WO2014096030A1

WO2014096030A1 - Method for the recovery of hydrocarbons from an oil reservoir using steam and noncondensable gas

Info

Publication number: WO2014096030A1
Application number: PCT/EP2013/077133
Authority: WO
Inventors: Patrick Lee Mcguire; Kristian Mogensen
Original assignee: Mærsk Olie Og Gas A/S
Priority date: 2012-12-19
Filing date: 2013-12-18
Publication date: 2014-06-26
Also published as: DK201470480A; EP2935769A1

Abstract

The invention relates to a method for the recovery of hydrocarbons from an oil reservoir. The method comprises the steps of providing steam, providing nitrogen gas, and optionally other injectants such as carbon dioxide, injecting nitrogen gas and steam and optionally other injectants as an injection mixture into a natural hydrocarbon reservoir, and collecting hydrocarbons displaced by the injection mixture from the natural hydrocarbon reservoir. The method showed great results in lowering the viscosity of viscous oil in relatively deep oil reservoirs.

Description

METHOD FOR THE RECOVERY OF HYDROCARBONS FROM AN OIL RESERVOIR USING STEAM AND NONCONDENSABLE GAS

FIELD OF THE INVENTION

The invention relates to a method for the recovery of hydrocarbons from an oil reservoir.

BACKGROUND

In the recovery of hydrocarbons from oil fields, various techniques are employed to optimize oil and gas production.

Traditional displacement methods use water to displace oil in a field, effectively pushing the oil to a collector point. Chemicals such as surfactants may be added to alter the flow and mixing properties of the oil/water mixture that is obtained. An alternative method is to use gas to displace oil. A well-known method is to re-inject the natural gas (mostly consisting of methane) produced from the oil field. However, in many cases the availability of the produced gas is limited. Often the produced gas can be sold at competitive market prices, making the method relatively expensive. Nitrogen gas or carbon dioxide gas can also be injected. These gasses have no value as fuel, but are relatively expensive to obtain. It may also be troublesome to maintain the reservoir pressure once a major part of the oil is recovered.

The existing methods give relatively poor results in retrieving so-called viscous oil from reservoirs. Viscous oils or heavy oils are hydrocarbons that are often hard to recover, due to the high viscosity of the oil in the reservoir. Heavy oil typically has a viscosity between 10 and 10,000 cp at reservoir conditions and does not flow at commercial rates unless diluted with a solvent or heated. This difficult-to-produce oil is often left in the reservoir unless the viscosity can be substantially reduced. Steam is a possible injectant that may be used to recover oil that cannot be produced from hydrocarbon reservoirs using more conventional techniques. Only a few reservoirs, all of which are in Venezuela, are steamed at a depth greater than 900 m. No commercial project is deeper than 1 ,200 m, anywhere in the world. The extreme temperatures at these depths are very difficult for wellbores and equipment to survive, and the severe heat losses at such high operating temperatures make the limit of 1 ,200 meters a hard barrier that conventional steam EOR technology may never cross. Very few successful projects operate at pressures greater than 70 bar. There are no steam projects which operate in excess of 90 bar.

High temperatures lead to high heat losses to the overburden, underburden, and the rock itself, while high latent heat (the difference in enthalpy between vapor and liquid) results in high useful heat transport deep into the reservoir where it heats the oil. Low steam temperature (-200 °C) and high latent heat (1600+ kJ/kg) is ideal, which is why steam works well between 200 and 600 meters of depth. At high pressures, the heat losses are excessive, and there is very little latent heat available to transport energy deep into the reservoir.

SUMMARY

The invention provides a method for producing hydrocarbons, comprising the steps of a) providing steam,

b) providing a non-condensable gas such as nitrogenor a mixture of nitrogen and one or more other non-condensable gasses,

c) injecting the non-condensable gas or gas mixture and steam as an injection mixture into a natural hydrocarbon reservoir either continuously or intermittently, and

d) collecting hydrocarbons displaced by the injection mixture from the natural hydrocarbons reservoir.

