for both with and woithout DGC (non-DGC) over the well’s lifecycle using the analytical model described above. The percentage of production gain achievable can be calculated by:

IPTC 16982

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Table 3 - Comparison of PROSPER-MBAL-GAP model and Analytical Model

Optimum Flow Rate (MMscf/d)

Modelling Method Non DGC DGC Production Gain

(%)

Mathematical 20.20 24.60 21.78

Software 21.15 25.91 22.49

Deviation (%) 4.71 5.33 3.2

Sensitivity Studies and Discussion The sensitivity studies are performed using the developed spreadsheet program employing the derived analytical model to anlyze the production performance of a dry gas well with and without DGC. The aims of this sensitivity study are to: investigate the parameters affecting the inflow and outflow performance of a gas producing well completed with DGC system; determine the most sensitive parameters affecting the performance of the DGC, and justify the potential application of the system. The well configuration and paramters for reservoir, and gas properties used for model validation are considered as base case for sensitivity study. The parameters considered in sensistivity studies are: reservoir deliverability; well completion parameters; and well head pressure. Reservoir deliverability covers sensitivity on reservoir pressure, reservoir permeability and reservoir thickness. Well completion parameters covers sensitivity on production tubing diameter, depth of DGC, well length and compression ratio of the compressor. The sensitivity of each paramters are observed and discussed in this section. Reservoir Pressure Pressure gives a high impact towards the behaviour of dry gas as it is a low density fluid with high coefficient of isothermal compressibility. While gas is flowing up the tubing, pressure starts dropping, which results the expansion of the gas, and hence increases the flow velocity of the gas. This promotes increasing in frictional pressure resulting higher pressure losses across the flowing tubing. From Figure 6, it can be seen that higher reservoir pressure can offer higher flowing capacity of well. The comparison between well completed with DGC and without DGC (termed as non-DGC) shows that the well completed with DGC gives a better view with respect to the reduction of pressure loss. The results are summarized in Table 4, which show that a higher reservoir pressure gives a better production gain. Even as the reservoir starts to deplete, the production gain retains about 20% giving the compressor to operate for a longer period of time for a given wellhead pressure. It also confirms that well would continue to flow at low reservoir pressure, when it is completed with DGC.

Figure 6: Reservoir pressure sensitivity 

Table 4: Reservoir pressure sensitivity result

Optimum Flow Rate (Mscf/d)

Reservoir Pressure (psia)

Non DGC DGC

Production Gain (%)

2,000 13,000 15,800 21.54

2,800 20,200 24,600 21.78

3,000 22,000 27,000 22.73

4,000 30,800 37,800 22.73

Reservoir Permeability From Figure 7, it can be seen that the IPR curves are strongly influenced by permeability. Thus, it shows higher production gain while using the DGC for a high permeable reservoir. Results from Table 5 shows that the DGC gives significant increase in production rate gain with higher permeability values. Higher value of permeability gives better inflow capability and hence higher gas flowrate, even at low drawdown, which offsets the pressure losses across the reservoir and the completion tubing. This shows that better reservoir deliverability helps promote more production gain with the help of DGC.

0

1,000

2,000

3,000

4,000

5,000

0 10,000 20,000 30,000 40,000 50,000 60,000 70,000 80,000

Pwf(psia)

Qg(Mscf/d)

DGC

NonDGC

IPR(R.Pres.=2000)

IPR(R.Pres.=2800)‐Base

IPR(R.Pres.=3000)

IPR(R.Pres.=4000)

IPTC 16982

IPTC 16982 9

Figure 7: Reservoir permeability sensitivity

Table 5: Reservoir permeability sensitivity result

 Optimum Flow Rate

(Mscf/d) Permeability

(mD) Non DGC DGC

Production Gain (%)

5 10,200 11,200 9.80

10 15,500 17,600 13.55

20 20,200 24,600 21.78

40 23,500 30,000 27.66  

   Reservoir Thickness Sensitivity of reservoir thickness behaves similar to reservoir permeability. There is significant increase in inflow rate with the increase in reservoir thickness, as clearly shown in Figure 8 for a vertical well. This should be due to higher enclosed/contact area of the reservoir at the well interface, which provides with a greater inflow capability, and hence higher gas deliverability. As can be seen from Table 6, the percentage of production gain is substantial resulted by the increased reservoir thickness, revealing that the DGC offers substantial boosting of productivity of a vertical well for a thick and high permeable reservoir as compared to thin and low permeable gas reservoir. This should be even more beneficial for horizontal well due to higher reservoir contact area resulting higher deliverability.

