A Study to Minimise Bottomw Water Coning in Heavy Oil Reservoirs

7/27/2019 A Study to Minimise Bottomw Water Coning in Heavy Oil Reservoirs

1/11

Binshan Ju1School of Energy Resources,

Key Laboratory of Marine Reservoir Evolution

and Hydrocarbon Accumulation Mechanism,

Ministry of Education,

China University of Geosciences (Beijing),

Beijing 100083, China

e-mail: [email protected]

Xiaofeng QiuBlock 1, Building 10, Unit 2, House 202,

China University of Petroleum (East China),

271 Beier Road,

Dongying, Shandong 257062, P.R.C.

Shugao DaiShengli Oil Field Dongsheng Jinggong

Petroleum Development Group Co. Ltd.,

Dongsheng Mansion,

Xisi Road, No. 266,


Tailiang FanSchool of Energy Resources,

Key Laboratory of MarineReservoir Evolution and

Hydrocarbon Accumulation Mechanism,




Haiqing WuShengli Oil Field Dongsheng Jinggong

Petroleum Development Group Co. Ltd.,

Dongsheng Mansion,

Xisi Road, No. 266,


Xiaodong WangSchool of Energy Resources,

Key Laboratory of Marine

Reservoir Evolution and

Hydrocarbon Accumulation Mechanism,




A Study to Prevent Bottom WaterFrom Coning in Heavy-OilReservoirs: Design andSimulation ApproachesThe coning problems for vertical wells and the ridging problems for horizontal wells arevery difficult to solve by conventional methods during oil production from reservoirs withbottom water drives. If oil in a reservoir is too heavy to follow Darcys law, the problemsmay become more complicated for the non-Newtonian properties of heavy oil and itsrheology. To solve these problems, an innovative completion design with downhole watersink was presented by dual-completion in oil and water columns with a packer separating

the two completions for vertical wells or dual-horizontal wells. The design made itfeasible that oil is produced from the formation above the oil water contact (OWC) andwater is produced from the formation below the OWC, respectively. To predict quantita-tively the production performances of production well using the completion design, a newimproved mathematical model considering non-Newtonian properties of oil was pre-sented and a numerical simulator was developed. A series of runs of an oil well wasemployed to find out the best perforation segment and the fittest production rates from the

formations above and below OWC. The study shows that the design is effective for heavyoil reservoir with bottom water though it cannot completely eliminate the water cone

formed before using the design. It is a discovery that the design is more favorable for newwells and the best perforation site for water sink (Sink 2) is located at the upper 1/3 of the

formation below OWC. DOI: 10.1115/1.2955560

Keywords: water coning, bottom water, non-Newtonian oil, improve oil recovery

1 Introduction

Water coning has been regarded as the biggest problem during

oil production from a reservoir with bottom water. The phenom-

enon has been known for at least 100 years. Smith 1 in 1963 and

some other previous researchers before him discussed the theory

of water coning. Resumptively, the occurrence of water coning is

due to pressure gradients resulting from well production from the

pay zone. The pressure gradients result in a water cone to rise

toward the bottom of the producing interval. The tendency of the

water to cone is offset or partially offset by gravity force since

water has a higher specific gravity than that of oil. A dynamic

balance exists between the gravitational force and the pressure

gradient caused by well production. If the pressure gradient ex-

ceeds the gravitational force, water coning to the wellbore will

occur. Although the theory is not difficult to understand for a

reservoir engineer, it is very difficult to control water coning, es-pecially for heavy oil reservoirs with bottom water since the dif-

ference in specific gravities of oil and water is very small. Most of

previous studies focused on the prediction of critical production

rate of water coning and water coning process to control water

coning by analytical models 26 , physical laboratory simulation 79 or numerical simulation technique 1014 , artificial barriers 1517 for controlling water coning, and prevention by injectionheavy fluids or chemicals 18,19 such as cross-linking polymersor gels.

In the past 100 years, reservoir engineers tried to look for some

effective techniques to control water coning during exploiting oil

1Corresponding author.

