The present invention relates to a system for the production of power/heat on an oil installation, and a method and apparatus for handling the exhaust gases from gas turbines at oil recovery installations.

Normally, the exhaust gases from such gas turbines are admitted directly to the atmosphere, possibly after flare burning for reducing remaining hydrocarbons or other inflammable substances that are decomposed into substantially steam and CO2. In view of the increasing global concern about pollution of the atmos- phere ("the greenhouse effect "), sucheffluents are environmentally very undesir- able, since it is a matter of large amounts of effluent in the order of four billions m3 or more per year from each single installation. There is therefore a need within the art of oil recovery to find a relatively economic solution of this pollution problem.

Under certain conditions during oil recovery the natural gas that usually is produced together with the oil (associated gas) is partly or entirely reinjected into the reservoir. The purpose of such injections would be to retain the pressure of the reservoir in order to facilitate the oil recovery. In recent years, however, also associated gas has increasingly been commercially utilised, resulting in a corre- spondingly lower amount of gas available for enhancing the reservoir pressure.

The principal object of the invention is, therefore, to provide a solution of the above pollution problem, permitting a substantial reduction of the amount of envi- ronmentally harmful gases, including CO2, discharged to the atmosphere, while also permitting control of the formation pressure with less consumption of natural gas.

This object is achieved according to the invention, by subjecting at least part of the exhaust gases to an afterburning process in which the Oz content of the gas is reduced, and in which the heat energy developed during the afterburn- ing process is utilised through heat recovery, followed by compressing the gas and injecting it into the reservoir, such as more specifically stated in the appending patent claims.

The purpose of the afterburning is primarily to reduce the 02 content of the exhaust gases to a desired, relatively low level. This is because the exhaust gas, which normally is relatively rich in oxygen exposes the production equipment to a corrosive environment when injected into the reservoir. Also, the energy demand and consequently the cost for carrying out the injection process are relatively high, since the exhaust gas to be injected has to be compressed up to required injection pressure, of the order of 150 - 400 bar.

Thus, the invention builds on the acknowledgement that by permitting the hot exhaust gas from the gas turbine to pass through an afterburner, the 02 con- tent of the gas may be reduced to a value that is adapted to the reservoir condi- tions at various oil fields of interest, while the energy demand for operating the injection equipment (compressors etc.) partly or entirely is covered by utilising the exhaust gas heat energy, including the combustion heat of the afterburning proc- ess.

The invention will now be explained in more detail with reference to the ap- pending drawings, of which fig. 1 shows a system or flow diagram of a possible embodiment of an apparatus according to the invention, and fig. 2 shows a flow diagram of a modified embodiment of the apparatus according to fig. 1.

Referring to fig. 1, the hot exhaust gas G from an gas turbine (not shown), normally an axial gas turbine (open system) is passed to a combined after- burner/heat recovery assembly E (briefly referred to as"the combination assem- bly"in the following description), supplie with supplemental fuel (oil, gas) B for the afterburning process, if necessary. According to requirements, means for in- creasing the pressure, such as a blower, may be located up-streams of or included in the combination assembly E in order to ensure that the gas turbine back pres- sure does not reach such a high level that the turbine efficiency is substantially reduced. Preferably, the combination assembly E is comprised of a steam boiler with water supply V and steam outlet D as indicated in fig. 1, in which the after- burning takes place in the boiler firing means. Gas exiting the latter is passed through an aftercooler K1 foilowed by preferable a plurality, such as five, compres- sor stages, Cl-C5, via intercoolers K2-K5 and optionally endcooler K6 with associ- ated condensed water separators U, whereupon the exhaust gas is injected into

the reservoir in a traditional manner via a separate injection well or directly into the producing well, at the appropriate injection pressure.

According to the invention the oxygen content of the exhaust gas, which normally would be in the range of 12 - 14 percent by volume, is reduced during the afterburning process to a desired teve !, normatty between 0, 25 and 7 percent by volume) dependent on the reservoir conditions.

