Improved Gas Lift Proposed For Hungarian Field

Gabor Takacs, Zoltan Turzo
University of Miskolc
Hungary

Changes in parameters such as tubing size, wellhead type, and gas lift pressures can improve the profitability of gas-lifted oil wells.

As an example, using field data and computer calculations, optimum tubing size and injection pressure were determined for the largest oil field in Hungary, the Algy" field, near Szeged.

Most wells in the field are on continuous-flow gas lift designed in the late 1960s with unique features dictated by the economics and technology of those times.

Proper operation was maintained until recently, but changes in reservoir parameters because of depletion have led to many unfavorable conditions that have increased lift gas requirements and raised production costs.

In this example, the widespread use of wellhead chokes for controlling well production rates are shown to be detrimental. With assumed optimum conditions, total required gas lift volumes are calculated and compared to current quantities.

The system modifications proposed by the authors could significantly improve the economics of the Algy" production operations.

Algy" field

Algy" field is the largest oil and gas accumulation in Hungary. The field is in the southern part of the country near the city of Szeged.

Discovered in 1965, the field had an original oil in place of 629 million bbl and large gas reserves of 4 tcf. The main producing horizons, 76 in total, are heavily layered sandstone formations having large gas caps and thin oil edges. The reservoirs are highly heterogeneous, delta-type sediments. Produced crude oils are light, sometimes volatile.

To date, 1,000 wells have been drilled, with depths between 5,900 and 6,900 ft.

Algy" is a mature field past its peak production rate of about 21,600 bo/d. Reservoir management involves water injection at the gas/oil and the water/oil contacts. The gas caps and the oil reservoirs are produced simultaneously.

The field is experiencing a continuous but slow drop in reservoir pressure and a more rapid increase in water cut.

Gas lift system

Today, about 65% of the field's total liquid production is with continuous gas lift. About 226 wells are on gas lift and, of these, about 20% are dual installations.

The basic design parameters of the gas lift system were determined in the late 1960s. The technical and economic situation during that time required special solutions, such as:

• An extremely high, 1,740 psi, injection pressure to reduce the number of required gas lift valves.

• A 2,320-psi pressure for unloading the wells. This high-pressure required having a dual-pressure injection gas distribution network.

• Mostly simple orifice valves in the gas lift mandrels instead of gas lift valves.

• Gas injection through existing, preinstalled valve mandrels without determining an optimum injection point.

• Controlling liquid production rates with wellhead chokes on most wells.

Although some of these solutions are also used in other parts of the world, the Algy" gas lift system is far from a conventional case. But in spite of its special features, the system met the technical and economic requirements at the time of its design.

However, with depletion, the field conditions underwent many significant changes such as a continuous drop in formation pressure and a rapid increase in water cut. Because of those changes, production costs have increased steadily in recent years.

The field operator, MOL Plc., initiated a general survey of production practices and contracted the petroleum engineering department of the University of Miskolc to help improve the gas lift economics.1 2

Analysis methodology

In general, lift gas requirements for continuous gas lift are basically determined by three operating parameters: injection pressure, wellhead pressure, and the size of tubing.

The Algy" field study evaluated all of these parameters along with the effect of the wellhead chokes.

Measured, calculated data

The study included collecting field-wide production performance as of July 1994 and processing all relevant well parameters for 185 wells.

Because the study did not aim at establishing optimum conditions for each well but rather at a general evaluation of field practices, key wells representing the conditions of various formations were set up.

These key wells, combined with computer programs, allowed us to reliably simulate the operational parameters of the Algy" gas lifted wells.

Computer predictions compared current field practices to optimum conditions. The computer program Cont lift3 was used to calculate the lift-gas requirements of continuous flow gas lift.

This program, based on the surface injection pressure, finds the required injection depth (depth of operating gas lift valve) as well as the injection gas volume. Wellhead pressure is usually assumed to be equal to the minimum pressure needed to transfer the well stream to the separator.

These assumptions are crucial for an optimum gas lift design, but they deviate considerably from the actual conditions prevailing at Algy". In the field, gas is not injected at the ideal depth, but at the depth of an existing valve mandrel. Also, wellhead chokes are installed for controlling liquid rates.

