NGL Recovery Being Hiked By Natural-gasoline Recirculation

Margiori Rivas M., Jos? Luis Bracho
Lagoven S.A.
Maracaibo, Venezuela

James E. Murray
Consultant
Corpus Christi, Tex.

The project is the result of a study of condensate-stream recirculation and absorber operations at the compression plants T!a Juana 2 (PCTJ-2) and T!a Juana 3 (PCTJ-3), offshore Lake Maracaibo in western Venezuela.

Lagoven is an operating affiliate of Petr?leos de Venezuela, S.A., Caracas.

Original designs

The PCTJ-2 and PCTJ-3 gas compression plants have two systems: gas compression and NGL extraction. Compression was installed in 1957 (PCTJ-2) and 1958 (PCTJ-3), and NGL extraction in 1971 (Fig. 1 [45234 bytes]).

The compression section of PCTJ-2 consists of 12 (14 in PCTJ-3) centrifugal compressors arranged in two trains of 6 compressors each (7 in PCTJ-3). These compressors are connected in series, and each train may be operated independently.

Normally, this section processes 410 MMscfd (420 in PCTJ-3) of gas, with a suction pressure of 45 psig (25 in PCTJ-3) and a discharge pressure of 1,600 psig for both plants.

The extraction section (Fig. 2 [41267 bytes]) of PCTJ-2 has a design capacity of 24,700 b/d, whereas PCTJ-3 is less, with about 21,600 b/d; extraction can be described as follows:

Inlet gas coming from the fourth-stage discharge of each train of PCTJ-2 (fifth in PCTJ-3) splits to exchange heat with cold residual gas and tower liquids streams.

The inlet rich gas then recombines and enters the chillers, where again the temperature is lowered to -35? F. by propane refrigeration. Cooling produces a condensation of the gas-heavier hydrocarbons.

After leaving the chillers, the cold stream is divided in a separator in three streams: gas, liquid, and rich glycol. Lean glycol has been previously injected through nozzles in the heat exchangers and chillers to prevent hydrates formation.

Following the heat exchange with the inlet gas, the cold residual gas is reintroduced into the gas-compression section, and the liquid stream is sent to the de-ethanizer tower.

The de-ethanizer controls the ethane content of the bottom product, which is a stabilized product consisting of hydrocarbons of propane or heavier. The ethane and methane leave the tower as overhead products.

The stabilized product is sent ashore by pipeline to the Ul? LPG-2 plant for separating into propane, butanes, and natural gasoline.

In addition to rich gas leaving each train, 50 MMscfd of additional gas is processed as a result a recent project in which gas is injected directly from the high pressure gas-transfer system. This yields a total NGL production of about 20,000 b/d in PCTJ-2 and 14,000 b/d in PCTJ-3.

In the original design of the NGL extraction section of PCTJ-2, the maximum recovery factors considered for propane, butanes, and natural gasoline were 64%, 89%, and 98%, respectively (63%, 88%, and 97% for PCTJ-3).

Currently, these factors are 61%, 87%, and 97% (54%, 82%, and 96% for PCTJ-3), which are below the design criteria, mainly because of the much leaner gas available for processing.

Because the gas richness cannot be changed, at present, both plants have available extraction capacity. To take advantage of this capacity and to consider new opportunities of improvement, the optimization study was to determine how to increase recovery factors, mainly propane, through a deeper extraction process.

The study concluded the best optimization was to recirculate streams of condensate as absorbent in a new absorption section added to the NGL-extraction process.

Alternatives

Previous analysis of the NGL extraction and fractionation processes of Lagoven determined that there are two practical and attractive alternatives for the recirculation of the condensate streams in PCTJ-2 and 3:

• Recirculation of natural gasoline from the Ul? LPG plant

• Recirculation of a conditioned condensate from the de-ethanizer tower of each plant.

Since the efficiency of any absorption process is affected by such varied factors as the absorbent and inlet-gas ratio as well as temperature and quality of lean absorbent, the process scheme of each alternative was defined as follows:

• Natural-gasoline recirculation (Fig. 3 [42050 bytes]). In this option, natural gasoline from the Ul? LPG plant (lean gasoline), precooled by absorber bottom product, is contacted with the residual gas leaving the chillers separator, using an absorber tower installed downstream the chillers separator of each train.

Upon contact with the gas, the stream absorbs any remaining heavy hydrocarbons present in the residual gas, mainly propane.

After heat exchange, the absorber top gas flows to the gas compression section of the plant.

The bottoms product, the rich condensate obtained, is mixed with the condensate from the separator, to be fed to the de-ethanizer tower for stabilization. The stabilized product, together with the absorbent gasoline, is sent to the Ul? LPG-2 plant for fractionation.

• De-ethanizer-condensate recirculation (Fig. 4 [56314 bytes]). This option is similar to natural-gasoline recirculation, but the condensate being used as absorbent is a stream obtained by separation-expansion process, using part of the de-ethanizer stabilized product.

The separation-expansion process is carried out at two pressure levels. The final product liquid of this process, mainly heavy hydrocarbons, is the stream used as absorbent at the main process.

The vapor streams are recompressed and combined with the remaining stabilized product. This mixture leaves the plant as NGL production.

This scheme of separation-expansion was considered because it requires low external energy (only in recompressors and pumps) compared to a new option consisting of a conventional fractionation scheme, which requires an additional heating system and tower top condensers which require higher investments.

For comparing these alternatives, both process cases for each plant were simulated with Hysim which yielded the results shown in Table 1 [75264 bytes].

