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SPE 120632

A New Nodal Analysis Technique Helps Improve Well Completion andEconomic Performance of Matured Oil FieldsM. Rafiqul Awal and Lloyd R. Heinze, Texas Tech University

Copyright 2009, Society of Petroleum Engineers

This paper was prepared for presentation at the 2009 SPE Production and Operations Symposium held in Oklahoma City, Oklahoma, USA, 4–8 April 2009.

This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not beenreviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, itsofficers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohibited. Permission toreproduce 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 SPE copyright.

Abstract

Mature fields lack the sparkle of a new play, and an operator typically will not invest capital for waterflooding, much lessEOR. But prevailing higher oil prices can turn such a mature oil field more profitable by employing innovative productionenhancement techniques. We propose the use of a simple, tapered tubing string completion (using larger internal diameter(ID) tubing pipes in the upper sections) that can be customized for specific reservoirs. Historically there are few instances oftapered ID tubing completion, which were basically necessitated by technical constraints (liner, workover, etc.). But ourapproach is focused on enhancing economic performance. We have employed nodal analysis technique to develop anequivalent tubing diameter (ETD) concept. The ETD allows for comparing the well performance for single-ID tubingcompletion. The procedure also seeks an optimum length for the larger tubing ID in the upper section. Using reservoirsimulation for full life cycle, and oil prices projected over time until abandonment, the economic performance is evaluatedusing NPV and other economic parameters.

The proposed production enhancement method is suitable for wells with moderate to high open flow potentials (AOFP). It is

especially suited for low GOR wells with high future water-cut that will eventually require an ESP system, and also remoteoilfields, where reservoir pressure maintenance and EOR is not viable.

The use of larger tubing ID section entails only a marginal increase in CAPEX. However, the tapered completion givesincreased production rate sustained over a long time, which results in significant economic gain. The economic benefitsaccrue from the prevailing high oil price, yielding a quick payout and many returns on investment.

The proposed completion approach does not involve complexity, and the innovative application of nodal analysis coupledwith high oil prices show how to make mature oil fields onshore and offshore, more profitable.

Introduction

Nodal analysis was performed in the sixties and seventies by hand calculations, using vertical pressure traverse graphs

generated in-house by big oil companies. Smaller operators, if they at all used nodal analysis, relied on Brown’s (1963)famous pressure traverse graphs. The workflow was tedious at best, discouraging engineers to explore for horizons that nodalanalysis could lead to. However, with the advent of affordable PC software (e.g., Fekete’s FAST™, IHS’s PERFORM™,etc.), and even MS-Excel™ based spreadsheet programs (e.g., Guo et al. 2007), the power of nodal analysis now can beunleashed even in a classroom setting. One such unexplored horizon is tapered tubing string design – with gradually largerinternal diameter (ID) in the upper sections of tubing string.

Conventional tubing string design entails selecting a constant internal diameter for all the tubing sections—from bottom totop. The upper sections of the string, however, have a greater wall thickness to support the load of the string below. Thusconventional tubing strings are tapered in terms of outer diameter ,which is necessitated by mechanical loading requirements.

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The idea of TIDC is not entirely new, as can be seen in the definition of tapering string for production that exists in theliterature: “A tapered production string may be configured with larger OD tubing sections in the upper wellbore area tooptimize the hydraulic performance of the string,” (Schlumberger [1]).

However, an extensive search of published literature has revealed few applications of the tapered ID string concept foroptimizing production. Trenchard & Whisenant (1935) reported probably the earliest case of tapered tubing stringcompletion, which was necessitated by well flow back problems that occurred after shut-in. Conventional methods to flow

back a well in such cases included: pumping, flowing with the aid of valves, and tapered tubing. The tapered tubing stringmethod was found to be quite satisfactory. It usually consisted of a string of pipe, half of which is ¾-inch, and the other half,1-inch. The use of the tapered tubing afforded a more continuous flow and probably a smaller amount of injected gas at thestart.

Frederick & DeWeese (1967) reported a similar tapered tubing string in the famous well, "Kaplan Caper" in South Louisiana.In order to flow the well after initial completion, a tapered macaroni string was installed inside the production tubing (ID).

