petsoc-05-12-01

December 2005, Volume 44, No. 12 49

Dual Gas Lift in Wells WithDownhole Water Sink Completions

L. MARCANOPDVSA-Intevep

A.K. WOJTANOWICZLouisiana State University

PEER REVIEWED PAPER (REVIEW AND PUBLICATION PROCESS CAN BE FOUND ON OUR WEB SITE)

Dual Gas LiftState of the ArtGas lift is a flexible method. It is possible to use it in wells of

0.159 m3 (a few barrels) per day, or wells of 159 m3 (a thousand barrels) per day. There are several methods of producing hydro-carbons using gas lift, but continuous gas lift is most common. Presently, there are at least 1,500 wells in Venezuela producing by intermittent gas lift. Also, single well completions are the most used gas lift installations around the world.

For any type of gas lift method, there is a maximum production rate, which is a function of depth, reservoir, completion, and sur-face conditions. This maximum production requires a specific opti-mized rate of gas injection. Any additional gas injection rate would result in an oil production rate smaller than the maximum rate.

To optimize gas lift for a given well, which includes the selec-tion of tubing strings, size limitations, and maximum available gas flow rate, it is necessary to find the best depth of injection point and the gas injection pressure.

AbstractDownhole Water Sink (DWS) technology controls water

coning in dual-completed wells by concurrently producing water from the bottom completion below the oil-water contact, and oil from another completion at the top of the oil sand. It has been shown that DWS improves well productivity, increases oil re-covery, and could produce oil-free water for direct injection or overboard dumping offshore. To date, DWS has been applied in natural flow wells or wells where a downhole pump can be easily installed. However, in many areas, such as the Louisiana Gulf Coast and Venezuela where water coning is commonplace, the only production method is gas lift.

This paper presents a feasibility study and a design method for dual gas lifting in DWS wells. The design employs a two-tier nodal analysis for several combinations of two tubing stringsone for oil and a second one for waterinstalled in a production casing. First, nodal analysis is performed separately for the water and oil legs in order to define their operational range. Then, the two solutions are combined and coupled with the Inflow Perfor-mance Window (IPW) describing the operational domain (top in-flow rate vs. bottom inflow rate) of the well.

Using the new method, a simulation study was conducted using data from actual wells. The results indicate that the gas lift would limit the performance of DWS wells. Moreover, the design can be optimized for maximum production of oil with controlled water withdrawal from the bottom completion. Limitations such as maximum gas injection rate, or injection gas pressure, are dis-cussed. Also, this paper presents an example of a theoretical per-formance of a DWS well with gas lift.

Although dual gas lift has been theoretically developed, it has not been practiced very much since single well completions are most commonly used around the world. In fact, only a few field cases of dual gas lift have been reported in the literature(1-8). Some of them indicate that accurate reservoir and well information be-comes a key factor for successful installation. Others emphasize the importance of an individual design for the operating valves(1, 2, 5). Other authors report that the challenge of dual gas lift design is to determine the amount of gas going to each zone, if the zones have different demands(4).

In the dual gas lift, it is necessary to define the placement depth of injection point and unloading valves for both tubing strings. The placement should put these points close to each other(7, 8). Then, each valve has to be individually designed.

Selecting the method of gas lifting is also important. For ex-ample, continuous gas lift is appropriate for wells producing at least 1.8410-6 m3/s (200 bfpd). In general, intermittent gas lift is applied for wells producing less than 1.8410-6 m3/s (200 bfpd), ex-cept for the chamber lift method. Also, well depth may make con-tinuous gas lift difficult to install.

In continuous gas lift, the application of nodal analysis with multiphase flow correlation for vertical and horizontal strings will allow determination of the conditions for having the best produc-tion rate. In intermittent gas lift, the optimum slug for the well conditions and the best cycle time determination is required for maximum oil production rate, as shown in Figure 1.

Principles of DWSDownhole Water Sink (DWS) is a technique for producing

water-free hydrocarbons from reservoirs with bottomwater drives

Oil

Pro

duc

tio

n R

ate

bo

pd

(= 1

.84

10-6

m3 /

s)

60

50

40

30

20

10

00 50 100 150 200 250

Cycle Time [min (= 60 s)]

FIGURE 1: Maximum oil rate for intermittent gas lift.

50 Journal of Canadian Petroleum Technology

and strong tendencies toward water coning(9-15). Conventional wells in these reservoirs produce increasing volumes of brine with decreasing amounts of oil or gas (Figure 2) which ultimately leads to early shut-down of these wells without sufficient recovery of hydrocarbons in place. Furthermore, produced waters are contami-nated with hydrocarbons and require costly treatment prior to off-shore discharges or subsurface injections.

