CANADIAN HEAVY OIL ASSOCIATION

SPE/PS-CIM/CHOA 97370 PS2005-306

Application of Gas Lift to Heavy-Oil Reservoir in Intercampo Oilfield, VenezuelaD. Hong'en, C. Yuwen, and H. Dandan, RIPED, PetroChina Co. Ltd., and C. Wenxin and Z. Guozhen, CNPC America Ltd.

Copyright 2005, SPE/PS-CIM/CHOA International Thermal Operations and Heavy Oil Symposium This paper was prepared for presentation at the 2005 SPE International Thermal Operations and Heavy Oil Symposium held in Calgary, Alberta, Canada, 1–3 November 2005. This paper was selected for presentation by an SPE/PS-CIM/CHOA Program Committee following review of information contained in a proposal submitted by the author(s). Contents of the paper, as presented, have not been reviewed by the Society of Petroleum Engineers, Petroleum Society–Canadian Institute of Mining, Metallurgy & Petroleum, or the Canadian Heavy Oil Association and are subject to correction by the author(s). The material, as presented, does not necessarily reflect any position of the SPE/PS-CIM/CHOA, its officers, or members. Papers presented at SPE and PS-CIM/CHOA meetings are subject to publication review by Editorial Committees of the SPE and PS-CIM/CHOA. Electronic reproduction, distribution, or storage of any part of this paper for commercial purposes without the written consent of the SPE or PS-CIM/CHOA is prohibited. Permission to reproduce in print is restricted to a proposal of not more than 300 words; illustrations may not be copied. The proposal must contain conspicuous acknowledgment of where and by whom the paper was presented. Write Librarian, SPE, P.O. Box 833836, Richardson, TX 75083-3836, U.S.A., fax 01-972-952-9435. Abstract

This paper presents successful applications of the gas lift to heavy oil reservoirs in Intercampo oilfield, Lake Maracaibo. Liquid production rate ranges from 50 to 2000 bbl per day per well, gas lift was selected as the first artificial lift method in the oilfield. The paper expresses the gas lift mechanisms in high water cut with lower API degree in heavy oil reservoirs. The theory analysis showed that injection gas rate of gas lift and GOR of oil well have direct effects on fluid flow state in wellbore.

Scenarios of theory design and actual production of gas lift were described in the paper. For artificial lift design, the paper points out the correlation equations of gas lift for heavy crude reservoirs that their flow behavior of actual situation should not characterized by present equations, therefore, there are big error value between theory design and actual production when producer is high water cut with lower API degree. In addition, the error created reason was analyzed and oil well normal production in high water cut stages with lower API degree was emphasized, in the case, emulsion of water and oil should not happen.

A corrected coefficient of gas lift design was provided under the high water cut with lower API degree. Nowadays, for the new correlations are very preliminary that will need to be developed by means of production engineers and researchers further. It is particularly important to production engineers in optimization and design of gas lifting equipments.

Introduction

Continuous gas lift has been employed in lifting heavy crude many yeas ago. The gas lift method was applied in former Soviet Union and Venezuela widely. In fact, heavy oil has at

large introduced to continuous gas lift in Venezuela, of which density is between 0.934 ~0.9659g/cm3 and viscosity is lower than 50cp.

Experimental study shows that when 3% hydrocarbon solvent is injected, daily oil production will increase. Actual data from oilfield show that if water cut were lower than 40%, the result is true; while water cut was higher than 50%, the hydrocarbon solvent effect will be worse, or even no effect will turn up when water cut was higher than 70%.

In traditional opinions, rod pumps were the best artificial lift method in heavy oil reservoirs, especially for heavy crude oil density between 0.96�1.0g/cm3.

Some scholars previously thought that gas lift would not be suitable for lifting in heavy oil well of lower GOR. Perhaps the conclusion can be explained as that the heavy oil well might not supply sufficient gas for gas lift, but it cannot prove that gas lift is no good for heavy oil well. In allusion to this point, this paper discusses gas lift is achievable for lifting low API heavy oil and taking as the first artificial lift method from theory analysis and production practice in oilfields.