This steam-assisted method showed an improved recovery of hydrocarbons, in particular in reservoirs containing relatively viscous oil (10 to 10,000 cp). The combination of nitrogen and/or carbon dioxide with steam can lead to excellent results in the recovery of oil from difficult-to-produce viscous oil reservoirs. The method as described achieves a more efficient heat transfer to lower the viscosity of the hydrocarbons than known methods. It is postulated the latent heat in the steam mobilizes the viscous oils by thermally lowering viscosity, whereas the gaseous injectant provides additional reservoir energy and assists in transporting the mobilized fraction towards a collection location of the oil reservoir. Additional carrier injectants may be used. The method can also be used continuously or intermittently with other injection methods. The steam provides both a transport medium in the form of water and a thermal heat that lowers the viscosity of hydrocarbons, allowing for more efficient displacement of the hydrocarbons, in particular relatively viscous fractions.

The injection mixture may be pre-mixed before injection, or may be achieved by simultaneous injection. According to an embodiment, steam and nitrogen and/or other injectants such as carbon dioxide are injected simultaneously for a period long enough to be considered continouos. Alternatively, during a first period hot steam and nitrogen are injected simultaneously, whereas during a second period, a carrier injectant such as nitrogen and/or carbon dioxide is injected without injecting steam i.e. the two methods of respectively first and second period are used intermittently for a longer period.

Preferably, the temperature of the injection mixture is in the range of 100°C and 300 °C, more preferably in the range of 180-250 °C, when injected into the hydrocarbon reservoir. At such temperatures, the heat loss is relatively moderate, and the risk of damaging the well is limited. Higher temperatures lead to higher heat losses and increased operational difficulties. Often the pressure of the injection mixture is in the range of 50-200 bar when injected into the hydrocarbon reservoir. At such pressures, the injection mixture may be utilized at great depths to achieve heat transfer to hydrocarbons in order to lower the viscosity of relatively viscous oil fractions. Most preferably, the method is performed under combined parameters where the temperature of the injection mixture is in the range of 180°C and 250 °C and the pressure is in the range of 50-200 bar. Contrary to existing methods, an acceptable balance is achieved between the value of the collected hydrocarbons and the heat losses to the overburden, underburden, and the rock itself.

It is advantageous if the molar ratio of steam and nitrogen gas in the injection mixture is in the range of 1 :0.5 to 1 :5, e.g. in the range of 1 :1 to 1 :2 when injected into the hydrocarbon reservoir, e.g. approximately 1 :1 . These ratios allow for injection with a relatively high latent steam heat with acceptable heat losses, allowing one to operate at relatively great depth at a better energy efficiency than existent steam methods.

Normally, the molar fraction of steam in the injection mixture is below 80%, or even below 70%, or in the range of 30-60%.

In one embodiment, the injection mixture comprises carbon dioxide. If the injection mixture comprises a mixture of steam, nitrogen gas and carbon dioxide, the carbon dioxide acts to further reduce the viscosity of the oil. According to some embodiments, the injection mixture is injected at a depth of at least 500 m. At such depths the method as described herein has a distinct advantage compared to existing steam methods, in particular in terms of energy efficiency. At increasing reservoir depth, the operational pressure is higher and the steam becomes thermally less efficient. Pressures at or less than 70 bar are desired because the enthalpy of the steam is nearly constant up to that pressure and the constant enthalpy makes it easier to recover viscous oil. Although the temperature of the steam continues to increase as pressure increases above 70 bar, the enthalpy of steam actually decreases. A pressure of 70 bar typically occurs at reservoir depths of about 800 m. For those reasons, known steam methods have a practical depth limit to formations shallower than 800 m.

At least part of the water for providing the steam can be obtained as a combustion product from hydrocarbons. As such, the energy and materials efficiency of the method is further improved, and also decreases the dependence on the external supply of water. This is particularly advantageous in locations where fresh water has a limited availability. At least part of the heat for providing the steam can be obtained as a combustion product from hydrocarbons, most preferably from a gas fraction of the collected hydrocarbons. The use of the heat generated by retrieved hydrocarbons, in particular gas, contributes to the at least partial self-sustainability of a system using the method as described herein, and becomes less dependent on external sources of energy for generating heat. Since it is difficult to utilize or sell hydrocarbon gas that is contaminated by nitrogen and/or carbon dioxide, it can be advantageous to utilize the produced gas as fuel for providing the steam. Possibly, both the water and/or heat for providing steam are at least partially obtained from the combustion of hydrocarbons produced by the method.