DWS wells are dual-completed, above and at or below oil water contact (OWC). The bottom (water sink) completion drains the water at a controllable rate to produce a pressure sink equal to that created by oil production at the top of the sand. The result is a stable dynamic OWC that allows either controlled water cut (WC) in the produced oil or production of water-free oil and oil-free water, as shown in Figure 3.

There is a certain operational range of the top/bottom rate com-binations that makes the dynamic OWC stable with no water break-through. The shaded envelope in Figure 4 indicates this rangethe area of segregated production of oil and water. Unlike conven-tional wells, DWS wells have an infinite number of critical rates for water (or oil) breakthrough(2, 3). Moreover, Figure 5 shows the DWS operational domain with the water cut and oil cut isolines.

Typically, the operational range of a DWS well is limited by the maximum pressure drawdown, pmax, that constrains rate of pro-duction at the top completion. As shown in Figure 6, the well with oil-free water drainage could only be operated in the area below the pmax line and the WC = 0 line. Within this area, however, the operation needs to be optimized for the maximum oil production rate.

Figure 7 demonstrates the principle of maximizing the DWS wells productivity by controlling water cut at the top completion. It shows that the fluid (oil and water) productivity index, PI, in-creases with increasing water cut while the productivity index for oil, OPI, displays quite an opposite trend. Thus, unlike conven-tional wells, DWS wells should be operated such that PI is mini-mized while OPI is maximized, i.e., with minimum water cut at the top completion.

10 20 30 400

2

4

6

8

10

00

20

40

60

80

100Qoil WOR WC

Flow Ratebfpd (= 1.8410-6 m3/s)

Water C

ut %, o

r Flow

Rate

bp

d (=

1.8410-6 m

3/s)

Wat

er-O

il R

atio

(%)

FIGURE 2: Effect of rate in conventional well with water coning problem.

FIGURE 3: DWS well principle.

Bottomdrainage ofwater and oil

Top productionof oil with water

Segregated inflow:oiltop; waterbottom

Bo

tto

m C

om

ple

tio

n R

ate

bp

d (

= 1

.84

10-6

m3 /

s)

Top Completion Ratebpd (= 1.8410-6 m3/s)

0

10

20

30

40

50

60

70

0 10 20 30 40 50 60 70 80 90 100

FIGURE 4: Inflow Performance Window for DWS well.

0.5

0

100

200

300

400

500

600

700

800

0 50 100 150 200

0.2 0.1

0.4

0.0

0.1

0.2

0.3

0.6

0.7

Bot

tom

Com

plet

ion

Rat

ebp

d (=

1.8

410

-6 m

3 /s)

Top Completion Ratebpd (= 1.8410-6 m3/s)

Oil Cut Isolines

FIGURE 5: Inflow Performance Window with water/oil cut isolines.

WC = 0 3010

$P= 625 Psi

0

2,000

4,000

6,000

8,000

10,000

12,000

14,000

0 400 800 1,200 1,600

Bo

tto

m C

om

ple

tio

n R

ate

bp

d (=

1.84

10-

6 m

3 /s)

Top Completion Ratebpd (=1.8410-6 m3/s)

50

70

90

p = 1,000 psi

p = 626 psi

FIGURE 6: Inflow Performance Window with top completions pressure drawdown isolines.


Design of Dual Gas Lift in DWS WellsA schematic of a dual gas lift installation in a DWS well is pre-

sented in Figure 8. Other installation variants could also be used. For example, one string could work with continuous gas lift and the other with intermittent gas lift. Alternatively, the well could have a dual completion with only one string on gas lift and another on natural flow. Hence, selection of a specific variant of gas lift for a well would depend on the wells properties such as the size, depth, bottom hole flowing pressure, and fluid volumes to be lifted in each string.

To date, there has already been one field installation of dual gas lift in a DWS well. The gas lift design, however, was not coupled with the wells productivity performance. Thus, there is a need to

develop a design procedure combining wells inflow performance with performance of lifting fluids in two tubing strings to achieve maximum oil productivity of the well.