Contributed by the Petroleum Division of ASME for publication in the JOURNAL OF

ENERGY RESOURCES TECHNOLOGY. Manuscript received April 8, 2007; final manuscript

received April 20, 2008; published online August 11, 2008. Review conducted byFaruk Civan. Paper presented at the International Petroleum Technology Conference

held in Doha, Qatar, November 2123, 2005.

Journal of Energy Resources Technology SEPTEMBER 2008, Vol. 130 / 033102-1Copyright 2008 by ASME

Downloaded 21 Nov 2010 to 124.16.168.130. Redistribution subject to ASME license or copyright; see http://www.asme.org/terms/Terms_Use.cf


2/11

from reservoirs with bottom water. Unfortunately, only a few suc-cessful oil-field examples were reported. Wojtanowicz et al. 20and Shirman and Wojtanowicz 21 reported that downhole watersink technology is a feasible operation to control water coning.Moreover, some oil-field examples were given and analyzed intheir published papers. The thought is to design two sinks in oneformation TSIOF . One locates above OWC Sink 1 and theother locates below OWC Sink 2 . From the view of the theoryfor the flow in sand formation, the design is novel because pres-sure gradients in the vicinity of producing interval can be modi-fied by changing the production rates of two sinks. Although thethought can be traced back to about 50 years ago 22 , the appli-cations of the thought in oil fields were reported in recent tenyears, and some reservoir engineers did not accept the idea yet.Among the oil-field examples given by Shirman and Wojtanowicz

21 , the specific gravity of oil is from 0.865 to0.93 21 deg32 deg API and the maximum viscosity is

17 mPa s downhole. Currently, there is no report that TSIOFtechnology is used in heavy oil reservoirs with bottom water toprevent water coning.

As the analysis above, for a heavy reservoir with bottom water,

generally, the critical production rate is too small to gain a profiton its operating cost. If it keeps a rate above the critical produc-tion rate, water coning results in production with high water-cut.One oil reservoir located in H.K., Shandong, China is a typicalheavy-oil reservoir with bottom water. The specific gravity of de-gassed crude oil is 0.988, and the viscosity of degassed crude oil

is 7337 mPa s at 20 C. The viscosity of the crude oil under the

reservoir condition is 710 mPa s. Therefore, the ratio of oil vis-cosity to water viscosity in formation condition is still quite ad-verse for water displacement. The current water-cut is up to 90%while oil recovery is only 1.0%. The object of this paper is tostudy the feasibility of TSIOF technology to enhance oil recoveryof heavy-oil reservoirs with bottom water.

Fig. 1 The principle of TSIOF

033102-2 / Vol. 130, SEPTEMBER 2008 Transactions of the ASME



3/11

2 Theory Analysis for Water Coning Control

Since water coning is caused by pressure gradients resultingfrom the sink above the OWC, pressure gradients in the wholeformation can be also modified by a water sink below the OWCwhen gravity forces are not high enough to offset the pressuregradients induced by the sink above the OWC. Therefore, themutual actions of the pressure gradients induced by two sinks andgravity forces control the evolvement of water coning and deter-mine the shape of water coning. The unique design may restrainwater coning or ridging by adjusting two sink production ratesfrom the completion intervals above and below the OWC andenlarge the oil draining area, which in turn improves the oil re-covery.

Figure 1 shows the principle of TSIOF used in vertical andhorizontal wells. Figure 1 a is one part of a reservoir with bottomwater and there is an original oil water contact OOWC in themid of the formation. Figure 1 b is one sink produced from avertical well, and it shows that the current oil water contact

COWC moves to the perforating interval. If two sinks see Fig.1 c are designed for production, theoretically, OWC can be kepthorizontal by modifying the rates of two sinks. That is to say,OWC can coincide with OOWC. Figure 1 d illustrates that onehorizontal well interval is above the OWC and the other is belowthe OWC. Similarly, one sink production results in water ridgingin three spaces, which looks like a water cone on crossing profile

see Fig. 1 e . Moreover, water ridging can be eliminated bymodifying the production rates of two sinks Fig. 1 g . Althoughthe OWC can theoretically be kept horizontal by modifying theproduction rates of two sinks, it is very difficult to keep it hori-zontal for the reservoir with high viscosity ratio of crude oil to

water. However, TSIOF technique can prevent water coning orridging to some extent and put off water breakthrough time.