Although energy recovered from the combination assembly E may of course be utilised in whatever desirable application, preferably it will be used in the com- pressor work to raise the exhaust gas pressure to the required injection pressure level.

The prime movers for driving the respective compressors Cre can of course be selected among several possible alternatives such as steam turbine, gas tur- bine or electric motor, depending on what is considered to provide optimum op- eration at the prevailing conditions.

In some cases it may be desirable to reinject, partly or entirely, the gaseous fraction of the fluids produced from the well, together with the exhaust gas G.

Such gaseous fraction, apart from associated gas, will normally, to a larger or smaller extent, contain previously injected exhaust gases. The flow diagram of fig.

2 illustrates a modification of the apparatus according to fig. 1, adapted to such gas reinjection. Here the gaseous fraction g is preferably passed through a cooler K7 with a condensate separator U and mixed with the turbine exhaust gas G at an appropriate location where the pressure of the tatter is equal to or somewhat lower than the pressure of the produced gaseous fraction g, e. g. between compressors C, and C2.

Three data-simulated examples of practical applications of the invention in connection with offshore oil recovery, using the apparatus shown in the figures, are given below. The examples are based on an assumed total injection exhaust gas amount of 1, 7 x 109 Sm3/year (4,9 x 1 o6 Sm3/day for 350 days of operation per year) from a gas turbine, e. g. of the type LN2500 with combicycle. The exhaust gas from the turbine will have a temperature of about 550°C and a pressure of about 1 bar. The 02 content of the exhaust gas is assumed to be about 12 %, and the combination assembly E to be used is a steam boiler, suitably adapted for use in connection with the invention.

Example 1 (Fig. 1) In steam boiler E the temperature increases to 1650°C and then fa ! ! s to about 150°C. The afterburning process is controlled in a manner to reduce the oxygen content of the exhaust gas to a desired level, normally about 1 % but with a possible variation range up to 7 % maximum. The control is carried out, if nec- essary, by varying added heat, i. e. additional fuel B ; the more additional fuel, the lower should be the content of the exhaust gas G from the boiler E. In aftercooler Ki the temperature further falls to about 30°C. Then the exhaust gas pressure gradually increases through compressors C1 - C5 from about atmospheric pres- sure (1 bar) to about 5 ; 16 ; 53 ; 97 ; and 175 bar (the injection pressure), respec- tively, with intercooling Ks - K5 down to about 25°C between each compressor, whereupon the gas is injected into the reservoir via an injection well, preferably after having passed through a scrubber. At this stage the gas is preferably main- tained above the dew point to avoid corrosion problems in the injection well. Op- tionally, additional cooling could be performed in an end cooler K6, if desirable owing to limitations on the design temperature of the injection riser/well.

Example 2 (Fig. 2) Here, all the gas produced from the reservoir (associated gas + previously injected exhaust gas) is reinjected together with the exhaust gas from the turbine.

The injection demand at the time during the lifetime of the field the example refers to is 8 x 1 o6 Sm3/day, of which 3 x106 comes from the reservoir and mainly con- sists of previously injected exhaust gas. This implies necessary addition of about 5 x 103 SM3/day net exhaust gas, corresponding to the amount of exhaust gas from the gas turbine. The gas g from the reservoir is added to the turbine exhaust gas G between the two first compressors Ci, Cs as shown in fig. 2, while otherwise the apparatus is the same as in example 1 (fig. 1).

Example 3 (Fig. 2) Also in this example all of the gas g that is produced from the reservoir is reinjected. Here, however, a part, G', of the exhaust gas G from the gas turbine is separated from the system, e. g. to give room to the reproduced gaseous fraction g, in view of the capacity of compressors C, - C5. The exhaust gas part G'not to

be injected can be separated upstreams of boiler E and discharged directly into the atmosphere, optionally via a separate heat recovering unit, such as a heat ex- changer, but preferably it is separated after boiler E and before the first compres- sor C,, as indicated by broken line in fig. 2, such that all of the exhaust gas G is subject to the afterburning process implying reduction of oxygen.