Design ProcedureDWS well gas lift design involves several steps that are summa-

rized below. The theoretical basis of each step derives from prin-ciples of well performance and the theory of DWS wells(16-19). The actual computations have been performed using the DWS design software, SCONE, and commercial software for nodal analysis and gas lift design. The main steps are as follows:

Develop the inflow performance chart (IPC) for the DWS well similar to that in Figures 4 through 6;

Use IPC to determine the best operational combinations of the top and bottom rates and respective water cut values. Consider plots similar to those in Figures 5 and 6. This step gives volumes of fluids to be lifted in each tubing string;

Compute bottom hole flowing pressure corresponding to the operational conditions;

Select all available size combinations of two strings (Figure 9). Consider lifting large volume of water and relatively small volume of oil;

Use gas lift software to obtain gas lift performance curve for water strings (Figure 10) from each combination of two strings. Determine maximum rates of lifting water in DWS well;

Use gas lift software to obtain a family of gas lift perfor-mance curves for oil strings from each combination of two strings. Consider variety of water cut values as shown in Figure 11. Determine maximum fluid rates for each value of water cut (WC);

Superimpose maximum water rates on the IPC relation-ship (Figure 12). This step will define the range of available

00.20.40.60.8

11.2

1.41.6

0 0.2 0.4 0.6 0.8 1

PI (water+oil) PI (oil)

PI,

bp

d/p

si (=

12.7

10-

6 m

3 /s

kPa)

Water Cut at Top Completion

FIGURE 7: Top completion productivity index (PI) vs. water cut.

Bubbleflow

Liquid

Gasbubble

Liquidfilm

Liquid

Liquid

Gas

Gas

Gas

Annularflow

Slugflow

Oil

Water+Gas

Oil Gas

Water

+

FIGURE 8: Schematics if dual continuous gas lift in DWS well.

Gas

WaterOil

75/8 inch

FIGURE 9: Geometry of dual gas lift.

0

Gas Injection RateMcft/d (= 32810-6 m3/s)

500 1,000 1,500

Bo

tto

m D

rain

age

Rat

eb

pd

(= 1

.84

10-6

m3 /

s)

6,000

4,000

2,000

0

27/8"

31/2"

FIGURE 10: Performance water flow rate from bottom completion with continuous gas lift.

0

200

400

600

800

1,000

1,200

1,400

1,600

0 1,000 2,000

max. value

90% water

70% water

50% water

30% water

10% water

0% water

Gas Injection RateMcft/d (= 32810-6 m3/s)

Oil

Rat

eb

pd

(= 1

.84

10-6

m3 /

s)

FIGURE 11: Oil production rate vs. gas rate for various water cut values.


top completion rates and WC values for each variant of two tubing strings;

Examine the available range of top completion rates to find fluid rate and WC combination that gives maximum oil rate, as graphically shown in Figure 13. First determine the oil gas lift limit plotsthe two top-downward curves in Figure 13. Then, determine the maximum oil inflow plotsthe two bottom-upward curves in Figure 13. The intercept of the two plots represents the maximum oil production rate; and,

Select the gas lift installation (combination of two strings) that gives the largest maximum oil rate.

Example of DWS Well With Dual Gas LiftThe example demonstrates the design procedure outlined above.

In the design, we used the following limitations/requirements: Unlimited gas injection rate; Unlimited gas injection pressure; Inflow pressure drawdown smaller than 6,894 kPa

(1,000 psi); Oil can be produced with small water cut; and, Oil-free water drainage is required.Figure 6 is the IPC relationship for this well. The relationship

has been generated with the SCONE software that simulates water coning for given values of the top and bottom rates. The software employs a trial and error method to find critical rates, water cuts, and pressure drawdown values and to generate IPC.

Table 1 shows data obtained from SCONE for a 1,723.4 kPa (250 psi) pressure drawdown in the top sand. For this example, the bottom completion produces clean (oil-free) water. The maximum oil flow rate corresponds to zero water cut and the maximum rate of water drainage.

Selection of Water and Oil String Size

Figures 5 and 6 clearly show that water drainage rates are much higher than oil rates. This means that the water string diameter should be larger than the oil string. In the gas lift design, strings

are sized by mandrel diameter rather than nominal diameter. Thus, for dual gas lift design, it is necessary to consider the size of the mandrel for each string. Also, the dimension of casing limits the combined size of both strings and defines selection of variants.

In this example, a well with a casing diameter of 0.194 m (75/8 in) (Figure 9) is assumed. Hence, it is possible to have the fol-lowing variants:

0.089 m (31/2 in) water string and 0.0524 m (21/16 in) oil string; or,

0.073 m (27/8 in) water string and 0.06 m (23/8 in) oil string.