3 Completion Method

In order to realize the TSIOF technique, a special completion isadopted to separate production fluids from the formations aboveOWC and below OWC. Figure 2 gives well completion configu-ration in a vertical well. The packers separate the fluids producedfrom the pay zones above and below the OWC. Because the for-mation pressure is not high enough to lift fluids onto the wellhead,one pump Pump 1 is set to pump oil into tubing and the other

Pump 2 is used to pump fluids into casing, respectively. There-

fore, the fluid produced from oil pay zone flows through tubingand the fluid produced from bottom water formation flow throughannular space.

4 Mathematical Model

Since oil recovery of the reservoir in this study depends on theflooding of the edge and bottom water, the three-dimensionalthree-phase black oil model is chosen to study the productionperformances. However, the rheology properties of the heavy oil

must be considered for the oil in the reservoir one kind of non-Newtonian fluids.

4.1 Assumptions for the Mathematical Model. The math-ematical model was based on the following assumptions.

1 Assume that the multiphase flow is isothermal and threedimensional, and rock and fluids are compressible.

2 The oil is non-Newtonian fluid. 3 Capillary and gravity forces are considered. 4 Chemical reactions are neglected.

4.2 Multiphase Flow in Porous Media. The continuity equa-tions of slightly compressible multiphase fluid flow and Newton-ian flow are given by the following expressions:

div

k krw

Bw wgrad w

+ qw =

t

sw/Bw 1

divk kro

Bo ograd o + qo =

t so/Bo 2

divk krg

Bg ggrad g +

k kro Rs

Bo ograd o + qg

= t sg/Bg + SoRs/Bo 3

For the flows of the three phases of oil, water, and gas, we candefine

So + Sw + Sg = 1 4

We define the parameters in Eqs.

1

3

as

o = po + o z 5

w = pw + w z = po + pcwo + w z 6

g = pg + g z = po + pcgo + g z 7

where t is time; is the porosity of the porous media; S, , and pare saturation, viscosity, and pressure of fluids, respectively; k is

the absolute permeability; kr is the relative permeability; B is the

volume factor of fluid; q is the production or injection rate of

fluid; Rs is the solution gas-oil ratio; is the specific gravity offluid; z is the distance from reference level; and pc is the capillary

Fig. 3 The relation of apparent viscosity and pressuregradient

Fig. 2 Well completion configuration

Journal of Energy Resources Technology SEPTEMBER 2008, Vol. 130 / 033102-3



4/11

force. The methods to obtain coefficients of Eqs. 1 3 exceptoil viscosity can be obtained from Ref. 23 .

The data from experiments in laboratories show that the crudeoil viscosity in reservoir is a function of both reservoir pressuresof oil phase and pressure gradients. Pressure is one factor to de-termine the viscosity of heavy oil for pressure has effects on bothsolubility of gas and the spaces between molecules. The effect ofpressure on viscosity was studied by experimental approach. Pres-sure gradient is the other factor to influence the viscosity of heavyoil for flow shearing. The characters of viscosity of heavy oilobtained by experiments in this study were shown in Fig. 3. Whenthe pressure gradient is less than 0.04 MPa/m or higher than 0.13MPa/m, the viscosity can nearly be regarded as a constant. As thepressure gradient falls in the interval of 0.04 MPa/m to 0.13MPa/m, the viscosity of the heavy oil declines linearly. Experi-mental data were used in the simulator to represent the relation-ship between the viscosity of heavy oil and pressure gradient.

o = f po,grad po 8

The reservoir pressure determines the static viscosity, while pres-

sure gradient determines the dynamic viscosity apparentviscosity .