At least part of the nitrogen gas can be obtained in a gas separation process, where oxygen obtained in the same gas separation process can be used for the combustion of hydrocarbons. If the injection mixture comprises carbon dioxide, then at least part of the carbon dioxide can be derived from the combustion of hydrocarbons from the oil reservoirs. The use as an injectant of carbon dioxide produced by combustion of hydrocarbons retrieved from the oil reservoir will improve the self-sustainability and independence from external injectant sources. Optimal self-sustainability and energy-efficiency is achieved in the method as described herein, wherein

- at least part of the water for providing the steam is obtained as a combustion product from hydrocarbons.

- at least part of the heat for providing the steam is obtained as a combustion product from hydrocarbons, and

-wherein at least part of the nitrogen gas is obtained in a gas separation process, wherein oxygen obtained in the same gas separation process is used for the

combustion of hydrocarbons,

and

optionally, the injection mixture comprises carbon dioxide, wherein at least part of the carbon dioxide is derived from the combustion of hydrocarbons, wherein at least part of the combusted hydrocarbons are collected from the natural hydrocarbons reservoir.

When nitrogen and/or carbon dioxide are used in driving hydrocarbons from the oil reservoir, in particular volatile hydrocarbon fractions are contaminated with nitrogen and/or carbon dioxide gas. Advantageously, at least part of the hydrocarbon is used as fuel for providing the steam is the nitrogen and/or carbon dioxide contaminated hydrocarbon gas produced from the viscous oil reservoir. Such contaminated hydrocarbon gas is used more efficiently and economically than further processing into purified and decontaminated products, as the separation methane gas and other volatile hydrocarbon fractions from nitrogen or carbon dioxide is relatively energy inefficient.

The method as described herein may be performed by a system or a device for the recovery of hydrocarbons from an oil reservoir, comprising

- at least one source of water

- a steam generator connected to the source of water, for heating the water to produce hot steam,

- a source of carrier injectant, for instance carbon dioxide and/or nitrogen

- at least one injector coupled to the source of water through the heater, for injecting steam into an oil reservoir, and - at least one injector coupled to the source of injectant, for injecting injectant into the oil reservoir.

, wherein the device is provided with a controller unit for controlling the injection of injectant and/or steam.

Such a device would be used in combination with at least one device for collecting oil reservoir.

It is preferred if at least one injector is coupled to the source of water through the heater, and wherein the same injector is also coupled to the source of injectant. Thus the injection can be done through the same channel, allowing for an effective prevention of clogging through the injector and the pathways of injectants and hydrocarbons in the oil reservoir.

It is preferred if the heater is connected to a combustor for hydrocarbons to use heat generated by the combustor in the steam generator to heat water and produce hot steam. This coupling may be directly but is preferably done indirectly through a heat exchanger and/or a heat storage where the energy may be temporarily stored. This allows for a better control of the produced heat. Advantageously, the combustor for hydrocarbons comprises a collector unit for collecting water obtained in the combustion of hydrocarbons, wherein the collector unit is connected to the water reservoir.

Examples

The invention will now be further elucidated by the following non-limiting examples.

Figure 1 shows the pressure-enthalpy diagram for steam.

Figure 2 schematically shows the method and device according to the invention.

Figure 3 schematically shows a device for the mixing and injection of steam and other injectants.

Figure 4 schematically illustrates a device 30 being integrated in the system of figure 1 .

This invention, comprising both method and apparatus, represents a significant potential to extend the limit of steam technology by applying Dalton's law of partial pressures to the steam injection process. By adding 1 mole of nitrogen to one mole of steam, we have a resultant mixture of 2 moles of combined steam and non-condensable gas. That will reduce the operating temperature at 150 bar from a completely impractical operating temperature of 340°C down to a much more practical temperature of 275°C. If we mix 2 moles of nitrogen with 1 mole of steam, we get a reduction at 150 bar down to 250 °C, which is clearly within the industry's ability to operate.