Nodal Analysis of Gas Lift Well

To run the nodal analysis software, it is necessary to gather the following input data:

Oil properties (API, water cut, reservoir gas-oil relation, spe-cific gravity of gas and water);

String diameter; Depth of injection point; Gas flow rate; Pressure and temperature of reservoir, productivity index or

drawdown, and fluid flow production rate; Pressure and temperature at separator; Diameter and length of flow line; and, Vertical and horizontal multiphase flow correlation.Figure 10 shows results from the nodal analysis of the 0.089

m (31/2 in) and 0.073 m (27/8 in) water strings operated in theDWS well continuous gas lift. The plots represent maximumrates of lifting water in this well for the two strings. More than 10.1210-3 m3/s (5,500 bwpd) can be lifted with a 0.089 m (31/2 in) string, as compared to 6.62410-3 m3/s (3,600 bwpd) for the 0.073 m (27/8 in) string, for the same 0.164 m3/s (500 Mcf/d) gas injec-tion rate.

0

2,000

4,000

6,000

8,000

10,000

12,000

14,000

0 400 800 1,200 1,600

Flow Rate at Top Completionbpd (= 1.8410-6 m3/s)

Top completion:

27/8"

31/2"

Bo

tto

m C

om

ple

tio

n R

ate

bp

d (=

1.8

410

-6 m

3 /s) 0% water

10% water30% water50% water70% water90% waterdp = 625 psidp = 1,000 psidp = 1,150 psidp = 1,300 psidp = 1,450 psidp = 1,540 psi

625

1,540

1,0001,150

1,3001,450

FIGURE 12: Available top rates (solid horizontal line) for maximum gas-lifted water drainage with 31/2-in tubing.

0

200

400

600

800

1,000

0 0.2 0.4 0.6 0.8 1

Water Cut Top Completion

27/8"

31/2"

Top

Co

mp

leti

on

Oil

Rat

eb

pd

(= 1

.84

10-6

m3 /

s)

Bottom drainage = 5,607 bwpd

Bottom drainage = 3,794 bwpd

Oil gas lift limit for 23/8" tubing

Oil gas lift limit for 21/16" tubing

FIGURE 13: Intercepts of oil inflow (upward) and oil gas-lifting (downward) curves give maximum oil rate for two dual-tubing variants.

TABLE 1: Fluid inflow rates for DWS well*.

Bottom completionwater, bwpd (m3/s)

1,909(3,512)

1,818(3,345)

1,681(3,094)

1,454(2,675)

1,273(2,342)

1,045(1,928)

295(543)

Top completionfluids,bwpd (m3/s)

129(237)

141(259)

174(320)

226(410)

361(664)

284(523)

248(456)

Top completionoil,bwpd (m3/s)

129(237)

128(236)

122(224)

113(208)

99(182)

85(156)

36(66)

Top completionwater cut,percent

0 10 30 50 60 70 90

* Constant 250 psi pressure drawdown at top completion


An example result from the nodal analysis of the 0.06 m (23/8-in) top completion string is shown in Figure 11. The plots describe fluid rates for different values of water cut. The maximum oil rate corresponds to the maximum water cut. Interestingly, it also corre-lates with the highest fluid productivity index in Figure 7.

Tabulated values of the maximum oil-lifting curve are in Table 2. Also, the table shows the effect of water cut on the efficiency of continuous gas lift. For 90% WC, the capacity of fluid lifting drops to 55% of the maximum fluid rate. However, when the oil is free from water, it is possible to lift up to 87% of the maximum fluid rate.

Figure 12 presents the IPC plot for the DWS well together with two horizontal lines representing the water lifting limit at the bottom completion for the 0.073 m (27/8 in) and 0.089 m (31/2 in) tubing strings. Also included in this plot are the isolines of pres-sure drawdown at the top completion. The horizontal line sections between the WC = 0 line and the p = 6,894 kPa (1,000 psi) line define the range of available top rates and WC values for each combination of two strings.

Oil inflow limit is the plot in Figure 13 for the two completion variants. The two bottom-upward curves represent oil rate limited by the maximum water rate vs. water cut. Analysis of these plots indicates that maximum oil rate occurs at maximum WC at the in-tercept with the two top-downward curves representing the max-imum pressure drawdown at the bottom completion of p = 6,894 kPa (1,000 psi).

Figure 13 is a combined plot of the oil inflow and oil lifting limits for the two completion variants. Of the two points of in-tercept, the better one represents the 0.089 m (31/2 in) to 0.0524 m (21/16 in) variant of the completion. The selected completion should produce 86510-6 m3/s (470 bopd) with 53% WC, instead of 73610-6 m3/s (400 bopd) with 70% WC.