Generally, many literatures reported the flow behaviors of gas lift same as natural flowing in vertical or near-vertical wells. In fact, change of phase regimes brought about by gas lift is much more complex than that of natural flowing, because high velocity gas enters into tubing through gas lift valve to mix with oil-gas-water of reservoir fluid, bringing not only external gas mass but also external energy supplement. The high velocity flow forms new multiphase fluid regime, which is transitional flow, change from liquid phase to a continuous gas phase occurs. Gas bubbles join together, and the liquid may be entrained in the bubbles. Although the liquid phase effects are significant, the gas phase effects are dominant. Then annular flow /mist flow occurs, the gas phase is continuous, and the liquid is entrained as droplets in the gas phase. Gas phase controls the pressure gradient. and it does not follow the three types of flow regimes in vertical tubing gas/liquid flow, consisting of bubble, slug and plug and mist flow from the bottomhole to wellhead. Factors influencing the flow regimes include borehole deviation, proportion of each phase; relative differences in phase densities, surface tension, and viscosity of each phase, average velocity, tubing roughness and chock size. However, kickoff pressure / casing head pressure is a function of above named factors.

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When gas lift was used to produce low API heavy oil with high water cut, many correlations published for predicting flow parameters are not suitable, which only suit black oil with high API gravity over 17 degree, and cutoff value of water cut of 60%. According to literatures report, emulsion should be formed at water cut of 50% severely. Black oil correlation of Woelflin is used at water cut less than or equal to the cutoff value. Therefore, the correlations could be applied neither for higher water cut nor for a new flow that is large numbers of gas being injected into tubing through gas lift valve. A new correlation needs to be established by researchers in order to calculate pressure drop in this case and the design power of surface facilities.

A new theory for lifting low API heavy oil with high water cut by gas lift was present. In addition, the study gained a correction factor to kickoff pressure/casing head pressure (CHP) predicted by use of some prevailing business software, also worked out a regression correlation in low API heavy oil with high water cut for predicting kickoff pressure with oilfield data.

Reservoir Description BASUP-53 reservoir is located in the northeast on the Lake Maracaibo, which belongs to Intercampo contract area and has been taken over by CNPC America Ltd., Venezuela. The lake depth is about 7 to 26 meters and the whole area is 39.56 square kilometers. At present, the reservoirs in the contract area can be classified to three types, heavy oil reservoirs of mid-high permeability in upper formation of Miocene, middle-heavy oil reservoirs of high permeability in middle formation of Miocene, and low permeability middle-heavy oil reservoirs in lower formation of Eocene. The main BASUP-53 reservoir in district structure is located in the downthrown of PUEBLO VIEJO Fault, In regional structure, the main part of BASUP-53 reservoir is a dipping to south monocline located on the down faulted block. In the north of the reservoir, there developed a north-south strike reverse fault dipping to east whose fault throw is about 100-500ft, and this fault dissected the BASUP-53 reservoir into two parts—the upper and downthrown fault blocks. The average API gravity is 14.3 degree and viscosity is about 40~763cp under the heavy oil reservoir condition (see in Fig.1). The API gravity usually ranges from 11 to 17, with the lowest API to 10 and the highest API up to 23. Therefore, the well liquid property is not good and the reservoir belongs to difficultly produce heavy oil reservoir. Presently, pilot test is going on. The BASUP-53 reservoir data is shown in Tab.1

New Theory for Lifting Low API Heavy Oil

Usually, fluid configuration and flow regime of heavy oil keeps unchanged along wellbore when heavy oil is produced with artificial lift equipment except gas lift. Generally, bubble and liquid fluid appears in the bottom of tubing. When gas volume is about 3 to 4 times as liquid volume, the fluid regime shall turns into slug flow. For the low GOR of heavy oil, the whole lifting process keeps mixture fluid of bubble and liquid.

However, for gas lift, the single fluid regime does not exist. Some scholars considered flow regimes of gas lift same as nature flowing. However, this opinion could not accord with

the actual field production. Actually, the flow regime is different from that of nature flowing and other artificial lift methods.

For gas lift, gas enters into tubing through gas valve port and mixes with reservoir fluid. When gas rate is high, gas will break the primary continuous fluid into small oil drip or foamy fluid to form annular fluid regime. In addition, if the gas flow velocity is high enough, shear stress between bubbles and fluid film will increase to make both bubbles and fluid film into oil mist. In other words, it is entirely possible to form foamy-oil flow in gas-lift. This fluid regime can greatly reduce the density of mixed fluid. Thus, the mixture viscosity is obviously reduced and flow condition in wellbore is greatly improved. Actually, flow regime presents a transition state of foamy flow during the gas-lift process. With increase of lift height, the pressure will fall gradually; more gas will be released again; flow velocity will gradually increase once more, and mist flow will be formed the second time, fluid regimes were showed in Fig.2 for gas lift.