Figure 8: Reservoir thickness sensitivity

 

Table 6: Reservoir thickness sensitivity result

 Optimum Flow Rate

(Mscf/d) Reservoir

Thickness (ft) Non DGC DGC Production Gain (%)

50 15,500 18,000 16.13

100 20,200 24,600 23.50

200 23,500 30,000 27.66  

Well Completion Parameters Optimizing total pressure loss across a production system is the main concern of successful design of a completion string. However, by looking into well completion parameters, the amount of production gain, which can be achievable by the DGC, would help reduce pressure loss across the tubing. Well completion parameters covered in this sensitivity study are: production tubing diameter; well length; depth or placement of DGC; and compression ratio of DGC. Most of these parameters will affect the outflow or vertical lift curve. Note that the DGC power requirements and operating performance analysis is beyond the scope of current study. Tubing Diameter The increase in tubing size, in general should increase the gas flow rate at a given flowing bottom hole pressure. The tubing sensitivity results are presented in Figure 9, in which it is observed that by increasing tubing diameter from 2.875 inch to 4.5 inch, the well completed with DGC still gives higher gas production as compared to without DGC well (non-DGC). It can also be observed that the percentage of production rate gain for a well completed with DGC reduces as the size of the tubing increases (as shown in Table 7) inferring that DGC would be more beneficial for small diameter tubing as compared to large diameter tubing. This could be due to the fact that DGC system offsets considerable frictional pressure loss by compressing the

0

500

1,000

1,500

2,000

2,500

3,000

3,500

0 10,000 20,000 30,000 40,000 50,000 60,000 70,000 80,000 90,000

Pwf(psia)

Qg(Mscf/d)

DGC

NonDGC

IPR(k=5)

IPR(k=10)

IPR(k=20)‐Base

IPR(k=40)

0

500

1,000

1,500

2,000

2,500

3,000

3,500

0 10,000 20,000 30,000 40,000 50,000 60,000 70,000 80,000 90,000

Pwf (psia) 

Qg(Mscf/d) 

DGC

Non DGC

IPR (h=50)

IPR (h=100) ‐ Base

IPR (h=200)

10

gas. Thus tubing size plays substantial role towards the production gain with DGC system. Although this study only considered dry gas, and liquid loading issue was not investigated, DGC is however, found to be applicable for both wet and dry gas fields, which have low average reservoir pressure deliverability (Liley 2005).

Figure 9: Tubing diameter sensitivity

Table 7: Tubing sensitivity result

Optimum Flow Rate (Mscf/d) Well Flowing Pressure (psi)

Tubing Size (inch)

DGC Non DGC Production Gain (%)

DGC Non DGC Reduction of Pressure (%)

2.875 20,200 24,600 21.78 2,100 1,900 9.52

3.5 27,800 31,600 13.67 1,810 1,560 13.81

4.5 37,500 40,500 8.00 1,200 950 20.83

Well Length Sensitivity analysis was also conducted to investigate the effect of well length on the productivity gain with DGC system. In this sensitivity analysis, the same initial reservoir pressure was considered. In this case, the compressor was placed at the mid perforation, and the depth of the well head to compressor is increased, and result was plotted in Figure 10. It can be observed from Figure 10 that DGC completed well still gives better production rate as compared to well without DGC (non-DGC); and productivity increases with increasing the well depth. The results are also summarized in Table 8, in which it is observed that the production gain of the DGC is much higher when the well depth is increased. It is obvious that the well depth also plays a significant role to deliver an optimal rate of production while the well is completed with DGC, confirming that DGC is more beneficial for deep gas wells.

