HYDROCARBON INJECTION IMPROVES CONDENSATE RECOVERY IN U.S.S.R.

Rudolf Ter-Sarkisov
All-Union Scientific Research Institute of Natural Gas
Moscow

Alexander Gritsenko
NPO Soyuzgastechnology
Moscow

Treating producing zones with hydrocarbon mixtures can increase the flow capacity of wells in which the rate has decreased because of gas-condensate precipitation.

When an appropriate mixture is injected in a predetermined amount (volume per meter of producing interval), production can be increased by 10-20%. After treatment, producing rates can be stabi-lized for a period of several months to 2 years.

Wells producing from gas-condensate, depletion-drive reservoirs are considered to be the most suitable for stimulation. These wells can be characterized by:

• Initial liquid content in the formation (pentane plus high boiling fraction) exceeds 430520 cu m/cu m of gas (77-93 bbl/MMcf).

• Formation pressure is in the range 10-25% of initial pressure.

• Producing formation thickness is 15-80 m (49-262 ft).

For better results in stimulating a well, one should consider the nature of rock characteristics of the reservoir. Preferred formations for stimulation are porous-type reservoirs with permeability not higher than 10-13 sq m (100 md) and not lower than 10-15 sq m (1 md).

CONDENSATE PRECIPITATION

Developing gas-condensate reservoirs with widely spaced vertical wells causes variances in formation pressures. Large zones of lower pressure are located in the vicinity of the well bore. Depending on the formation, reservoir permeability, and production rate, the pressure at the well bore may be lower by a value from 1 to 30 MPa (145-4,350 psi).

As formation pressure decreases down to 20-25% of initial pressure, several hundred pore volumes of formation gas pass through the near well bore area. The accumulation of liquid hydrocarbon phase first reaches a threshold of hydrodynamic mobility (30-50% of pore volume and then is maintained at this level .12

The radius of the threshold saturation zone can increase to tens and even to hundreds of meters. As a result, permeability drops near the well bore, and the production rate decreases (Fig. 1).

Experience indicates that if the initial content of pentane plus high-boiling fraction in the formation gas is 350-450 cu m/million cu m (62-80 bbl/MMcf), one might not observe a well production decrease due to retrograde condensate precipitation. On the contrary, well production rate may increase as a result of a lighter liquid-hydrocarbon phase and retrograde condensate in the formation. In this case, the threshold saturation of the bottom hole zone is relatively small (Fig. 2). The liquid phase is easily filtrated, and well production rate is likely to increase (Fig. 3).

Field data from the case history of the Karadag gascondensate field' show a tendency towards increased production rates for wells that are higher and further from the oil fringe. These wells have less molecular mass in the liquid hydrocarbon phase.

In the case that the initial content of pentane plus high--boiling fraction in the formation gas exceeds 430-520 cu m/million cu m (77-93 bbl/MMscf), threshold saturation of the formation by the liquid hydrocarbon phase is relatively high. Thus, according to experimental data available for the Vouktyl field, threshold saturation amounts to 40-45% of the pore volume permeability. This may lead to a decrease in production rate.

There are some cases reported in the U.S.3 where in a low-permeability gas reservoir the threshold condensate saturation of about 50% of pore volume caused virtual impermeability for gas (e.g., in the Knox-Bromide field).

By maintaining formation pressure, such as by cycling, production rates can be prevented from decreasing. However, in some gas condensate fields this is not always acceptable because of technical and economic considerations.

INCREASING PRODUCTION RATE

Gas-condensate wells are chosen for stimulation if at the bottom hole zone the hydrocarbon condensate accumulated can cause an appar-ent drop of phase permeability that correspondingly will decrease the well's production rate.

Some experimental research by the authors shows the physical basis of the method to increase productive capacity at such wellS.4 5 6

In Fig. 4, a gaseous mixture of a given content was squeezed through the gas-condensate formation model at a pressure, reduced due to preliminary development in the depletion drive, of 25% of the dew-point of the initial mixture in the formation.