Viscosity is one of the properties of fluid and it keeps constantat all directions at a certain grid node for Newtonian fluid. It istrue that the static viscosity does not depend on the direction at acertain grid node; however, the apparent viscosity of heavy oilalso depends on pressure gradient for it belongs to non-Newtonianfluids. Since the pressure gradients between adjacent blocks aredifferent, the apparent viscosities may be different. For three-dimensional case, one block has six surfaces through which fluidscan transfer. Therefore, there are six gradients between the blockand other adjacent six blocks, i.e.,

gradi1i,j,kn+1

=pi,j,k

n pi1,j,k

n

0.5 dxi,j,k+ dxi1,j,k 9a

gradi+1i,j,kn+1

=pi+1,j,k

n pi,j,k

n

0.5 dxi,j,k+ dxi+1,j,k 9b

gradi,j1j,kn+1

=pi,j,k

n pi,j1,k

n

0.5 dxi,j,k + dx,j1,k 9c

gradi,j+1j,kn+1 =

pi,j+1,kn pi,j,k

n

0.5 dxi,j,k + dx,j+1,k 9d

Table 1 Parameters for numerical simulation

Parameter names The values

The length of geological model, m 300The a verage thickness of ge ologic al model, m 17.0The average thickness of oil zone, m 10.0The average thickness of bottom water, m 7.0

The grids number, NxNy Nz 15 15 17The average porosity 37.99%

The average horizontal permeability, m2 0.666

The average oil saturation 0.57Initial pressure of the reservoir, MPa 11.70Bubble pressure, MPa 8.24

The static viscosity of oil in reservoir, mPa s 710

Volume factor of the crude oil 1.06Initial the solution gas-oil ratio 19.0

The viscosity of formation water, mPa s 0.48

Volume factor of formation water 1.01

Fig. 4 The rhythm of the sand formation

Fig. 5 The oil saturation in each layer from top to bottom

Fig. 6 Grids on the plane

Fig. 7 The relative permeability of oil and water

Fig. 8 Water-cut match




5/11

gradi,j,k1kn+1 =

pi,j,kn pi,j,k1

n

0.5 dxi,j,k+ dxi,j,k1 9e gradi,j,k+1k

n+1 =pi,j,k+1

n pi,j,kn

0.5 dxi,j,k+ dxi,j,k+1 9f

Fig. 9 Water coning process




6/11

When we calculate the fluids transferring through six faces, sixapparent viscosities determined by gradients are needed. For in-

stance, the apparent viscosity of oil between the grid i 1 ,j , k

and i ,j , k can be expressed as

i1,j,kn+1

= fpi1,j,k

n + pi,j,kn

2,gradi1i,j,k

n+1 10

5 Numerical Simulation and Discussion

Based on the mathematical model above and the rheology prop-

erties of the heavy oil, a new black oil simulator is developed tostudy the feasibility of the TSIOF technique to improve recoveryfrom the heavy-oil reservoir with edge and bottom waters. For ahorizontal well, water ridging looks like a cone in the view ofcrossing profile. From the point of fluids flowing in formation, thebottom water flows upward for both vertical and horizontal wells,so the mechanisms are similar whether it is a vertical well or ahorizontal well. Therefore, this paper focused on the feasiblestudy of the TSIOF technique used in vertical wells. The mainobjectives of this section are as follows.

a Prove if the TSIOF technique can be used in old wells toimprove oil recovery for heavy-oil reservoir with strongbottom and edge waters when water coning occurred:

1 historical matching for production wells 2971 and numeri-

cal simulation for water coning process 2 the effects of production rates of Sink 2 on oil production

and water-cut of Sink 1 3 the effects of production rates of Sink 2 on the behaviors of

water coning 4 the best location of perforating intervals of Sink 2 5 the economic feasibility of the TSIOF technique

b Prove that the TSIOF technique is also an effective ap-proach to prevent water from coning for new productionwells:

1 the effects of production rate of sink 2 on oil productionsink 1, and the total oil production of two sinks

2 the effects of production rate of Sink 2 on the ratios ofcumulative water to oil

3 the comparison of oil production between implementingTSIOF in a new well and an old well

To give the answers of the objectives of this paper, a single wellmodel with fine grids was run on the numerical simulator devel-oped in this paper. The main parameters of geology and reservoirfluids are listed in Table 1. The parameters listed in Table 1 areobtained by well logging interpretation and experimental data ofthe reservoir located in H.K., Shandong, China. The geologicalmodel is heterogeneous. The rhythm of the reservoir is composite;however, we can regard the formation as an antirhythm as a whole

see Fig. 4 . The distributions of oil saturation from top to bottomof the formation are shown in Fig. 5. The average grid sizes of

directions x and y are 20.0 m, and the average grid size in zdirection is 1.0 m. To improve accuracy, fine grids are set on the

plane in the vicinity of production well Fig. 6 .

