Production Data Analysis for Electric Submersible Pumped (ESP) Wells

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Production Data Analysis for Electric Submersible Pumped (ESP) Wells

Dr. Osman Farag Mohamed
Petroleum Engineering, PhD Ýí Petronas
Malaysia


Production Data Analysis for Electric Submersible Pumped (ESP) Wells

Analyzing well performance is an important step toward increasing profits by improving production techniques. The analysis is made by field tests and examination of well data. The pump intake pressure and bottom-hole pressure are extremely important factors in analyzing Electric Submersible Pumped (ESP) well performance. Usually, the bottom-hole pressures for ESP wells are determined by an acoustic well sounding technique (recording fluid level in the annulus). But this method can not be used if the annulus is to be packed off (a packer used).

The objective of this study is to develop a method capable of calculating the pump intake pressure (PIP), the bottom hole flowing pressure (BHFP), the dynamic fluid level (DFL) & net liquid above pump (NLAP) for ESP wells using production and completion data only.

This method is based on supposing the well is natural flow (NF) from pump discharge to the surface. So, the pump discharge pressure is calculated by two phase correlations (Ha

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INTRODUCTION


Static and producing bottom hole pressures are important parameters for investigating the inflow and vertical lift performances of an oil well. There are different methods which can be used for determining bottom hole pressures of electric submersible pumped (ESP) wells:



1) Conventional pressure bomb: used if the ESP completion is equipped with Y-tool (by-pass system), usually the Y-tool is not used due to it's required large casing (not less than 9 5/8"), and the Y-tool plug can cause leakage and/or stuck. Generally, this method requires the following steps:

a. Switch-off the ESP,

b. Retrieve the plug of the Y-tool,

c. Install the pressure bomb at the bottom hole of the well,

d. Install the plug of the Y-tool above the pressure bomb,

e. Re-run the ESP and operate it for enough time,

f. Switch-off the ESP,

g. Retrieve the plug of the Y-tool,

h. Retrieve the pressure bomb,

i. Install the plug of the Y-tool, and

j. Re-run the ESP for operating the well.



It is clear enough, at this point, that the previously described method of BHFP measurement takes more time and it is economically infeasible (loss in oil production due to shut-in times). In addition, many expected problems may occur due to many wire-line jobs (six runs).



2) Pressure sensors: which may be installed with the down-hole pump assembly so that accurate pressure readings may be obtained whenever required, but the cost would be high if they were used in every pumped well in a field or area.



3) Acoustic well sounding technique: which records fluid level in the annulus, the bottom hole pressures are usually determined by this method. But this method can not be used if the annulus is to be packed off (a packer used).



It is clear enough that all the previously described methods of BHFP measurement require a device. Then, require added money.



Gibbs and Nolen3 and Podio et al4 introduced a well Analyzer's computer and A/D converter, that can be used in conjunction with an acoustic gas gun and microphone. The gas gun generates an acoustic pulse in the well-bore and the microphone converts the reflected acoustic pressure pulses to electrical signals, which are digitized by the analog to digital A/D converter and stored in the computer. The computer displays these signals and processes the data as introduced by software to automatically determine fluid level depth. To calculate the producing bottom-hole pressure, the casing pressure is measured at the time of fluid level determination. When liquid is present above the formation and gas is flowing upward in the casing annulus, the casing vent valve is closed and sequential measurements of casing-head pressure are made for approximately 10-15 minutes so that an accurate casing pressure build-up rate can be obtained. The program uses this rate and the annulus void volume to calculate the casing annulus gas flow rate. This allows determination of the gaseous liquid column gradient from empirical correlations. It is noted that the tubing joints should have the same length because the depth to the fluid level is computed by estimating the total number of collars from the surface to the fluid level.