Golan and Whitson (1986) reported the use of a smaller size (ID) of tubing in the liner section of well. In this case, thesmaller tubing size (OD, 27/8) was necessitated following casing collapse above the pay zone. The collapsed section wasrepaired by placing a liner inside it. The smaller tubing size was connected to the existing upper tubing (3½-in.) section via acrossover (Fig. 1)

Schlumberger [2] reported using a tapered tubing string of 5.5 to 7 in. in a condensate well with a high GOR. The well was producing 5500 BOPD with a gas/oil ratio of 9600 SCF/STB through a mono tubing completion consisting of a 7-in.liner. Inorder to avoid liquid loading, a tapered tubing string of 5.5 and 7 in. was used, which caused a fluid velocity increase inexcess of the critical velocity of 8 m/s at a flowing wellhead pressure of 1,430 psi.

The most recent case of tapered-string tubing is reported by Tibbles et al. (2004). The well produced at 2,147 STBO/d before hydraulic fracturing was considered. Pre-fracturing nodal analysis indicated a high AOFP using the designed hydraulicfracturing parameters. In order to lift the increased volumetric throughput, a larger ID tubing string was needed. A taperedtubing string (4½-in. tubing from surface to 5,000-ft, and 3½-in. tubing from 5,000-ft to 5,892-ft.) string indicated a production rise to 3,145 STBO/d. After fracturing, the measured flow rate was 3,101 STBO/d.

A cursory look at both API and non-API tubing sizes shows two limitations on actual tubing internal diameter (ID) sizes:

1. There is no size greater than 3.958-in., and

2. There is only a finite range of sizes: from 0.824-in. to 3.958-in.

The available tubing ID sizes are shown in Table 4. The second limitation on tubing ID size poses a practical problem: Howdo we implement the optimum tubing ID size determined from nodal analysis? In our knowledge, the E&P industry has so farducked this problem by restricting nodal analysis for optimum tubing size to the available commercial API and non-APIsizes.

Conventional Tubi ng size optimization procedure for maximizing fl uid f low rate:

The routine procedure includes the following steps:

• Perform nodal analysis for a given well using all or a few of the tubing sizes available (See Table 1).

• Plot a graph of fluid flow rate vs. tubing size (ID), and select the tubing size, di-opt, that corresponds to the highest

fluid flow rate.• If di-opt is not a standard tubing size, select the nearest standard size, which could be either greater or smaller than di-

opt.

The above procedure is thus a compromise between theory and practice. In this paper, we present an unconventional taperedstring: that of using larger internal diameter tubing pipes in the upper sections of the well. For the sake of discussion, we willrefer to this idea as Tapered Internal Diameter Tubing Completion (TIDC).

Motivation for TIDC

In this paper, we re-introduce the concept of TIDC for the following reasons:

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1. Techni cal r equir ements:

(i) Even with the most rigorous PVT and fluid dynamics modeling that goes into modern nodal analysis software,

the most optimum tubing (ID) size cannot be realized, simply because the design engineer is forced to select the next

best size manufactured commercially. Both API and non-API tubing pipes come in all but a few sizes. With TIDC,

the most optimum tubing size can be selected using the equivalent tubing diametr (ETD) technique presented in this

paper.

(ii) Toward the end of natural flow in the life cycle of an oil well, an artificial lift method (ALM) must be used. With

the advent of high efficiency gas removal system (e.g., helico-axial multiphase pump installed at an ESP intake,

Schlumberger [3]), the electric submersible pump (ESP) has become more popular, Fig. 3. And in fields where

edge-water or bottom-water drive eventually causes high water-cut (WOR). In such cases, even for a minimum

economic production rate of 10 STBO/d, a very high water production rate may result (e.g., 90 STBW/d @ 90%

WOR). In the Middle Eastern oil fields (Dogru et al., 2004; Saadawi, 2007), a gross liquid volume rate of 2,000

STB/d may be necessitated to lift 200 STB/d oil @90% water-cut. Obviously, a tubing string designed previously to

lift 200 STBO/d neat oil may be quite undersized (ID).

2. Economic requirements:

(i) For the case shown in (1-ii) above, it is obviously more economic to recomplete the well with a tapered string

(TIDC) than use a larger bore constant ID string.

(ii) Due to high oil price experienced in recent years, re-completing a well with undersized tubing string with a

TIDC completion will give a quick return-on-investment and additional profit. The price has returned to ‘normal’ as

of writing this paper, but the probability of upsurge remains due to growing rise in oil consumption in the

developing countries.