Gibbs'-Dalton's law of partial pressure

The total pressure of a mixture of gases is made up by the sum of the partial pressures of the components in the mixture as known from Gibbs'-Dalton's Law of Partial Pressures. The total pressure exerted by a mixture of gases is the sum of the partial pressures of the individual gases

The total pressure in a mixture of gases can be expressed as:

p =∑pi (1 )

where

p = the pressure of the mixture

pi = partial pressure of gas i

For a mixture of steam, nitrogen and carbon dioxide, the equation would be

p = p(steam) + p(N₂) + p (CO₂) (2)

wherein p(steam) is the partial pressure for steam, p(N₂) is the partial pressure for nitrogen and p (CO₂) is the partial pressure for carbon dioxide.

While the Gibbs'-Dalton's Law of Partial Pressures forms the conceptual basis of this invention, an equation-of-state simulation package was used for all of the pressure- temperature calculations. This increases the accuracy of the calculations at high pressures where the steam begins to deviate from ideal gas behavior.

1 :0 steam has no inert gasses at all. It is pure, normal steam. 1 :0.5 reduced partial pressure steam has a composition of one mole of H₂O and one half of a mole of either N₂ or CO₂ (or a mixture of the 2 gasses). This reduces the temperature considerably and also increases the latent heat capacity of the steam.

1 :1 reduced partial pressure steam has a composition of one mole of H₂O and one mole of either N₂ or CO₂ (or a mixture of the 2 gasses). This further reduces the temperature and also increases the latent heat capacity of the steam. 1 :2 reduced partial pressure steam has a composition of one mole of H₂O and two moles of either N₂ or CO2 (or a mixture of the 2 gasses). This further reduces the temperature and also further increases the latent heat capacity of the steam.

1 :4 reduced partial pressure steam has a composition of one mole of H₂O and four moles of either N₂ or CO₂ (or a mixture of the 2 gasses). This even further reduces the temperature and also even further increases the latent heat capacity of the steam. Figure 1 shows the pressure-enthalpy diagram for water vapor. The dome-shaped area indicates the region where steam is present as a mix of liquid and vapor. The area to the left side of the dome shape is the liquid area, the area to the right side is vapor. The top of the dome is the critical point, above which the fluid becomes supercritical. Figure 2 shows the saturation temperature as a function of pressure for mixtures of steam and nitrogen, ranging from pure steam up to 1 :4 reduced partial pressure steam, with ratios of steam:N₂ of 1 :4, 1 :2, 1 :1 and 1 :0.5., The figure also shows the saturation temperature of steam/carbon dioxide mixtures over the same range, with ratios of steam:CO2 of 1 :4, 1 :2, 1 :1 and 1 :0.5. The impact of adding the non-condensable gas is evident from the figure. For example, the resulting saturation temperature of pure steam at 100 bar is an impractical 310 °C. Utilizing 1 :1 reduced partial pressure steam will reduce the temperature down to a much more practical temperature of 250 °C. If the 1 :2 reduced partial pressure steam is used, the saturation temperature at 100 bar is reduced down to 230 °C, which is well within the industry's ability to operate.

In general, operating at relatively high temperature is associated with high heat losses to the overburden, underburden, and the rock itself, while high latent heat implies high useful heat transport deep into the reservoir where it heats the oil. Heating the oil lowers the viscosity which will allow a greater fraction to flow out of the reservoir. Low steam temperature (-200 °C) and high latent heat (>1 ,600 KJ/kg) is ideal, which is why steam works so well between 200 and 600 m of depth.

There is a limit to how much gas one would want to inject along with the steam, but over this 1 :0.5 to 1 :4 range, this method and apparatus has a major effect in allowing deep heavy oil reservoirs that could not be economical steamed with conventional technology to be steamed, either by cyclic steam stimulation (CSS) or by steam drive (SD) or by steam assisted gravity drainage (SAGD). This technology increases the practical steam EOR depth limit from less than 1 ,000 m to well over 2,000 m.