Figure 10: Well length sensitivity

Table 8: Well length sensitivity result

Optimum Flow Rate (Mscf/d)

Well Depth (ft)

Non DGC DGC

Production Gain (%)

3,000 26,000 28,500 9.62

6,000 20,200 24,600 21.78

12,000 14,800 19,600 32.43  

0

500

1,000

1,500

2,000

2,500

3,000

3,500

0 10,000 20,000 30,000 40,000 50,000

Pwf (psia) 

Qg(Mscf/d) 

DGC (OD=2.875) Non DGC (OD=2.875) DGC (OD=3.5)

Non DGC (OD=3.5) DGC (OD=4.5) Non DGC (ID=4.5)

0

500

1,000

1,500

2,000

2,500

3,000

3,500

0 10,000 20,000 30,000 40,000 50,000

Pwf (psia) 

Qg(Mscf/d) 

Non DGC (L=6000) DGC (L=6000)

Non DGC (L=3000) DGC (L=3000)

Non DGC (L=1200) DGC (L=1200ft)

IPTC 16982

IPTC 16982 11

DGC Depth The aim of DGC depth sensitivity is to investigate the effect of the placement of DGC within the well on the well performance. In this sensitivity study, the DGC depth is referenced from the well head to the depth of the DGC. For the same tubing completion, the deepest depth of DGC is considered closer to the mid perforation of about 5900 ft. Figure 11 shows the sensitivity results of the four different DGC depths. As can be seen from Figure 11, the higher depth of DGC leads to a higher production gain as compared to well completed without DGC (non-DGC). The maximum gain is achievable when the DGC is placed closer to the mid perforation (5500 ft). This is because the DGC placed close to the mid perforation leads to compress the gas immediately leaves the bottomhole of the well allowing gas to be energized by compression, which saves the inflow pressure and offset the component of frictional pressure across the tubing. This finding is in line with the result from Table 9, which shows that by the increment of every 500 ft closer to the perforation, an extra production rate gain of 3% on average is achievable.

Figure 11: DGC depth sensitivity 

Table 9: DGC depth sensitivity result

DGC Depth (ft)

Optimal Flow Rate (Mscf/d)

Production Gain (%)

4,000 24,100 16.18

4,500 24,600 17.89

5,000 25,500 20.78

5,500 26,500 23.77  

Compression Ratio The sensitivity of compression ratio of DGC system for a given flow rate are plotted in Figure 12. The compression ratio normally depends on the gas flow rates. Increasing the compression ratio results in decreasing the velocity of gas, but increases the mass flow rate or volumetric flow rate (for a given tubing size), as can be seen in Figure 12. The results are also summarized in Table 10. Result in Table 10 shows that increasing the compression ratio by 0.5, significantly increases the production gain of the well completed with DGC. Increasing compression ratio from 1.5 to 2 results an increase in production rate gain of 12.85 %, where as an increase of 2 to 2.5 just increase the production rate gain of 7%. The imcremental production gain, thus, is not a linear function of compression ratio. However, compression ratio is associated with compressor’s driven power. Higher the compression ratio, the higher operating power required to run the system. Therefore, higher compression ratio is not necessarily guarantee always the higher production rate gain, and thereby an optimal operating condition should be maintained in order have a certain economic benefit.