Because of these conditions, calculated and measured gas requirements will differ considerably.

Key wells

To exclude the effects of variations in the main formation parameters, calculations were conducted for each main productive formation in the field. To improve statistical reliability, the analysis included only the most significant data from key wells for each formation. Liquid rate was the criteria for selecting key wells.

For each formation, the liquid rate ranges of individual well rates for 95% of the wells were determined (Table 1 [8534 bytes]).

Using measured field data, key wells with average properties were created for each formation. Table 2 [8534 bytes] shows the main parameters along with the number of wells represented.

As seen, 185 gas-lifted wells are included in the study. Before actual calculations were started, a check was done on how representative the key wells were for each formation. Measured total liquid and lift gas volumes were compared to the values calculated using the key wells.

The field-wide measured liquid rate of 53,900 b/d compares well to the calculated 51,500 b/d. Measured and calculated gas requirements were 26.5 MMscfd and 26.7 MMscfd, respectively.

Because these values are in excellent agreement, it shows that key wells effectively represent the average conditions of the formations.

Tubing size

The Algy" field has two tubing sizes, 23/8 and 27/8 in. To analyze tubing size on lift gas requirements, measured injection gas volumes were evaluated first.

Fig. 1 [31801 bytes] shows lift gas consumption for the different formations. As seen, except for the Szeged-1 zone, gas requirement for the larger tubing size is greater than for the smaller one. This phenomenon can be attributed to the different wellhead pressures in the two cases.

Using key wells, the program Contlift found the lift gas requirements with the Duns-Ros4 and the Orkiszewski5 vertical multiphase flow correlations. Wellhead pressures were assumed to be equal to actual field values that, because of the effect of wellhead chokes, were considerably higher than optimum.

Table 3 [8534 bytes] summarizes the average field data along with calculated injection depths and injection gas volumes.

As seen, calculated and measured gas/liquid ratios (GLRs) differ considerably. The main discrepancies are caused by the computer program using optimum depths for gas injection whereas actual injection depths are different.

It is also obvious from both vertical flow correlations, that the smaller tubing, 23/8 in., decreases injection gas requirements, as compared to the larger tubing.

To further investigate the effect of tubing size on gas lifting, an additional study was conducted. It involved calculating lift gas volumes for a wellhead pressure of 290 psi, the pressure needed to transfer the well streams to the separators.

Fig. 2 [30883 bytes] compares field data with the values calculated by the Orkiszewski correlation, previously found to properly simulate Algy" conditions. The figure proves that gas lifting under optimum conditions would considerably reduce the injection gas required for each formation.

Wellhead pressure

The positive effects of decreasing wellhead pressure on lift gas requirement can be calculated based on the following assumptions:

• Optimum conditions are assumed. These include gas injected at the deepest possible depth, and no wellhead choke is installed.

• The Orkiszewski correlation determines the injection gas requirement.

• The technical feasibility of reducing separator pressure is not investigated.

• Specific and daily lift gas volumes were calculated for wellhead pressures of 145, 218, and 290 psi.

Fig. 3 [28008 bytes] summarizes the results and also includes the field measured GLRs. As seen, actual field values are much greater when compared to all assumed cases. The main reason is the presence of wellhead chokes.

Fig. 3 also shows that current lift gas quantities could substantially be reduced if the wellhead pressures are reduced to an easily attainable 290-psi level. This case is important because a wellhead pressure of 290 psi is sufficient to transfer the well streams to the separators operating at 260 psi.

Decreasing the wellhead pressure below 290 psi does not drastically change the required amount of injected gas as compared to the amount saved by changing the wellhead pressure from the current pressure to 290 psi. Based on this, we conclude that even without any changes to the field's current surface gathering system, optimization of Algy" gas-lifted wells can result in substantial savings.

Table 4 [34717 bytes] shows lift gas requirements for the wellhead pressures investigated. If compared to current conditions, decreasing the wellhead pressure to 290 psi and injecting gas at ideal depths, for the 185 wells studied, results in saving over 21 MMscfd of lift gas.

It should be noted that because of inaccuracies in the vertical multiphase flow correlation used, these numbers can contain some errors. Accuracies of 10-20% are common. But the savings, if corrected to account for such factors, are still substantial.

