DIRECT STEAM GENERATION CO2 OUTPUT CONTROL

Methods and systems generate steam and carbon dioxide mixtures suitable for injection to assist in recovering hydrocarbons from oil sands based on concentration of the carbon dioxide in the mixtures as influenced by temperature of water introduced into a direct steam generator. Increasing temperature of the water to above 200° C. before introduction into the direct steam generator may utilize heat from an electrical power generation unit. Enthalpy of this preheated water impacts amount of fuel needed to burn in the direct steam generator and hence the concentration of the carbon dioxide, which may be below 11% by mass percent of the steam.

DETAILED DESCRIPTION

For some embodiments, methods and systems generate steam and carbon dioxide mixtures suitable for injection to assist in recovering hydrocarbons from oil sands based on concentration of the carbon dioxide in the mixtures as influenced by temperature of water introduced into a direct steam generator. Increasing temperature of the water to above 200° C. before introduction into the direct steam generator may utilize heat from an electrical power generation unit. Enthalpy of this preheated water impacts amount of fuel needed to burn in the direct steam generator and hence the concentration of the carbon dioxide, which may be below 11 percent by mass percent of the steam (i.e., mass of the carbon dioxide/mass of the carbon dioxide and steam expressed as a percentage).

FIG. 1illustrates a direct steam generator (DSG)100that produces a mixture101of steam and carbon dioxide. The steam generator100may integrate with a steam assisted production process used in connection with an injection well102and a production well104. An output of the steam generator100couples to the injection well102to convey the mixture101into a formation.

In an exemplary steam assisted production operation, the injection well102and production well104each include horizontal lengths that pass through the formation and may be disposed parallel to one another with the horizontal length of the injection well102above the production well104. This configuration of the injection well102and the production well104exemplifies a conventional steam assisted gravity drainage (SAGD) well pair. The steam in the mixture101condenses and transfers heat to hydrocarbons in the formation that then drain with condensate of the steam by gravity to the production well104for recovery.

An emulsion106of the hydrocarbons and the condensate recovered from the production well104upon separation provides products and part or all of feed water108to the steam generator100. The water108pumped to the steam generator100may need additional treatment if being recycled depending on configuration of the steam generator100. In some embodiments, separation of the emulsion106occurs without significant heat loss from the water108relative to when recovered from the production well104.

For some embodiments, one or more heat exchangers, such as a first heat exchanger110, transfers heat to the water108from any components of the emulsion106recovered through the production well104. The water108exits the first heat exchanger110through a heater input conduit112coupled to a device, such as a second heat exchanger114, for heating the water108to a temperature above 200° C. prior to being introduced into the steam generator100.

Depending on how much heat is lost and/or recovered, initial temperature of the water108upon introduction into the second heat exchanger114thus may range from ambient up to a temperature, such as 200° C., corresponding to temperature of the emulsion coming from the production well104. In some embodiments, the second heat exchanger114transfers heat from an electrical power generation unit116to the water108increasing the temperature of the water108to above 200° C. For example, the electrical power generation unit116may utilize a gas turbine burning natural gas with resulting exhaust used by the second heat exchanger114instead of, or in addition to, a second cycle to increase electricity production.

The second heat exchanger114may not rely only on waste heat from the electrical power generation unit116since the heat in common practice would otherwise raise steam production for the second cycle. Increasing size and firing rate of the gas turbine compensates for the heat removed by the second heat exchanger114. However, resulting fuel savings in the steam generator100outweighs additional fuel burned in the electrical power generation unit116, as shown in Table 1 herein.

Location of the electrical power generation unit116on-site enables employing the second heat exchanger114with the steam generator100. With respect to being on-site, the electrical power generation unit116supplies power needs of a facility supporting the steam assisted production process. Demand for the power comes from associated equipment including an air separation unit, evaporator and/or carbon dioxide conditioning/compression system.

A heater output conduit118conveys the water108from the second heat exchanger114for introduction into the steam generator100under sufficient pressure to be in liquid phase. In operation, fuel120, such as hydrocarbons including natural gas, and an oxidant121, such as oxygen separated from air, supplied to the steam generator100combust inside the steam generator100as the water108is introduced. The water108makes direct quenching contact with resulting combustion products and is thereby vaporized into steam. This steam in combination with the combustion products produces the mixture101output from the steam generator100.

In some embodiments, a portion of the water108(e.g., from the heater input conduit112as shown) enters into the steam generator100at a temperature below 200° C. in an area of the steam generator100upstream from where the water108above 200° C. is introduced. The water108that is below 200° C. when entering the steam generator100may ensure sufficient cooling in a head of the steam generator100where temperatures may be highest in the steam generator100. The head also includes injectors of the fuel120and the oxidant121and is most susceptible to thermal damage.

For some embodiments, the second heat exchanger114increases temperature of the water108such that the water108is above 250° C., between 250° C. and 300° C., or between 250° C. and 280° C. and at a pressure above 6000 kilopascals when output from the second heat exchanger114and/or introduced into the steam generator100. Further, the water108may enter the steam generator100at more than 30° C. below a temperature of the mixture101output. For example, the mixture101may exit from the steam generator100above 280° C. and at least 6000 kilopascals for introduction into the formation through the injection well102.

FIG. 2shows a graph with a line plotting the temperature of the water108fed to the steam generator100versus the concentration of the carbon dioxide in the mixture101produced by the steam generator100. Depending on the temperature of the water108, the mixture may thus contain a carbon dioxide level in mass percent of the steam below 11 percent or below 10 percent. In some embodiments, controlling temperature of the water108fed to the steam generator100adjusts the carbon dioxide level to a selected value to achieve a threshold steam to oil ratio.

In addition to providing control of the carbon dioxide level in the mixture101, approaches described herein may reduce operating and capital expenses compared to similar approaches that lack the second heat exchanger114used to increase the temperature of the water108above 200° C. The Table 1 shows this comparison made with process models for a 90,000 barrel per day facility. As shown in the Table 1, firing rate of the steam generator100decreases by 16 percent when the second heat exchanger114is employed as described herein. This reduction enables using fewer steam generators along with smaller air separation units and carbon dioxide processing systems per given amount of steam output. Total fuel usage also drops with use of the second heat exchanger114.