The injection demand at the time during the lifetime of the field for which the example is intended, is about 106 SM3/day, of which 8 millions comes from the reservoir and mainly consist of previously injected exhaust gas. This means that 2 x106 SM3/day net exhaust gas must be added.

The pressure levels in the recovery well can of course vary. Thus, upon a gas breakthrough the wellhead pressure may rise as high up as to 50 bar. In the above simulation examples 2 and 3 a wellhead pressure of 5 bar are assumed for all reproduced gas, which is a relatively low value. For higher wellhead pressures it may be appropriate to insert reinjected gas g in the exhaust gas G at a higher compressor stage, between compressors C2 and C5.

All three examples assume an added (fired) thermal power of 75 MW to the gas turbine, and a mechanical power of 26 MW in the turbine. The total thermal power of the exhaust gas G in boiler E, including added (fired) power to the latter, is assumed to be about 210 MW, which provides a computed power of about 77 MW based on the steam produced in boiler E.

Net cooling demand associated with the production of exhaust gas with 1 % oxygen is 132 MW if all of the exhaust gas from the gas turbine is reduced in oxy- gen to 1 %. In addition comes compressor cooling, which in example 3 is 80 MW.

The energy demands for recompression is given in the following table : Compressor Dimensioned Energy de- Energy de- Energy de- power for each mand mand mand compressor Example 1 Example 2 Example 3* MW M M M C11615,615,67,4 j41721 gg C41050810 C51053911 Sum 79** 47,3 69 71

The table shows the energy demand (power) for which the compressors are di- mensioned, for an oil field, and the energy demand for the three examples.

* Example 3 refers to the dimensions for total energy demand.

**All the compressors will not run at full capacity at the same time, such that the sum in the bottom column is the maximum total power used to compress the exhaust gas and produced gas.

As appearing from the table, the total energy demand of the first compres- sor C, is 15, 6 MW. This value is based on an efficiency of 95 %, provided that the exhaust gas from the gas turbine is passed through boiler E and compressed (examples 1 and 2). In example 3 the demand for exhaust gas to injection is re- duced compared to the design criterion. Consequently this example results in 7, 4 MW for that compressor. All examples assume a pressure drop of 0, 2 bar be- tween each compressor stage and after the last compressor stage, mainly be- cause of cooling.

The last column in the table shows a power consumption at a time during the lifetime of the field when the energy demand for compression is at its highest.

At that time the energy demand of 71 MW is still lower than 77 MW, which the boiler steam production is capable of providing. In this case the exhaust gas de- mand for injection is about 50 % of that which the gas turbine can deliver, such that the burning of the amount of exhaust gas which is sufficient for injection is capable of providing only 36 MW which is not sufficient to cover the compressor demand. Then more exhaust gas could be burned than that of the injection de- mand while discharging the non-injected gas into the atmosphere, or cover the

remaining power demand in different ways. At other times during the lifetime of the field the burning of sufficient amounts of exhaust gas for injection will provide enough power to compress exhaust gas and produced gas.

It is then evident that produced steam can be fully utilised. Since the as- sumed recompression demand is fairly low, as is also the assumed separator pressure, this implies a considerable degree of reduction potential.

The steam balance is easily adjusted by adjusting the amount of fuel B added to boiler E.

A good energy demand and production balance is achieved. However, there are also alternatives in which the entire recovery plant (plafform) is supple- mented with power based on steam.

This would require installation of one or two steam boilers, each of 50 MW produced mechanical energy as steam, and the exhaust gas is injected therefrom.

The process must be adjusted to the actual process configuration and up- dated wellhead pressure.

The invention is primarily intended for use in connection with offshore in- stallations, but is not limited to such application.