Also, it is reasonable to assume that many a well completed in the 1970’s and before, and still producing (albeit at a lowerrate than in the early period of production due to reservoir depletion) did not enjoy optimum sizing that requires nodalanalysis. Excepting the big oil companies who could afford expensive mainframe computers, small operators relied on handcalculation-based nodal analysis using PVT and fluid dynamics modeling.

Results of Nodal Analysis using TIDC

Nodal analyses are performed for mono and the various TIDC completions depicted in Fig. 2 and Table 1, using thecommercial software, PERFORM™. The reservoir, well construction, PVT and well test data are shown in Table 2. Thenodal software has more than one correlation for both inflow performance (IPR) and tubing performance (TPR) relationships.In order to illustrate the use of TIDC, we have used Vogel & Harrison (1968) and Beggs & Brill (1973) correlations,respectively.

First, we run the base case with mono tubing completion, using five tubing ID sizes: 1.995, 2.441, 2.992, 3.476, and 3.958inches. The well performance graphs (Flowing bottomhole pressure vs. Fluid flow rate) are shown in Fig. 4. For water-cutranges from 50% to 60%, the stabilized gross liquid rate increases with tubing size until 3.476-in., then reverses at 3.958-in.,indicating that the di-opt value is somewhere between 3.476-in. and 3.958-in. This is shown clearly in Fig. 5. Obviously, thisoptimum tubing size is not available from commercial tubing pipes. This shows the need to use a tapered tubing string using

these two standard tubing sizes.

Next, we show the nodal analysis results for the Duplex TIDC realizations. The TIDC realizations shown are simplistic, i.e., the depth intervals for various tubing sizes in a TIDC completion are equal. The results are shown in Fig. 6. The DuplexTIDC gives significantly higher gross liquid rates at all three water-cut values, shown clearly in the Table 4 next to thegraph. This is a spectacular result, which shows that there could be more benefits in using a TIDC than expected intuitively.

For a given well, the length of the upper section in the Duplex TIDC can be optimized. The optimization procedure is simple:choose several values for length of the upper tubing section, and compare the stabilized flow rates. The procedure isillustrated in Fig. 7 for a Duplex TIDC. It reveals the optimum length of the upper section (larger ID, 3.958-in.) to be 3,600-ft, which much shorter than the smaller ID (3.476-in.), lower section: (9,990 – 3,600) ft = 6,390-ft.

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In the foregoing duplex TIDC optimized solution, the economic gains are significant, given the high oil price. The duplexTIDC gives increased gross fluid rates as follows:

• 10 to 15% compared to the 3.476-in. mono tubing completion, and

• 10 to 30% compared to the 3.958-in. mono tubing completion,

over the water-cut range of 50 to 70%.

The selection of the optimum length of the upper section can be further refined by including the concept of marginal utility ineconomics. This is illustrated in Fig. 8.

The increased fluid lifting performances of higher order TIDC completions are shown in Fig. 9. The same data have beenused, but Hagedorn & Brown correlation was used instead of Beggs & Brill’s.

Economic Analysis using Well Life Cycle

Before finalizing the tubing ID selection using mono or one of the various TIDC schemes discussed above, a completeeconomic analysis including cost and profits is in order. Affanaambomo (2008) presented economic analysis using the mono,duplex, triplex and quad completions. For this, a single well located at the center of a circular drainage volume is considered.The reservoir, well and PVT data are taken from Economides et al. (1993).

The economic analysis involves two major steps.

Step-1: Predict the reservoir depletion and well production performance for a specific tubing completion using Tracy’smaterial balance method, and nodal analysis. A MS-Excel spreadsheet program developed by Guo et al. (2007) isused for these calculations.

Step-2: Calculate, NPV, ROI, etc. using standard economic analysis method.

While Affanaambomo (2008) presented the economic analysis for duplex, triplex and quad completions, we show the resultsfor a duplex completion only. The data used for cost analysis are shown in Table 5.

NPV is calculated at 10% interest rate. Prices of oil and gas used are $126.2/bbl and $11.537/MMbtu as of May, 2008,

respectively. The cost of tubing pipes for outside diameters 2.378 in., 2.875 in., 3.5 in., and 4.0 in. are $ 4.02, 5.44, 7.76, and9.48 per foot as of May, 2008 respectively. Because the well is presumed to be in natural flow, operational expenditure(OPEX), development cost, and abandonment cost are not considered. In the economic analysis, only the different tubingcosts are considered, and consider all other cost components equal.