Figure 12: Compression ratio sensitivity

Table 10: Compression ratio sensitivity result

 Compression

ratio Optimal Flow Rate

(Mscf/d) Production Gain

(%)

1.5 24,600 21.78

2.0 27,200 34.65

2.5 28,600 41.58

  

0

500

1,000

1,500

2,000

2,500

3,000

3,500

0 10,000 20,000 30,000 40,000 50,000

Pwf (psia) 

Qg(Mscf/d) 

Non DGC DGC (Depth=4000ft)

DGC (Depth=4500ft) DGC (Depth=5000ft)

DGC (Depth=5500ft)

0

500

1,000

1,500

2,000

2,500

3,000

3,500

0 10,000 20,000 30,000 40,000 50,000

Pwf (psia) 

Qg(Mscf/d) 

Non DGC DGC (Comp.Ratio=1.5)DGC (Comp.Ratio=2) DGC (Comp.Ratio=2.5)

12

Well Completion Parameters It can be seen in Figure 13 that the well completed with DGC performs better at higher wellhead pressure (WHP) as compared to well without DGC (non-DGC). The results are also summarized in Tables 11, which show that slightly increase in WHP, decreases the operating flow rate in both cases. However, well completed with DGC allows higher production rate. This shows that the DGC is suitable to be used on production system with higher WHP, whereby the surface facility does not need to be changed. DGC would provide better surface pressure operating window for a desired rate of production over a range of pressure depletion.

Figure- 13: Well Head Pressure Sensitivity 

Table 11: Well head pressure sensitivity result

Optimum Flow Rate (Mscf/d)

WHP (psia) Non DGC DGC

Production Gain (%)

250 20,800 25,100 20.67

500 20,200 24,600 21.78

1,000 18,900 24,000 26.98  

This study is focused on natural gas systems with an emphasis on the understanding of the key concepts of the technology and investigation of its potential application for increasing well productivity through sensitivity studies. The sensitivity results presented may vary significantly for wet or condensate gas system. Futher study is required for wet and condensate gas systems. Economical analysis should also be conducted to study the feasibility of DGC technology. Conclusion The DGC technology may be considered as a viable form of artificial lift technology for natural gas well. It can increase production rate or well productivity by compressing the low pressure gas downhole, and offer production gain of about 20 – 30 % depending on various conditions associated with reservoir, wellbore and other completion parameters, and play significant role in case of increasing the well productivity for a depleted gas reservoir and/or well with higher operating wellhead pressure. However, based on the sensitivity analyses for a given well scenario in case of dry natural gas system, following conclusions are made:

The best candidates well for the DGC are deep depleted gas well with medium to high reservoir deliverability. Well with high well head pressure are also favourable to the use of the DGC.

The placement of DGC may affect the overall performance. In general DGC placed deeper depth or closer to the mid perforation would provide higher production rate gain for a given compression ratio. The optimum placement should be considered in combination of productivity, operational needs, other completion constraints, and compression ratio.

Compression ratio of DGC plays vital role. The productivity gain is controlled in combination of compression ratio and operating power requirement. These parameters need to be optimized towards the maximization of the production rate gain.

The production performance of well with DGC is very sensitive to parameters such reservoir deliverability (permeability-thickness), reservoir pressure, well tubing diameter, well length, well head pressure, and compression ratio. These parameters play key role in selection of this technology, and need to be optimized.

Nomenclature

Inclination angle of the tubing Specific gravity of gas

0

500

1000

1500

2000

2500

3000

3500

0 10000 20000 30000 40000 50000

Pwf (psig) 

Qg(Mscf/d) 

Non DGC (WHP=250psia) Non DGC (WHP=500psia)

Non DGC (WHP=1000psia) DGC (WHP=250psia)

DGC (WHP=500psia) DGC (WHP=1000psia)

IPTC 16982

IPTC 16982 13

BHIFP Bottom hole inflow flow pressure D Tubing inner diameter, inch DGC Downhole Gas Compressor Dqg Rate dependent skin (non-Darcy effect) ESP Electric Submersible Pumps ff Fanning frictional pressure fm Moody friction factor h Reservoir thickness, ft IPR Inflow Performance Relationship k Reservoir permeability, md L Length of the tubing m(p) Pseudo-pressure function, psi2/cp Non-DGC Well completed without DGC (natural flowing well) q Flow rate, MSCF/day qg Gas flow rate, MSCFD/d re drainage radius, ft rw well radius, ft S Total skin T Temperature WHP Wellhead Pressure

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