Spath et al5 described a technique to exploit the measurements made below ESP installations to determine well and reservoir properties. Well testing using pressure gauges below ESP’s is not new; the key advantage of the technique described here is that the well and reservoir properties may be obtained more accurately with higher resolution and without shutting the well in. In addition, the properties may be continuously determined for purposes of real-time production management. The technique is based on changing the flow rate by using a variable speed device (VSD), which changes the frequency (Hz) of the power supplied to the ESP motor, the production rate of the well is perturbed about a nominal flow rate. The resulting variation in bottom-hole flowing pressure is measured and modeled using the appropriate theoretical reservoir response (type curves) and nonlinear regression. Once the reservoir model is obtained, the well and reservoir parameters are computed from the regression analysis; variation in the properties (e.g., skin, reservoir pressure or distance to fluid interface) can be continuously monitored. Knowledge of the well and reservoir properties, and their variation over time, from the described technique, allows operators to optimize production rates and recovery while minimizing capital investments and operating expenses.



El-noby16 discussed and evaluated the different practices and applications in concern of testing the naturally non-flowing wells. He recommend some appropriate methods to be used for monitoring and optimizing the well production performance. Also, new correlations have been proposed to identify the completion factors for each reservoir based on the actual productivity index measurements for better planning and forecast estimations.



The basic objective of this study is to develop a method capable of calculating the pump intake pressure (PIP), the bottom hole flowing pressure (BHFP), the dynamic fluid level (DFL) & net liquid above pump (NLAP) for ESP wells using production and completion data only.




PUMP PERFORMANCE CURVES



The performance curves of a submersible electrical pump (Figure 1) represent the variation of head, horsepower, and efficiency with capacity. Capacity refers to the volume of the produced fluid rate, which may include free and/or dissolved gas. These curves are for a fixed power cycle (normally 50 or 60 cycle) and can be changed with variable frequency controllers.



The head (in feet per stage) developed by a centrifugal pump is the same regardless of the type or specific gravity of the fluid pumped. But when converting this head to pressure, it must be multiplied by the gradient of the fluid in question. Therefore, the following can be stated7:



(pressure developed by pump) = (head per stage) × (gradient of fluid) ×

(number of stages) (1)



The total fluid rate (liquid plus gas) at any conditions of pressure and temperature is, then:



(2)



Where VF is formation volume’s factors.



When pumping gas with the liquid, the capacity and, consequently, the head per stage as well as the gradient vary as the pressure of the fluid is elevated from the intake value PIP to the discharge value Pdis. Thus, the above equation can be written as follows:



(3)



Note that parentheses are included to indicate that h and Gf are functions of the capacity V, which is given by Equation 2.



The gradient of the fluid at any pressure and temperature is given by:

(4)



but,

(5)



where W is the weight of the capacity V at any pressure and temperature, which is equal to the weight at standard conditions. Hence:

(6)





Substituting Equation 6 into Equation 4 gives:



(7)





ρfsc is the weight of 1 bbl of liquid plus pumped gas (per 1 bbl of liquid) at standard conditions, or:



(8)





Substituting Equation 7 into Equation 3 gives:



(9)





The total number of stages is obtained by integrating the above equation between the intake and the discharge pressures:



(10)



or:

(11)







For each pump, there is a capacity range within which the pump performs at or near its peak efficiency (see Figure 1). The volume range of the selected rate between the intake and the discharge pressures should remain within the efficiency range of the pump. This range, of course, can be changed by using a variable frequency controller.



HEAD PER STAGE



Calculating head per stage for submersible pumps is based on the head coefficients (as shown in Table 1) and the volume of the production rate as follows:



(12)







The production rate for submersible pumps is considered for two cases: pumping liquid only and pumping liquid & gas.



For liquid only:

(13)





For liquid and gas:

(14)





The head per stage which calculated from Equation 12 is based on fresh water. Then, the head per stage for viscous liquid need to the following:



Find equivalent water capacity (Qw) as follows:



(15)



Find the viscous head (h) as follows:



(16)



Where Cq & Ch are viscosity correction factors for capacity & head respectively, as shown in Table 2.



The head per stage (calculated from Equation 12) is based on 60 hertz motor frequency. Then, if the motor frequency is more or less than 60 hertz, the head per stage for this frequency need to the following:



Find equivalent capacity at 60 hertz (Q60) as follows:

(17)





Find the head @ motor frequency (hHZ) as follows:

(18)



TOTAL DYNAMIC HEAD



The total dynamic head developed by the pump is considered for two cases: pumping liquid only and pumping liquid & gas.