According to the general theory, in lifting heavy oil with low API, heavy oil and water is emulsified severely when water cut ranges from 60% to 85%. It is assumed that emulsification appears in wellbore during gas lift, so more power is needed to lift well fluid to the wellhead, gas lift kick off increases undoubtedly. Nevertheless, it has been proved by production practice in the oilfield there is no emulsification phenomenon occurred under the water cut. Why the phenomenon commonly encountered in other lift method does not happen in gas-lift? Even though oil and water had slight emulsified in wells, under the scouring of high-speed flow of massive lift gas, the primary phase was broken and the new phase was set up. It can be said that both flow in the wellbore and the fluid flow through multi porous media are transition. Moreover, flow regime of each point along the wellbore is thus independent or different. The explanation and calculation of pressure drop gradient and friction of multi-phase flow in wellbore based on general emulsification curve, in particular for gas-lift, are all with relatively big errors.

Lifting crude oil with high water cut, emulsification would be worse between crude oil and water for the artificial lift methods except gas lift, no matter rod pumps (sucker rod pump, progressive cavity pump) or rodless pumps (electric submersible pump, hydraulic pump). The traditional viewpoint is that gas lift could not meet to heavy or extra-heavy oil lifting, in fact, sharp changing of flow regime forms no more steady emulsification for gas lift.

Due to continuous gas injection, pressure increases in tubing and amount of natural gas resolves into crude oil. Then a part of crude oil turns up to foamy oil after resolving gas, the mixture density goes down, and the discharging pressure drops. Therefore, the flowability of mixture and lift condition is improved, and extra-heavy oil is produced with gas lift successfully.

Production Examples

There were 110 wells produced by continuous gas lift except eight ESP wells in the oilfield; average daily liquid production of these wells is about 4760.8m3/d; average daily oil

SPE/PS-CIM/CHOA 97370 3

production is 2456.35m3/d; water cut is 48.2%. Liquid production rate ranges from 50 to 2000 barrels per day per well. At present, the actual consumption was 104.7×104m3 per day. The gas consumption was about 0.952×104m3 per well and GOR was 219m3/m3. The data of heavy oil/extra-heavy oil well with low API and high water cut wells was shown in Tab.2. The change of CHP with water cut was analyzed by design software, and results were shown in Fig.3. The calculated CHP value reached up to 11.3MPa and 12.1 MPa in well BA2387and BA2321 respectively, whose water cuts are approximately 80% to 90%. However, the field data indicated that BA2387 produced 156m3/d liquid with water cut of 79%, lift gas rate of 147.84m3/d and CHP of 6.8MPa. Well BA2321 production liquid reached 133m3/d with water cut of 89.5%, lift gas injection rate of 227.72m3/d and CHP of 6.5MPa. Comparing the two results between the calculation of software and the actual wellhead lift pressure, the gap is between 5 to 6 MPa. Therefore, it can be concluded primarily that the correlations of present business software were not good for field production by gas lift in high water cut with low API.

Correlation

Many correlations are used to suit black oil with API gravity more than 17 degree and cut off of water cut of 60%. The correlations are not applicable for high water cut from 50% to 95% with low API from 11 to 16 degree in heavy crude oil. Even viscosity correction is performed; the correlations could not express the actual oil well condition. In fact, the actual pressure loss calculation in wellbore does not have the corresponding correlations after emulsification. Usually, Orkiszewski method was adapted to make sure flow regime prediction and pressure gradient calculation for gas lift. However, this method could merely consider flow mass change without gas injection and power supplement. New energy balance equation will need to be present when the multiphase flow regime of oil-gas-water is set up through valve port under the external gas injection. New correlation of prediction multiphase flow regime will be established. Consequently, it is a new research task in multiphase area.

According to statistic results from some wells in high water cut with low API degree, the paper points out that the design CHP needs to multiply with a corrected coefficient at water cut of 70% to 80%. Then it is validated that this corrected coefficient value is from 0.5 to 0.6. After correction, CHP of well BA2387 was assured from 5.65 to 6.78 MPa and well BA2321 was between 6.05 to 7.26 MPa, which presents a low error with the actual value.

To regress by oilwells data, the following regression correlation is proved to approach the actual value, the applying condition is adapted to oilwell CHP calculation with approximately 11 API, and water cut from 50% to 95%.