The economic analysis shows advantage of TIDC over mono tubing completion (Figs. 10 and 11).

Conclusions

In this exploratory work involving nodal analysis for optimizing tubing string ID for maximizing gross liquid production rate,the following observations are made:

1. The E&P industry only performs tubing ID optimization for mono tubing completion only. The use of tapered ID

tubing string are few, mainly motivated by workover and mechanical completion constraints.

2. This work is the first systematic study that explores the benefits of tapered ID strings.

3. The TIDC reveals non-intuitive, positive results over mono tubing completions. The production rate from a TIDC

could exceed the highest rate possible from any single tubing size.

4. The TIDC affords a means to use the theoretically optimum tubing size, by combining commercial sizes suitably.

5. In the high oil and gas price scenario witnessed in the past two years, attention to TIDC makes good economic

sense.

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Acknowledgements

The authors thank Fekete Associates, Inc., Calgary, Canada and IHC, Inc., Houston, USA for providing nodal analysissoftware.

References

Affanaambomo, B.O. 2008. Study Of Tapered In ternal Diameter Tubing String Well Completion F or EnhancedProduction. MS Thesis, Texas Tech University, Lubbock, TX. pp.77 – 180.

Beggs, H.D. 1991. Total system analysis, in Production Optimization: Using NODAL™ Analysis . OGCI Publications,Tulsa, OK. p.135

Dogru, A.H., Hamoud, A.A. and Balow, S.G. 2004. “Multiphase Pump Recovers More Oil in a Mature CarbonateReservoir,” SPE 83910 in Journal of Petroleum Technology, Feb.

Economides, M.J., Hill, A.D., and Ehlig-Economides, C. 1993. Petroleum Production Systems . Prentice Hall PTR, NewJersey, MD. p. 593 - 595

Frederick, B. and DeWeese, E., "Kaplan Caper," in Drilling, Vol/Issue: 28/9, June, 1967. p.34 - 39Golan, Michael, and Whitson, Curtis H., Well Perf ormance , 2nd ed. Englewood Cliffs,” Prentice-Hall, New Jersey, 1986.

p.77-78.Guo, B.W., and Gholambor, Ali. 2007. Petroleum_Production_Engineering-A_Computer_Assisted_Approach . Gulf

Publishing Company, Houston, USA.Saadawi, H. 2007. “An Overview of Multiphase Pumping Technology and its Potential Application for Oil Fields in the Gulf

Region,” SPE/IPTC paper 11720, Abu Dhabi, UAE. 4 – 6 December.Schlumberger [1]: Oilfield Glossary. http://www.glossary.oilfield.slb.com/Display.cfm?Term=tapered%20string Schlumberger [2]: “GHOST— Gas Holdup Optical Sensor Tool brochure,” SMP-5762, 2001.Schlumberger [3]: Case Study— Well Life Increased by a Projected 2 Years.

http://www.slb.com/content/services/resources/casestudies/artificial/poseidon_canada_profound.asp Tibbles, R., Ezzat, A., Mahmoud, K.H., Ali, A.H.A., and Hosein, P. (2004). "Hydraulic fracturing the best producer: A

myth?" presented at New Zealand Petroleum Conference, Auckland from 7-10 March. Slide #9-10.Trenchard, J. and Whisenant, J. B., "Government Wells Oil Field, Duval County, Texas," Bulletin of the American

Association of Petroleum Geologists Vol. 19, No. 8 August, 1935. p. 1131 - 1147.

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Figure 1. A practical example of TIDC, necessitated by reduced bottomhole diameter after inserting a

liner through the production casing (PC) following collapse of the lower section of the PC (Goan &Whitson, 1986).

Table 1. API and non-API tubing sizes(ID), inches.

Table 2. Tubing IDs for the mono and various TIDC realizations.

Tubing IDRealizations

Tubing size (ID), in.

1.995(Depth interval,

ft)


ft)


ft)


ft)

Mono tubing ID (0 – 9,990) (0 – 9,990) (0 – 9,990) (0 – 9,990)

Duplex TIDC (0 – 5,000) (5,000 – 9,990)

Triplex TIDC (0 – 2,500) (2,500 – 5,000) (5,000 – 9,990)

Quad TIDC (0 – 2,500) (2,500 – 5,000) (5,000 – 7,500) (7,500 – 9,990)

Table 3. Reservoir, well construction, and operating data (Beggs, 1991).