The liquid hydrocarbon phase before gas injection was about 15% of the system volume. Under conditions of depletion drive, the liquid phase would remain immobile because the liquid saturation is below threshold.

During gas injection, a swift increase of liquid phase volume in the system was observed. After injection of more than 11/2 pore volumes of gas, the liquid saturation reached 55% and the threshold value was exceeded.

A model simulation (Fig. 5) of a formation containing 30% of a liquid hydrocarbon phase proved that the two-phase filtrate exited the system during injection of the rich gaseous mixture. Further displacement of the formed mixture by dry gas (methane) allowed the reduction of the medium pore saturation of the liquid hydrocarbon phase from an initial 30% to about 10-12% of pore volume.

Reducing the saturation by that amount in typical gas condensate formations, such as dolomites, would allow production rates to double if the bottom hole zone is 100% covered by the injection agent (Fig. 1).

For maximum effect after a well treatment, the injected gaseous mixture should include components that easily transform into a liquid phase. And then with further dry gas (methane) displacement, these components need to easily evaporate and be produced together with the gas.

Such intermediate hydrocarbon components as ethane, propane, and butane have appropriate properties. The right proportion of these components in the injection gas determines the stimulation effect.

If the formation pressure is reduced to the level equal to 10-15% from the dew point pressure, the injected gas would not retain the necessary amount of intermediate components in the gaseous phase and the agent would transform into a two-phase state regardless of the contact with liquid hydrocarbon phase.

In this case, the preferable stimulation is a gaseous mixture with a step-by-step injection of a light liquid hydrocarbon mixture composed of ethane, propane, and butane. This injection is followed by dry gas (methane) to enable a significant reduction in liquid saturation compared to an untreated well.

In this case, the stimulation effect is determined by a pro-portion of intermediate components in the injected hydrocarbon liquid and the amount of injected dry gas.

In one well, treatments can be carried out no more than two or three times. Therefore, it is expedient to use existing field connections to measure and deliver the mixture into a well. Typical piping schemes for research and injecting agents into a well are shown in Figs. 6 and 7.

Depending on formation conditions, lines to feed additional components, such as methanol, may be needed.

Portable measuring units at the inlet are suggested to measure both the liquid and gas injected.

VOUKTYL FIELD

About ten wells were treated in the Vouktyl gas-condensate field. The field produces from carbonate reservoirs of lower Permian that are of the fractured, porous type.

At 3,350 m (10,990 ft), the initial formation pressure was 37 MPa (5,336 psi). Initial hydrocarbon content of pentane plus high-boiling fraction was 520 cu m/million cu m (93 bbl/MMcf). Average effective thickness of the productive deposits is 115 m (377 ft), with significant variations in certain wells.

Average reservoir permeability is about 10 -14 sq m (10 md). Average porosity is 8%.

The field is under depletion drive. Maximum average formation saturation by retrograde hydrocarbon condensate is 13-15% of pore volume at a pressure of about 10-15 MPa (1,450-2,176 psi).

According to experimental data, threshold saturation is 40-45% of pore volume for the precipitated hydrocarbons.

Some laboratory simulations were done prior to the stimulation work.

The Vouktyl wells were treated by a gaseous agent. Because the reservoir is considerably nonhomogeneous, treatment success was ap-proximately 50%. To save time and resources, the nonhomogeneity in the wells was not evaluated.

In a well treatment, two typical periods are distinguished. During the first short-term period lasting several days, quick wave-like changes of gas-condensate factor and molecular mass of the product were observed (Fig. 8). This period corresponds to the process of removing the injected mixture consisting of hydrocarbon solvent and precipitated condensate zone near the well bore.

The second period is basically the period when the stimulation effect occurs. This period may last from several months up to 1 or 2 years. During this period, a slow change of liquid characteristics and consequently an increase in well production is observed.

Fig. 9 shows the results of gas-dynamics studies of one of the treated wells during the second period. The treatment led to a considerable increase in the wells' productive capacity. The stimulation effect lasted for about 2 years.