The recirculation rates for both alternatives were established according to the available capacity in the de-ethanizer tower and associated equipment at NGL extraction facilities.

Fractionation capacity

Because NGL production from PCTJ-2 and PCTJ-3 is fractionated in the Ul? LPG-2 plant, it was necessary to analyze the required fractionation capacity taking into account the new NGL production involved.

The results of this analysis are shown in Table 2 [13140 bytes].

It can be observed there that with the option of using de-ethanizer recirculating condensate, the fractionation capacity is not exceeded, which it does with the option of recirculating gasoline.

That is to say that with the latter scheme, the Ul? LPG-2 plant capacity needs to be increased. It would require a revamping or major modifications, such as, among others, changing out trays in the fractionator towers, modifying condensers, and changing piping and accessories to reboilers.

To accomplish these modifications, a long LPG-2 plant shutdown would be necessary, which is not operationally feasible because of the impact on products distribution to Lagoven's Amuay refinery and internal market. This modification was therefore discarded.

Another option of fractionation, however, was studied. This option considers processing only part of the NGL production from PCTJ-2 and PCTJ-3 in the existing facilities of LPG-2 plant so as not to exceed its capacity.

As a result, a modified scheme was developed for recirculating gasoline. The scheme considered such factors as ease of facilities to be installed, use of existing equipment, and availability of both capacity for heating and space.

This scheme contemplated fractionating part of the NGL product from both plants in a condensate stabilization tower (T-8) which was available and out of service. It is located at the LPG-1 plant, adjacent the LPG-2 plant.

The modified scheme permits the increase of the gasoline recirculation rate from 2,400 to 7,000 b/d in PCTJ-2 and from 3,900 to 7,600 b/d in PCTJ-3, yielding a much higher NGL recovery in both plants.

Considering these modifications, an economic study was made for both alternatives; results are shown in Table 3 [14080 bytes].

Selection

Accounting for the installations involved, the products obtained, and the associated costs yielded the following:

• Recirculating NGL heavier hydrocarbons (natural gasoline or de-ethanizer condensate), and installation of a refrigerated absorption process in the existing NGL extraction process at PCTJ-2 and PCTJ-3, increase the production of liquids, mainly propane and butanes.

• Recirculating natural gasoline from Ul? LPG plant is, particularly for Lagoven, more attractive than the de-ethanizer condensate recirculation because of a greater NGL product revenue, simpler operation, and lower investments.

• Finally, the scheme established to optimize the present NGL extraction process of plants PCTJ-2 and PCTJ-3 was defined as recirculating natural gasoline with partial fractionation in Tower T-8.

At present, Lagoven. has undertaken to implement this optimization scheme. Construction was completed for PCTJ-3 in April 1997; for PCTJ2, construction will conclude in November 1997.

Following is a summary of these projects.

Adding absroption, fractionation

The project consists of adding to the NGL-extraction section of both PCTJ-2 and PCTJ-3 a refrigerated absorption process which will use natural gasoline from the Ul? LPG plant as an absorbent and installing a new fractionation process in the Ul? plant (Fig. 5 [56418 bytes]).

The new absorption unit for each plant, will be located on a new platform adjacent the existing offshore NGL-extraction facilities, and the new fractionation unit will be located in an available area of the Ul? plant.

The offshore process facilities of PCTJ-2 as well as PCTJ-3 are being built as independent units for each train. Each one will use a static mixer, an absorber tower, two heat exchangers, and two pumps.

The new process facilities in the Ul? plant will contain a flash tank, a debutanizer (existing tower T-8) with its associated equipment, and a debutanizer feed preheater.

Each absorber tower of PCTJ-2 is designed to process 200 MMscfd (210 in PCTJ-3) of residual gas from the chiller separator with a propane-plus content of 0.6 gal/Mcf with a recirculation rate of lean natural gasoline of 3,500 b/d (3,800 for PCTJ-3) at -22? F. (-24? F. for PCTJ-3).

After leaving the absorber tower top with a propane-plus content of 0.3 gal/Mcf propane plus, the lean gas will exchange heat with the inlet rich gas and then be returned to the compression train.

The loss of natural gasoline in this stream, normal to this type of process, will be recovered in the future through a sponge section which will operate with another lean absorbent.

The lean gasoline for each plant, which will be sent from the Ul? plant using new pumps and a new 15.7 mile, 8-in. pipeline, will exchange heat with absorber bottom product.

This product will be heated and mixed with the inlet rich gas using a static mixer, then the stream will be separated into two phases. The gas will enter NGL extraction, and the rich condensate will be sent to the Ul? plant through the new 8-in. line.

At the Ul? plant, the rich condensate will be introduced into a flash tank and separated in two phases: the liquid will be preheated with the debutanizer bottom product before being fed to this tower.

The mixture of the gas from the flash tank and the vapor from the debutanizer top will be fractionated in other Ul? plant towers.

The products rates, the recovery factors for each plant, and the fractionation capacity required in the Ul? plant are shown in Table 4 [67775 bytes].

Total cost of the project is $10 million (US$ 1996) for PCTJ-2 and $8 million for PCTJ-3.

Considering these costs as well as maintenance and operation costs, an economic analysis of the project associated to each plant yielded the results shown in Table 5 [8914 bytes].

Bibliography

"Engineering Data Book, Vols. 1 & 2," Gas Processors Suppliers Association, 1994.

Campbell, John M., "Gas Conditioning and Processing, Vols. 1 & 2" Campbell Petroleum Series, 1994.