Parameter Value

Avg. reservoir pressure, psig 3,483

Bubble point pressure, psig 3,600

Flowing wellhead pressure, psig 400Mid perforation depth, ft 10,000

Tubing shoe depth, ft 9,990

Oil density,oAPI 35

Gas gravity (air 1.00) 0.65

Water-cut, % 50

GLR, SCF/STB 400

Well Test data:

Stabilized flow rate, STB/d 320

Flowing bottomhole pressure,psig

3,445

0.824, 1.049, 1.380, 1.610, 1.867, 1.995, 2.041, 2.441,2.259, 2.750, 2.992, 2.992, 3.068, 3.476, 3.548, 3.958

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(a) (b) (c)

Figure 2. Three realizations of tapered internal diameter tubing completion, TIDC, in order to optimize thefluid dynamics. (a) Duplex, (b) Triplex, and (c) Quad.

(a) (b)

Figure 3. Augmented productivity by modern ESP. (a) Production profile showing ESP operation beforeand after adding a helicon-axial gas handling pump. (b) The high-capacity gas handling deviceenables a greater percentage of free gas to be produced.

(Ref. Schlumberger [3]).

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3000

3100

3200

3300

3400

3500

3600

3700

3800

3900

4000

0 500 1000 1500 2000 2500 3000

p w f , p s i

g

Q L, STB/d

Tbg.ID=1.995-in.

Tbg.ID=2.441-in.

Tbg.ID=2.992-in.

Tbg.ID=3.476-in.

Tbg.ID=3.958-in.

IPR

0

500

1000

1500

2000

2500

1.5 2 2.5 3 3.5 4 4.5

G r o s s L i q u i d r a t e ,

S T B / d

Tubing ID, inch

W-cut: 50%

W-cut: 60%

W-cut: 70%

Figure 4. Well performance graphs (IPR and TPRs) for various standard tubing ID sizes in monoboretubing string completion.

Figure 5. Graphical method to determine the optimum tubing ID size for a mono tubing string.

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3000

3050

3100

3150

3200

3250

3300

3350

3400

3450

3500

0 1000 2000 3000 4000 5000

F l o w i n g b o t

t o m h o l e p r e s s u r e ,

p s i g

Gross liquid rate, STB/d

Mono-1

Mono-2

Dual

IPRWater-cut

% Mono-1 Mono-2 Dual

50 1911 1908 2137

60 1729 1635 2048

70 1554 1282 1854

Gross liquid rates, STB/d

1400

1500

1600

1700

1800

1900

2000

2100

0 2000 4000 6000 8000

G r o s s l i q u i d r a t e ,

S T B / d

Length of upper tubing, ft

Water-cut: 70%

Table 4. Comparison of mono and Duplextubing string fluid lift performance.

Figure 6. Comparison of mono and Duplex tubing string fluid lift performance. The length of the uppersection in a Duplex TIDC is 5,000 ft.

Figure 7. Graphical method to determine the opt imum length of the upper section in a Duplex TIDC. Forthis case, the opt imum length is approx. 3,500 ft. The lower section

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0

500

1000

1500

2000

2500

3000

3500

4000

200 400 600 800 1000

S t a b i l i z e d F l o w R

a t e , q

* L

( S T B / d )

GLR (SCF/STB)

Mono: 1.995@9990ft

Dual:2.441in@5000ft;

1.995@9990ft

Tripple: 2.992@2500ft;

2.441in@5000ft;

1.995in@9990ft

Quad:3.476@2500ft;

2.992@5000ft;

2.441@7500ft;

1.992@9990ft

Figure 8. Graphical procedure to optimize the length of the upper section of a Duplex TIDC.

Figure 9. Increased fluid lifting performances of various TIDC completions.

Length of upper section of tubing string

Stabilized flow rate

Q1

Q2

LU-1 LU-2

• Ideally, the optimum length of the upper

section should be LU-1., which

corresponds to the maximum production

rate, Q1.

•

But overall economics based onmarginal utility may dictate the optimum

length at LU-2

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Table 5. Data used for cost analysis (Affanaambomo, 2008).

Figure 10. Rate of and cumulative production overfull life cycle: mono and duplex tubing(Affanaambomo, 2008).

Figure 11. Net present value (NPV) over full lifecycle: mono and duplex tubing (Affanaambomo,2008).

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