Interesting results were obtained on one of the wells treated initially by gaseous agent. The well was retreated some years later but by a light liquid-phase hydrocarbon solvent that was forced deep into the formation by dry gas.

This well, No. 177, is located on the east side of the middle part of productive structure in the vicinity of the gas processing plant .3

Intervals 3,203-3,224 and 3,280-3,290 m (10,50910,577 and 10,761-10,794 ft) of the middle carbon Moscow are gas bearing. Well No. 177 was first treated by gaseous agent in February 1985 when the average formation pressure was down to 9 MPa (1,305 psi). This pressure is about 25% of the dew point pressure of the initial gas.

As a result of well treatment, the condensation factor was changed for a long period of time, and the productive rate went up substantially (1 0-20%).

In the year following the treatment, the additional gas recovered was about 1.5 million cu m (52.9 MMcf), with condensate recovery above 1,500 cu m (9,436 bbl). About 2 years after the treatment, the effect was not tangible.

In April 1988, when the average formation pressure in the well had decreased to about 6 MPa (870 psi), or 15% of the initial pressure, a second stimulation on the well was performed in such a way that condensate which had precipitated deep into the formation was removed.

About 1,600 cu m (5,032 bbl) of light liquid hydrocarbons and then 1.1 million cu m (38.8 MMcf) of dry gas were injected into the well. This amount of agents was several times greater than that which was used for the first treatment 3 years before.

After the second treatment production improved substantially. The well became stable and the production rate increased. A year after the treatment, productive capacity exceeded the initial (before treatment) by about 20%.

After a year on stream, additional production was 750 cu m (4,717 bbl) of condensate and about 5.5 million cu m (194 MMcf) of gas.

Treatment of other wells, either by the first or second method, was effective. In most cases it was less than in Well No. 177, but there wasn't a single stimulated well with negative consequences. In the worst case, improvement in production rate was not observed, but in all cases stability of production was reached.

REFERENCES

1. Durmishyan, A.G., Gas-condensate fields, Nedra, 1979, pp. 260-64.

2. Ormerod, L., Todd, A., Tweedie, J., and Ashcroft, J., "Techno-economic modeling of gas-condensate development," Chemical En-gineering Research and Design, Vol. 65, No. 1, 1987, pp. 97-106.

3. Gritsenko, A.I., and Ter-Sarkisov, R.M., and Klapchyuk, O.V., and Nikolaev, V.A., "Injection of liquid hydrocarbons into reservoir," Obz. inf. Ser. Razrabotka i ekspluatatsiya gazovych i gazokondenstnykh mestorozhdenii, Vniiegasprom, No. 6, 1980, pp. 20-25.

4. Ter-Sarkisov, R.M., "The use of enriched gas for condensate en-hanced recovery," Gazovaya promyshlenost, No. 10, 1982, pp. 26-28.

5. Nikolaev, Y.A.. "On study of physical basis of recovery of dispersed liquid hydrocarbons," Tekhnologicheskie problemy osvoeniya gazokondensatnykh mestorozhdeniy, Vniigas, 1986, pp. 50-58.

6. Basnie, V., Bedrikovetsky, P., Nokolaev, V., and Ter-Sarkisov, R., "Hydrothermodynamics of hydrocarbon fluid displacement by solvents," Fifth European symposium on improved oil recovery, Budapest, 1989, pp. 175-182.

7. Ter-Sarkisov, R., et al., "The use of enriched gas for condensate enhanced recovery at the Vouktyl gas-condensate field," Povyshenie nadezhnosti sistem razrabotki mestorozhdeniy prirodnogo gaza, Vniigas, 1985, pp. 128-137.

8. Ter-Sarkisov, R., et al., "Condensate enhanced recovery on the basis of hydrocarbon solvents at the Vouktyl gas-condensate field," Osobenosti osvoeniya mestorothdeniy Prikaspiiskoy vpadiny, Vniigas, 1986. pp. 67-71.

Copyright 1991 Oil & Gas Journal. All Rights Reserved.