Wellhead chokes

Because the Algy" field has high injection pressures, and simple orifices are used instead of gas lift valves, wellhead chokes are installed to control flow rates.

Surface chokes, however, substantially reduce continuous gas lift economics because the pressure drop across the choke greatly increases energy losses. An undesirable consequence of wellhead chokes, discussed earlier, is the effect of wellhead pressure on lift gas quantity.

A systems (Nodal) analysis method further investigated the surface choke problem. Calculations used an example Algy" well with the data shown in Table 5 [14103 bytes].

For Nodal analysis, the solution node was placed at the wellhead, upstream of the choke. The production system of the well was divided into subsystems comprised of the productive formation and the tubing string, and the surface choke, flow line, and separator. The two cases investigated were with and without a wellhead choke.

Fig. 4 [23579 bytes]displays the calculated performance curves. It is easy to see that removal of the wellhead choke greatly increases the well's liquid production rate for the current injection GLR. Because the increased liquid rate is greater than the allowable, the target production could more efficiently be attained by injecting less gas into the tubing.

A decreased injection GLR of 111 scf/bbl and use of a larger surface choke, 0.35 in., as indicated by a modified Performance Curve 4, would result in a flow rate very close to the current value. Therefore, flow rate control can be more economical by increasing the surface choke size and by injecting less gas than allowed by the current practice of extensive choking.

Proposed modifications

Based on the Algy" field study, the authors developed a set of proposed improvements for the field.

Fig. 5 [28058 bytes] illustrates current and proposed conditions for an Algy" well. Currently, a high-pressure differential of 466 psi occurs through the downhole choke instead of the gas lift valve. Calculated gas injection volume through the installed 0.06-in. diameter choke is about 103 Mscfd. This compares well to the measured injection gas/liquid ratio.

To improve the economic parameters of gas lifting in Algy", the following improvements and modifications are proposed:

• Decreasing the surface injection pressure

• Removing wellhead chokes

• Using gas lift valves for gas injection.

An ideal injection gas pressure at injection depth equals the tubing pressure at the same depth plus the pressure drop in the gas lift valve. In the example well, the surface injection pressure corresponding to this value is 1,378 psi, compared to 1,740 psi used in the field.

Because the wellhead choke is removed, wellhead pressure equals the input pressure required to transfer the well stream to the separator, for example 290 psi. After calculating the injection gas volume required for continuous flow gas lift, it was found that an injection volume corresponding to a GLR of 56 scf/bbl was sufficient to lift the given liquid rate.

Gas usage, as compared to the current value of 232 scf/bbl, decreased to one fourth of its original level.

A comparison of current and proposed conditions for the entire Algy" field showed1 that the proposed modifications would greatly improve production operation economics. The improvements mean that, while maintaining the same liquid production from the wells, less lift gas volumes are needed at a lower injection pressure.

Therefore, this saves substantial gas compression requirements and consequently lowers production costs.

Under the proposed conditions, control of the wells' liquid production becomes easier because downhole gas injection occurs through a gas lift valve ensuring a controlled injection.

Currently, with the 1,740 psi injection pressure, the well's liquid rate is primarily determined by the downhole choke's gas throughput capacity. Well flow rates in Algy" being relatively low, the choke sizes needed are, in most cases, very small, or even impractically small. This is the reason why one must inevitably install surface wellhead chokes to control well rates.

The disadvantages of this practice, as it was shown previously, leads to very inefficient and costly gas lift operations.

Acknowledgment

The authors wish to express their gratitude to the management of MOL Plc., operator of the Algy" field, for the permission to publish this article.

References

1. An evaluation of the Algy" oil production system, Research Report, Petroleum Engineering Department, Miskolc University, 1994.

2. Improving fluid lifting technology, Research Report, Petroleum Engineering Department, Miskolc University, 1994.

3. Contlift Program Manual, Version 1.1., G. Takacs, 1989.

4. Duns, H., and Ros, N.C.J., "Vertical flow of gas and liquid mixtures in wells," 6th World Petroleum Congress, Frankfurt, 1963.

5. Orkiszewski, J., "Predicting two-phase pressure drops in vertical pipe," JPT, pp. 829-38, 1967.