For liquid only, the head per stage is constant for all stages. Therefore, the total head given by:



(19)



For liquid and gas, the head per stage is changing from stage to stage. Therefore, the total head given by:

(20)




In case of pumping liquid and gas, the head per stage changes from stage to stage because the pressure changes from stage to stage, which may affect the production rate (volume capacity ) from stage to stage. The pressure at the last stage is equal to the discharge pressure of the pump:



(21)



Where the discharge pressure of the pump can be calculated from the two-phase flow correlations.


The pressure at the stage before the last stage is equal to the pressure at the last stage minus the pressure developed by the last stage, and so on:





(22)



(23)


Finally, the pressure at the first stage is equal to the pressure at the second stage minus the pressure developed by the second stage:

(24)

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PRESSURE DEVELOPED BY THE STAGE



Calculating pressure per stage for submersible pumps is based on the head per stage and the average specific gravity of the liquid:



(25)



where:







(26)







TOTAL PRESSURE DEVELOPED BY THE PUMP



The total pressure developed by the pump is considered for two cases: pumping liquid only and pumping liquid and gas.



For liquid only, the pressure per stage is constant for all stages. Therefore, the total pressure given by:



(27)



For liquid and gas, the pressure per stage is changing from stage to stage. Therefore, the total pressure is given by:



(28)







PUMP INTAKE PRESSURE


The pump intake pressure is equal to the discharge pressure of the pump minus the total pressure developed by the pump:



(29)



Where, as mentioned before, the discharge pressure of the pump can be calculated from the two-phase flow correlations.





BOTTOM HOLE FLOWING PRESSURE


Knowing the pump intake pressure (PIP), the bottom hole flowing pressure at mid of perforation can be calculated from the two-phase flow correlations assuming the flow pass into the existing casing.





DYNAMIC FLUID LEVEL



The dynamic fluid level in the well annulus can be determined as the following:



(30)







(31)





(32)







Where :

C = 100 for old pipe

= 120 for new pipe

= 150 for plastic pipe







NET LIQUID ABOVE PUMP



The net liquid above the pump can be determined as the following:







(33)

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RESULTS AND DISCUSSION

The new developed method is applied and the designed VISUAL BASIC computer program is used to calculate BHFP, PIP, DFL, and NLAP.



The required data to calculate the PIP, BHFP, DFL & NLAP showed in Tables 3, 4 & 5. The well bore data showed in Table 3 , The down-hole pump data showed in Table 4, and the production data showed in Table 5.



The Echometer surveys results from actual producing ESP wells showed in Table 6, these wells were selected from the Western Desert area of Egypt covering a wide range of a variations in their reservoirs, fluid properties, and ESP assembly.



Table 7 showed comparison between the measured and calculated values of DFL, NLAP, PIP & BHFP. The error% is calculated as the following:







(34)



Also, Figures 2, 3, 4, and 5 showed comparison between the measured and calculated values of DFL, NLAP, PIP & BHFP.



The results indicate that, the absolute error percent between the measured and calculated values of DFL, NLAP, PIP & BHFP is not more than 10%.





CONCLUSIONS



The pump intake pressure (PIP), the bottom hole flowing pressure (BHFP), the dynamic fluid level (DFL), and net liquid above pump (NLAP) in annulus for Electric submersible pumped (ESP) wells can be determined accurately by the developed method using the production and completion data.



The VISUAL BASIC computer language was used to design a computer program for an easy use.



Comparing the results obtained by the new method and the measured values of pump intake pressure (PIP), bottom hole flowing pressure (BHFP), dynamic fluid level (DFL) and net liquid above pump (NLAP) indicated a good agreement and shows that the new method is reliable and dependable to be used.





ACKNOWLEDGMENT



The authors would like to express their sincere thanks and appreciation to the Petroleum Engineering Department, Suez Canal University, for encouragement to publish this paper, and for the staff of the Khalda Petroleum Company (KPC) for their cooperation and providing field data.