5.1 Prove That TSIOF Technique Fitting for Old Wells

5.1.1 Historical Matching and Water Coning Process. Thewell has a production history of three years and four months. Theformation pressure is almost constant due to the strong floodingby natural bottom and edge waters. Therefore, the pressure matchis relatively easy and the water-cut match is the focus of historicalmatching. By modifying the relative permeabilities of oil and wa-ter, water-cuts are matched well. The relative permeability curvesof oil and water are shown in Fig. 7, and the water-cut match isshown in Fig. 8. It indicates that the numerical simulation results

have a good agreement with water-cuts from production data ex-cept for the first month. The relative high water-cut productiondata of the first month is caused by well operation before produc-tion. Figure 9 gives the evolvement of water coning and indicatesthat a smaller water cone has been formed in the first two monthsand a bigger water cone occurred after six months. Consequently,the dramatic increase in water-cut of the production well resultsfrom water coning.

5.1.2 Effects of Production Rate of Sink 2 on Oil Production,Water-Cut of Sink 1, and Water Coning Behavior. This section is

designed to predict the production performances with and withoutthe TSIOF technique. Supposing the production fluid rate of Sink

1 is 20 m3 / day, only Sink 1 production i.e., the production rateof Sink 2 is 0.0 and three production rates 10 m3 /day,20 m3 /day, and 30 m3 / day of Sink 2 are set for numerical simu-lation. Figure 10 shows that the increase in the production rates ofSink 2 results in obvious increase in cumulative oil production ofSink 1. The cumulative oil production of Sink 1 in five years atfour cases is given in Table 2.

Figure 11 shows that the increase in the production rate of Sink2 results in the reduction in water-cut of Sink 1.

Figure 12 shows that the shape of water cone can be changedby the production of Sink 2. The production of Sink 2 induces thedecline in the height of water cone. It implies that water cone canbe alleviated by the production of Sink 2; however, it is verydifficult to eliminate water cone for the severely adverse ratio of

Fig. 10 The effects of production rate of Sink 2 on oil produc-

tion of Sink 1

Table 2 Cumulative oil production of Sink 1 ton

Sink 2 rate 0.0 m3 /day 10 m3 /day 20 m3 /day 30 m3 /day

1 year 1038.0 1469.7 1916.5 2339.02 years 1927.6 2660.1 3480.2 4173.53 years 2693.8 3668.0 4843.8 5742.64 years 3387.4 4554.4 6081.7 7144.95 years 4013.5 5341.9 7229.1 8426.8

Fig. 11 The effects of production rate of Sink 2 on water-cut ofSink 1




7/11

oil viscosity to water viscosity. Inasmuch as the capacity of waste

water treatment of this plant is limited, a rate of 20 30 m3 / dayfor Sink 2 is recommended.

5.1.3 Optimization for the Best Perforating Location of Sink2. To optimize the best perforating location of Sink 2, the equal

production rates 20 m3 / day of Sinks 1 and 2 are set for simu-

Fig. 12 The effects of production rate of Sink 2 on the behaviors of waterconing




8/11

lation by changing the perforating location. Supposing that theperforating interval of Sink 2 locates at 1.0 m, 2.0 m, 3.0 m, 4.0m, 5.0 m, 6.0 m, and 7.0 m, respectively, from OOWC, each caseis run on the simulator for five years. Figure 13 gives the cumu-lative oil production for each perforating location of Sink 2. Itshows that perforating interval located at 2.03.0 m under theOOWC is the best location for the maximum cumulative oil pro-duction obtained. Therefore, the upper 1/3 of the thickness ofbottom water is recommended as a perforating site for Sink 2.