The plot in Figure 13 also demonstrates the effect of tubing size on the oil and water production rate. It shows that selecting the largest possible tubing for water lifting should optimize the DWS production.

ConclusionsA method for optimized design of dual gas lifting in DWS wells

has been developed and theoretically tested. The conclusions from this work are as follows:

It is possible to use dual gas lift in DWS. However, the re-sults show that the gas lift design would control performance of DWS;

The design procedure is controlled mostly by the water-lifting limit that reduces the operational range of the well and the oil inflow rate. In the design, the water-lifting limit isrepresented by the oil-rate vs. WC relation (the bottom-up-ward curves in Figure 13);

There is also an additional effect of limited oil lifting ca-pacity of the tubing installed at the top completion. In the de-sign, this effect is represented by the oil-rate vs. WC relation (the top-downward curve in Figure 13);

For a single two-tubing design variant, the maximum oil pro-duction rate corresponds to the intersection of the oil inflow and oil lifting curves. For multiple variants, the best design is given by the intercept with the highest oil rate; and,

The results show that using the largest water tubing should be the first choice when the well size is small.

AcknowledgementsThe authors express their appreciation to PDVSA-Intevep and

the Downhole Water Sink Technology Initiative consortium of pe-troleum industry participants at LSU for providing funds for this study.

SI Unit Conversion Factors(gal) 3.785412 E-03 = (m3)(in) 2.54 E-02 = (m)(psi) 6.894 E+00 = (kPa)(lbf/in2) 6.894 E+00 = (kPa)(ft) 3.048 E-01 = (m)(bpd) 1.84 E-06 = (m3/s)(Mscft) 328 E-6 = (m3/s)(Mscft/bbl) 178.1 E+00 = (m3/ m3)(Bpd/psi) 12.685 E-06 = (m3/skPa)

REFERENCES 1. BROWN, K.E. and DAVIS, J.B., Attacking Those Troublesome Dual

Gas Lift Installations; paper SPE 4067, 1972. 2. DAVIS, J.B. and BROWN, K.E., Optimum Design For Dual Gas

Lift; Petroleum Engineer International, Vol. 45, No. 7, pp. 36-39, July 1973.

3. DOUGLAS, B.L., Dual String Automatic Gas Lift Valve; Patent In-formation: U S 3851997, C 12/3/74, F 3/1/74; Dresser Industries Inc., 1974.

4. BLEAKLEY, W.B., First Dry Subsea Wellhead Passes 11th Year; Petroleum Engineer International. Vol. 56, No 4, pp. 19-21, March 1984.

5. WALSH, P.W., Gas Lift Operations in Bass Strait; paper SPE 28765, 1994.

6. CHIA, Y.C. and HUSSAIN, S., Gas Lift Optimization Efforts and Challenges; paper SPE 57313, 1999.

7. Middle East Report, Unique Well Completion Offers Producing Flexibility; Oil and Gas Journal, Vol. 75, No. 20, pp. 92-98, May 5, 1977.

8. MOORE, P.C. and ADAIR, P., Dual Concentric Gas-Lift Completion Design for the Thistle Field; SPE Production Engineering, Vol. 6, No. 1, pp. 102-108, February 1991.

TABLE 2: Efficiency of continuous gas lift in DWS well.

Water Cut(fraction)

Maximum Rate,Qmax, bfpd(10-6 m3/s)

Oil Rate, bopd

(10-6 m3/s)

Gas Injection Rate, Mcft/d

(= 32510-6 m3/s)

Gas-Oil Ratio (Mcft/bbl)

(= 175.6 m3/m3)

Percent Qmax Produced

(%)

0951

(1,750)830

(1,527)1,600(0.520)

1.93(343.7)

87.28

0.11,048(1,928)

883(1,625)

1,400(0.455)

1.59(283.2)

84.26

0.31,284(2,363)

1,008(1,855)

1,400(0.455)

1.39(247.6)

78.50

0.72,095(3,855)

1,305(2,401)

1,000(0.325)

0.77(137.2)

62.29

0.92,666(4,905)

1,458(1,225)

1,000(0.325)

0.69(122.9)

54.69


9. GRASSICK, D.D., KALLOS, P.S., DEAN, S., and KING, S., Dy-namic Risk Analysis of Gas Lift Completions; SPE Production Engineering, pp. 172-180, May 1992.