NOMENCLATURE



Bw = the water formation volume factor, bbl/stb

Bo = the oil formation volume factor, bbl/stb

Bg = the gas formation volume factor, bbl/scf

C1, C2, C3, C4, C5 & C6 are head coefficients

DP = pump depth, ft

DFL = dynamic fluid level, ft

dP = the differential pressure developed by the pump, psi

d(St) = the differential number of stages

FT = tubing friction loss, ft

Gf = the gradient of the pumped fluid, psi/ft

GOR = produced gas oil ratio, scf/stb

h = the head per stage, ft/stage

hw60 = head per stage @ 60 hertz, ft (for fresh water)

HZ = the motor frequency, hertz

h60 = the head per stage @ 60 hertz motor frequency, ft

hHZ = the head per stage @ hertz more or less 60 hertz, ft

hst = the head per stage, ft

ht = the total dynamic head, ft

PC = casing pressure, psi

Pn = the pressure at the last stage (stage number n), psi

Pdis = the pump discharge pressure, psi

Pn-1 = the pressure at the stage before the last stage (stage number n-1), psi

Pn-2 = the pressure at the stage before the before last stage (number n-2), psi

P1 = the pressure at the first stage, psi

P2 = the pressure at the second stage, psi

PIP = pump intake pressure, psi

Pdis = pump discharge pressure, psi

Qw60 = the production rate @ 60 hertz, bbl/day (for fresh water)

Q = the production rate @ pump conditions (pressure & temperature), bbl/day

Qsc = the production rate @ standard conditions, stb/day

Q60 = the production rate @ 60 hertz motor frequency, stb/day

QHZ = the production rate @ hertz more or less 60 hertz, stb/day

Qo = oil production rate, stb/day

Qw = water production rate, stb/day

Rs = the solution gas oil ratio, scf/stb

st = the number of stages

TID = tubing inside diameter, in

WHPH = the well head flowing pressure, ft

WHP = well head flowing pressure, psi





Symbols



γw = water specific gravity

γavg = average specific gravity of the liquid

γg = gas specific gravity

γo = oil specific gravity

ρgsc = the density of gas (in lb/scf) at standard conditions.

∆Pp = the total pressure developed by the pump, psi

∆P2 = the pressure developed by the second stage, psi

∆Pst = the pressure developed by one stage (pressure per stage), psi

∆Pn = the pressure developed by the last stage, psi

∆Pn-1 = the pressure developed by the stage before last one, psi



REFERENCES



1. Hagedorn, A. R., and Brown, K. E.: “Experimental Study of Pressure Gradients Occurring During Continuous Two-Phase Flow in Small-Diameter Vertical Conduits,” JPT, 475-484, April 1965.



2. Beggs, H. D., and Brill, J. P.: “A Study of Two-Phase Flow in Inclined Pipes,” JPT, 607-617, May 1973.



3. Gibbs, S. G., and Nolen, K. B.: "Wellsite Diagnosis of Pumping Problems using Minicomputers," J.P.T., PP. 1319-1323, Nov. 1973.



4. Podio, A. L., McCoy, J. N., and Dieter Becker: "Integrated Well Performance and Analysis," SPE 24060, Western Regional Meeting, Bakersfield, California, March 30 – April 1, 1992.



5. Spath, J. and Martinez, A. D.: "Pressure Transient Technique Adds Value to ESP Monitoring," Paper SPE 54306 Prepared for Presentation at the 1999 SPE Asia Pacific Oil & Gas Conference and Exhibition Held in Jakarta, Indonesia, 20-22 April 1999.



6. Elnoby, M. G.: "Testing of The Naturally Non-flowing Wells," Ms. thesis, Submitted to Petroleum Engineering Department, Faculty of Petroleum and Mining Engineering, Suez Canal University, Suez, Egypt, 2003.



7. Brown, K. E., et al.: “The Technology of Artificial Lift Methods,” Vol 2b. Chapter 4. Tulsa, Oklahoma: The Petroleum Publishing Co., 1980.

[findaposition]

some equation is unavailble ,please upload the paper,

[DAH7542]

Could you share the paper in pdf format and the VISUAL BASIC program?

[shummo]

thanks a lot dear, but there is some missing ;would you pleas send me the full information to the below email
yashumo@yahoo.com