5.1.4 Economic Feasibility of TSIOF Technique. In order toprove the feasibility of the TSIOF technique, economic evaluationwas adopted to identify which is better for normal completion andthe TSIOF technique. Static payback period of investment Table3 and net present values Table 4 are calculated to demonstratethe economic feasibility of TSIOF. The main parameters of eco-nomic evaluation are listed in Table 5.

From Table 3, the longest payback period of investment is lessthan three months. It shows that the technique is feasible from theview of investment. Table 4 shows that the net present values ofthe three cases of the TSIOF completion are all greater than thatof the normal completion from the second year.

5.2 Prove That TSIOF Technique Fitting for New Wells.To prove that the TSIOF technique is also one effective approachto prevent water from coning for new production wells, we sup-

pose a new well brings into production with two sinks. Numericalsimulation by modifying the production rates of Sink 2 is used tostudy the feasibility of the TSIOF technique.

5.2.1 Effects of Production Rates of Sink 2 on Oil ProductionPerformance. Supposing the production rate of Sink 1 is

12 m3 /day, and the production rates of Sink 2 are 0.0 m3 /day,

4.0 m3 / day, 8.0 m3 / day, and 12.0 m3 / day, respectively. Theproduction time is three years and four months. Table 6 gives thesimulation results for each case. The data show that more oilproduction and less water production of Sink 1 are realized byusing the TSIOF technique. In addition, the ratios of total cumu-lative oil to cumulative water production also imply that theTSIOF technique can improve oil recovery and reduce water-cutfor heavy-oil reservoir with edge and bottom waters. When thetotal cumulative fluid production increases two times the rate ofSink 2 is 12.0 m3 / day , the total cumulative oil production in-creases from 4118 tons to 9568 tons.

5.2.2 Effects of Production Rates of Sink 2 on Water ConingBehavior. Figure 14 gives the original state of the formation andcurrent states production for three years and four months at dif-ferent production rates of Sink 2. When a production rate of Sink2 is 0.0 i.e., normal completion , a big water cone forms. Withthe increase in production rates of Sink 2, the height of water cone

reduces. When the production rate of Sink 2 is 12.0 m3 /day, wa-ter coning is alleviated to a great extent

5.2.3 Comparison of Oil Production Between ImplementingTSIOF in a New Well and an Old Well. To compare which is betterbetween the implementing TSIOF in a new well and an old well,cumulative oil productions of the old well and the new well ob-

tained by numerical simulation are charted in Fig. 15. The pro-duction liquid rates of Sinks 1 and 2 for the new well and the old

well are all 10 m3 /D. The two cumulative oil production curves

Fig. 13 The effect of perforation location on cumulative oilproduction

Table 3 Static payback period of investment

Normal completion TSIOF completionOnly one sink Production rate

of Sink 2,10 m3 /D

Production rateof Sink 2,20 m3 /D

Production rateof Sink2,30 m3 /D

Payback period of investment month 0 2.8 2.0 1.7

Table 4 The results of net present values

Net present value 104 RMB Normal completion TSIOF completion

Time year Only Sink 1 Production rateof Sink 2,10 m3 /D

Productionrate of Sink 2,

20 m3 /D

Production rateof Sink 2,30 m3 /D

0 0 100 100 1001 202.92 198.35 299.25 396.052 357.05 411.27 585.41 736.013 474.56 570.52 806.3 992.924 568.93 694.48 984.38 1196.565 644.42 791.97 1131.09 1361.83

Table 5 Main parameters of economic evaluation of Zh2971

Capital investment of TSIOF completion, 104 RMB 100

Cost of oil production per ton including the cost oftreating the increased water produced

1600

Oil price, RMB/ton 4000

Cost of a remedial well treatment per year, 104 RMB 15

Benchmark rate of return 0.12




9/11

Fig. 14 The effects of production rate of Sink 2 on the behaviors of waterconing for a new well

Table 6 The effect of Sink 2 on the production performances of Sink 1

Production ratesof Sink 2

m3 /day

Sink 1 Sink 2 Sink 1+Sink 2 The ratios of totalcumulative oil towater production

ton/m3

Cumulative oilproduction

ton

Cumulative waterproduction

m3


ton


m3


ton


m3

0 4118 10654 0 0 4118 10654 0.3874 5506 9066 287 4760 5793 13826 0.4198 6957 7816 637 9334 7594 17149 0.443

12 8342 6430 1226 13670 9568 20099 0.476




10/11

show that cumulative oil productions of the new well are fargreater than that of the old well. It indicates that the TSIOF tech-nique is more fitted for a new well produced from a reservoir withbottom water.