10. WOJTANOWICZ, A.K., SHIRMAN, E.I., and KURBAN, H., Downhole Water Sink (DWS) Completions Enhance Oil Recovery in Reservoirs With Water Coning Problem; paper SPE 56721, 1999.

11. SWISHER, M.D. and WOJTANOWICZ, A.K., In Situ Segregated Production of Oil and WaterA Production Method With Environ-mental Merit: Field Application; paper SPE 29693, 1995.

12. SWISHER, M.D. and WOJTANOWICZ, A.K., New Dual Com-pletion Method Eliminates Bottom Hole Water Coning; paper SPE 30697, 1995.

13. BOWLIN, K.R., CHEA, C.K., WHEELER, S.S., and WALDO, L.A., Field Application of In Situ Gravity Segregation to Remediate Prior Water Coning; paper SPE 38296, also, Journal of Petroleum Tech-nology, pp. 1117-1120, October 1997.

14. LOGINOV, A. and SHAW, C., Completion Design for Downhole Water and Oil Separation and Invert Coning; paper SPE 38829, 1998.

15. SHIRMAN, E.I. and WOJTANOWICZ A.K., More Oil With Less Water Using Downhole Water Sink Technology: A Feasibility Study; paper SPE 49052, 1998.

16. WOJTANOWICZ, A.K. and SHIRMAN, E.I., Inflow Performance and Pressure Interference in Dual-Completed Wells With Water Coning Control; Journal of Energy Resources TechnologyTransac-tions ASME, Vol. 124, December 2002.

17. WOJTANOWICZ, A.K. and SHIRMAN, E.I., More Oil Using Downhole Water Sink Technology: A Feasibility Study; SPE Produc-tion and Facilities, Vol. 15, No. 4, pp. 234-240, November 2000.

18. SHIRMAN, E.I. and WOJTANOWICZ, A.K., Water Cone Histeresis and Reversal for Well Completions Using the Moving Spherical Sink Method; paper SPE 37467, 1997.

19. SHIRMAN, E.I., A Well Completion Design Model for Water-Free Production; proceedings of the SPE Annual Technical Conference and Exhibition, Denver, CO, pp. 853-860, October 6 9, 1996.

ProvenanceOriginal Petroleum Society manuscript, Dual Gas Lift in Wells With Downhole Water Sink Completions (2002-238), first pre-sented at the 3rd Canadian International Petroleum Conference (the 53rd Annual Technical Meeting of the Petroleum Society), June 11 - 13, 2002, in Calgary, Alberta. Abstract submitted for review December 14, 2001; edi-torial comments sent to the author(s) August 22, 2005; revised manuscript received October 18, 2005; paper approved for pre-press October 18, 2005; final approval November 5, 2005.

Authors Biographies

Luisana Marcano holds a masters degree and a Ph.D. degree in energy, both from Poitiers University, France. She worked for PDVSA-Intevep from 1987 to 2002 and has held a variety of positions in the R&D of ar-tificial lift. Her main activities have been in gas lift design and trouble shooting, selec-tion of artificial lift method, development of interactive simulators for intermittent gas lift, training and technology transfer activi-

ties for intermittent gas lift, supervisor of field activities in well performance and production enhancement, and supervisor of R&D activities in artificial lift. She had a sojourn at Louisiana State University analyzing the application of gas lift to control water coning through dual completion techniques (Downhole Water Sink, DHWS). Since 2002, she has worked independently on sev-eral oilfield production projects.

Andrew K. Wojtanowicz is the Texaco-en-dowed Environmental Chair in petroleum engineering at Louisiana State University, USA. He has held faculty positions at the New Mexico Institute of Mining and Tech-nology and the University of Mining and Metallurgy in Krakow, Poland. He is a UN expert in drilling engineering and has also worked in the petroleum industry as a drilling engineer, drilling supervisor, and drilling fluids technologist in Europe and

Africa. Wojtanowicz conducted research in drilling, completion, and production operations with an emphasis on environmental ef-fects and prevention techniques. His studies are reported in 180 publications and four books. He is an editor-in-chief of ASME Transactions Journal of Energy Resources Technology and a reg-istered petroleum and environmental engineer in Louisiana. As a Conoco Environmental Research Fellow (1991/1992), he devel-oped dewatering technology for closed-loop drilling systems. He has also developed a water coning control technique with Down-hole Water Sink (DWS) well completion, for which he received the Special Meritorious Award for Engineering Innovation in 1996. He has directed a DWS Joint Industry Project at LSU since 1997. He has also served as the 2003/2004 SPE Distinguished Lecturer of the downhole water separation technology.

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