495472828.95f-59.585f0.54215f-0.0018fP w2w

3w

4w ++=

The above examples have proved that heavy oil with high water cut and low API does not emulsify to lead CHP increase. Even if emulsification occurs, the relatively high gas injection amount would break the emulsion condition. In addition, with

water cut increasing, lift gas amount and CHP change slightly, because density of mixture fluid goes up with water cut.

According to these, no emulsion breaker is required anymore when gas lift is employed in high water cut with low API in heavy oil reservoir. Gas lift method brings relative easiness to deal with heavy oil and extra-heavy oil. So it is the best choice to such oilfield.

Conclusions

1. The flow regime of gas lift is different from nature flowing and other artificial lift methods. In the process of lifting heavy crude oil, it changes flow regime in wellbore and makes foamy oil condition appearing mostly. Then the mixture density goes down, and gas lift becomes easily produced for heavy oil. Therefore, gas lift is the first choice for producing heavy and extra-heavy oil.

2. It is proved in Intercampo oilfield that gas lift can produce heavy oil successfully in high water cut with low API degree and no emulsification exhibits, which is better than the other artificial lift methods.

3. Multiphase fluid correlations do not meet with the actual field production by using in the pressure gradient and friction loss calculations for gas lift. The authors present correction coefficient and regression correlation to approach the actual value of field, but they are very preliminary that will need to be developed by means of production engineers and researchers further.

Acknowledgement

The authors wish to thank CNPC America Ltd., Venezuela for granting permission to publish this paper. Also, thank RIPED, Petrochina Company Ltd. for support.

References

1. Kermit E.Brown, The Technology of Artificial Lift Methods, Vol.2a, Pennwell Publishing Company, Tulsa, 1980

2. Kermit E.Brown, The Technology of Artificial Lift Methods, Vol.4, Pennwell Publishing Company, Tulsa, 1984

3. Abdel Wally et al, “Study Optimizes Gas Lift in Gulf of Suez Field,” Oil & Gas J., June 24 1996, pp.38-44

4. Shahaboddin Ayatallahi et al, Method Optimizes Aghajari Oil Field Gas Lift,” Oil & Gas J., May 21 2001, Vol.99, No.21

5. Juan Carlos Mantecon et al. “Dynamic Simulation Estabishes Water-Cut Limits for Well Kickoff”, JPT, May 2005, pp64~65

6. Edinburgh Petroleum Services Ltd. “FloSystem User Documentation”, Version 3.6, Sept. 1999

7. Baker Jardine Petroleum Engineering and Software, “Pipesim 2000 User Guide for Windows”, 2002

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Tables Tab.1 Basic data of BASUP-53 reservoir

Sedimentary Lake-river delta Original pressure (MPa) 13.3

Oil-bearing area (km2) 9.243 Saturation pressure (MPa) 12.16

Valid thickness (m) 32.92 Geothermal (�) 76

OOIP (104m3) 5829.25 Coefficient of pressure 0.95

Porosity (�) 30 Geothermal gradient

(�/100m) 3.42

Oil saturation (�) 72 Datum depth (m) 1402

API 14.3 Put into production (year) 1955

Oil density (g/cm3) 0.971 Well spacing 300

Oil-viscosity @ underground(cp) 40~700 Well pattern Three-spot

Reservoir depth (ft) 4330�5103 Drive type Natural water drive and solution

gas drive

Permeability (µm2) 783 Recovery percent (%) 2.99

Shale content (%) 2.38 Water cut (%) 48

Tab. 2 Production parameters of several typical well for lifting low API heavy oil

Daily liquid rate

Daily oil rate Water-cut GOR

Middle depth of reservoir

Reservoir pressure

Saturation pressure

Reservoir temperature

Gas density

Well No. Reservoir API m3/d m3/d % m3/m3 m MPa MPa � g/cm3

BA2421 BS53ZT 11.7 100 82 18 16.8 1420- 1429 12 12.1 76 0.7

BA2387 BS53ZT 11.8 156 33 78.6 133 1448- 1468 12 12.1 76 0.7

BA2359 BS53ZT 15.7 111 110 0.9 7.7 1426- 1478 12 12.1 76 0.7

BA2321 IS09ZT 16.6 133 14 89.5 181.5 1491- 1768 13 12.1 76 0.7

SPE/PS-CIM/CHOA 97370 5

Figures