6 Conclusion

The theory analysis for water coning control by the TSIOFtechnique is presented and a special well completion design for avertical well is also given in this paper. A simulator consideringthe rheology of heavy oil is developed for the study of waterconing problems. The results of fine simulation show that theTSIOF technique is fitted for not only old wells that water coneoccurred but also for new wells. There are an obvious increase inoil production and decrease in water-cut of Sink 1 with the TSIOFtechnique. TSIOF technique is effective for heavy-oil reservoirswith bottom water. Although the TSIOF technique can alleviatewater coning problems, it is very difficult to eliminate completelyfor heavy-oil reservoirs.

NomenclatureB volume factor of fluidk absolute permeability of a porous media m2

kr relative permeability of a porous media

p pressure Paq production/injection rate m2 / s

Rs solution gas-oil ratio

S saturation

t time s

porosity of the porous media specific gravity of fluids. viscosity of fluid Pa s

potential

Subscripts

c capillaryg gas

o oil

w water

SI Metric Conversion Factors1.0 ton 1000 kg

1.0 MPa 106 Pa1.0 mPas 103 Pa s

Acknowledgment

The authors thank the International Petroleum TechnologyConference Copyright IPTC for the permission for the use ofthe authors one-time journal publication rights for IPTC Paper10521. The paper An Effective Method to Improve Recovery ofHeavy Oil Reservoir With Bottom Water Drive was first pre-sented at the International Petroleum Technology Conference heldin Doha, Qatar, November 2123, 2005.

References 1 Smith, C. R., and Pirson, L J., 1963, Water Coning Control in Oil Wells by

Fluid Injection, SPE J., 3, pp. 314319. 2 Chierici, G. L., Sobocinski, D. P., and Cornelius, A. J., 1965, A Systematic

Study of Gas and Water Coning by Potentiometric Models, JPT, 17, pp.

923928. 3 Wheatley, M. J., 1985, An Approximate Theory of Oil/Water Coning, The

60th Annual Technical Conference and Exhibition of the Society of Petroleum

Engineers, Las Vegas, NV, Sept. 2225, SPE Paper No. 14210. 4 Hoyland, L. A., Papatzacos, P., and Skjaeveland, S. M., 1989, Critical Rate

for Water Coning: Correlation and Analytical Solution, SPERE, 4, pp. 495

499. 5 Guo, B., Abass, H. H., and Bass, D. M., A General Solution of Gas/Water

Coning Problem for Horizontal Wells, The European Petroleum Conference,

Cannes, France, Nov. 1618, SPE Paper No. 25050. 6 Shirif, E., Guo, B., and Lee, R. L., 2002, Waterflooding Performance of

Stratified Reservoirs With Bottom-Water Condition, The SPE Asia Pacific Oil

and Gas Conference and Exhibition, Melbourne, Australia, Oct. 810, SPE

Paper No. 77963. 7 Abass, H. H., Shirif, K. E., and Hromek, J. J., 1988, The Critical Production

Rate in Water-Coning System, The SPE Permian Basin Oil and Gas Recovery

Conference, Midland, TX, Mar. 1011, SPE Paper No. 17311. 8 Khan, A. R., 1970, A Scaled Model Study of Water Coning, JPT, 22, pp.711713.

9 Wibowo, W., Permadi, P., Mardsewojo, P., and Sukarno, P., 2004, Behavior ofWater and Production Performance of Horizontal Well in Bottom Water Drive

Reservoir: A Scaled Model Study, The SPE Asia Pacific Conference on Inte-

grated Modeling for Asset Management, Kuala Lumpur, Malaysia, Mar. 29

30, SPE Paper No. 87046. 10 Pirson, S. J., and Mehta, M. M., 1967, A Study of Remedial Measures for

Water-Coning by Means of a Two-Dimensional Simulator, The 42nd Annual

Fall Meeting of the Society of Petroleum Engineers of AIME, Houston, TX,

Oct. 14, SPE Paper No. 1808. 11 MacDonald, R. C., and Coats, K. H., 1970, Methods for Numerical Simula-

tion of Water and Gas Coning, SPE J., 10, pp. 425430. 12 Graue, D. J., and Filgate, R. A., 1971, A Study of Water Coning in the

Kaybob South Beaverhill Lake Field, The 46th Annual Fall Meeting of the

Society of Petroleum Engineers of AIME, New Orleans, LA, Oct. 36, SPE

Paper No. 3623. 13 Woods, E. G., and Khurana, A. K., 1977, Pseudofunctions for Water Coning

in a Three-Dimensional Reservoir Simulator, SPE J., 21, pp. 251254. 14 Zakirov, S., Yulmetjev, T., and Zakirov, E., 2000, Enhanced Oil Recovery

From Oil Fields With Bottom Water, The SPE European Petroleum Confer-

ence, Paris, France, Oct. 2425, SPE Paper No. 65130. 15 Karp, J. C., Lowe, D. K., Marusov, N., 1962, Horizontal Barriers for Con-

trolling Water Coning, JPT, 14, pp. 783789. 16 Romero-Juarez, A., 1964, Characteristic of Oil Production Related to Water

Coning, SPE Paper No. 1089. 17 Islam, M. R., and Farouq Ali, S. M., 1987, Improving Waterflood Perfor-

mance in Oil Reservoirs With Bottom Water, The 62nd Annual TechnicalConference and Exhibition of the Society of Petroleum Engineers , Dallas, TX,

Sept. 2730, SPE Paper No. 16727. 18 Bowlin, K. R., Chea, C. K., Wheeler, S. S., and Waldo, L. A., 1997, Field

Application of In-Situ Gravity Segregation to Remediate Prior Water Coning,

The SPE Western Regional Meeting, Long Beach, CA, Jun. 2527, SPE Paper

No. 38296. 19 Shirif, E., 2000, Mobility Control by Polymers Under Bottom-Water Condi-

tions, Experimental Approach, The SPE Asia Pacific Oil and Gas Conference

and Exhibition, Brisbane, Australia, Oct. 1618, SPE Paper No. 64506.

20

Wojtanowicz, A. K., Xu, H., and Bassiouni, Z. A., 1991, Oil Well Coning

Control Using Dual Completion With Tailpipe Water Sink, The Production

Operations Symposium, Oklahoma City, OK, Apr. 79, SPE Paper No. 21654.

21 Shirman, E., and Wojtanowicz, A. K., 1988, More Oil With Less Water UsingDownhole Water Sink Technology: A Feasibility Study, The SPE Annual

Technical Conference & Exhibition, New Orleans, LA, Oct. 2730, SPE Paper

No. 49052. 22 Widmyer, R. H., 1995, Producing Petroleum From Underground Formation,

U.S. Patent No. 2855047.

23 Peaceman, D. W., 1977, Fundamentals of Numerical Reservoir Simulation,Elsevier, New York.

Fig. 15 Comparison of numerical cumulative oil production ofold well and new well




11/11

Binshan Ju (Ph.D., China University of Geosciences, Beijing, 2004) is a staff, who has 15 years experi-ence in the fields of petroleum engineering, in School of Energy Resources, China University of Geosciences(Beijing). His research interests include (1) Oil and gas development, (2) Petroleum geology and reservoirdescription, (3) Enhanced oil recovery and (4) Percolation flow mechanics in petroleum engineering andenvironmental sciences. He has finished over 15research projects and two oil reservoir numerical simula-tors for (CGFORS and ORSCPPCFS) for oil companies such as CNPC, CNODC and SinoPec, publishedover 30 scientific and technical papers in authoritative journals, and gained many honors and awards suchas excellent doctoral dissertation and excellent scientific research awards. e-mail: [email protected]


Documents

A Study to Minimise Bottomw Water Coning in Heavy Oil Reservoirs