Figure 3 schematically shows a system 1 , wherein an air separator unit 2 separates air 3 into nitrogen gas 4 and oxygen 5. The oxygen is used in a combustion unit 6 to combust hydrocarbons 7, yielding energy 8, water 9 and carbon dioxide 10 as main products. The water 9 from the combustion unit is fed to a steam generator 1 1 . The steam generator may use water from an external water source in addition to the water obtained from the combustion unit. The steam generator may use heat 8 from the combustion unit to generate steam. The steam is supplied to an injector, that injects steam, optionally mixed with additional injectants, through an injection channel 13 into the oil reservoir 14. In the injector unit, the steam is brought under the desired temperature and pressure, and optionally mixed with additional injectants. As additional injectants, nitrogen 4 from the air separation unit 2, or carbon dioxide 10 from the hydrocarbon combustion unit 6 may be used, as well as suitable injectants from external sources. These may be injected through a separately controllable injector unit 16. In this example the injection is also through a separate injection channel 17, but it would also be possible to lead the additional injectants through the steam channel 13 via the steam injector unit. The steam and additional injectants act to reduce the viscosity of the oil in the injection area of the oil reservoir 14. The steam may be used combined with nitrogen 4 and/or carbon dioxide 10.

The steam and additional injectants such as nitrogen and/or carbon dioxide displace hydrocarbons from the reservoir 14 and are collected through one or more collector channels 15, into a collector unit 16. The collector unit may feed part of the hydrocarbons 7 back to the combustor unit 6, whereas another part 17 of the hydrocarbons is let away for transport and further steps in the production process. Figure 4 schematically shows a device 30 that can be integrated in the system in figure

1 . The device 30 comprises a steam generator 31 and a source of carbon dioxide and/or nitrogen gas 32. The steam 31 and carbon dioxide/nitrogen 32 are supplied to a mixing unit 33, in a predetermined ratio that can be adjusted by a control unit. The mixing unit may also be set to supply only steam or only carbon dioxide/nitrogen gas,. The mixed injectants 34 are led through an monitoring unit 35, that measures the injection pressure. Subsequently, the mixed injectants are lead to the actual injector 36 for injection into the oil reservoir.

Claims

1 ) Method for producing hydrocarbons, comprising the steps of

a) providing steam

b) providing nitrogen gas, and optionally other injectants,

c) injecting nitrogen gas and steam and optionally other injectants as an injection mixture into a natural hydrocarbon reservoir, and

d) collecting hydrocarbons displaced by the injection mixture from the natural hydrocarbon reservoir. 2) Method according to claim 1 , wherein the temperature of the injection mixture is in the range of 100°C and 300 °C, e.g. in the range of 180-250 °C, when injected into the hydrocarbon reservoir.

3) Method according to any of the preceding claims, wherein the pressure of the injection mixture is in the range of 50 to 250 bar when injected into the hydrocarbon reservoir.

4) Method according to any of the preceding claims, wherein the temperature of the injection mixture is in the range of 100°C and 300 °C and the pressure is in the range of 50 to 250 bar.

5) Method according to any of the preceding claims, wherein the molar ratio of steam and nitrogen gas in the injection mixture is in the range of 1 :0.5 to 1 :5, e.g. in the range of 1 :1 to 1 :2 when injected into the hydrocarbon reservoir, or e.g. approximately 1 :1 .

6) Method according to any of the preceding claims, wherein the molar fraction of steam in the injection mixture is below 80%, e.g. below 70%, or e.g. in the range of 30-60%.

7) Method according to any of the preceding claims, wherein the injection mixture also comprises carbon dioxide.

8) Method according to any of the preceding claims, wherein the injection mixture comprises a mixture of steam, nitrogen gas and carbon dioxide. 9) Method according to any of the preceding claims, wherein the injection mixture is injected at a depth of at least 500 m. 10) Method according to any of the preceding claims wherein at least part of the water for providing the steam is obtained as a combustion product from hydrocarbons. 1 1 ) Method according to any of the preceding claims wherein at least part of the heat for providing the steam is obtained as a combustion product from hydrocarbons.

12) Method according to claim 10 or 1 1 , wherein at least part of the water and/or heat for providing steam is obtained from the combustion of hydrocarbons produced in step d), most preferably from a gas fraction of the collected hydrocarbons from the hydrocarbon reservoir.

13) Method according to any of the preceding claims wherein at least part of the nitrogen gas is obtained in a gas separation process, wherein oxygen obtained in the same gas separation process is used for the combustion of hydrocarbons, preferably hydrocarbons collected from the hydrocarbon reservoir.

14) Method according to any of the preceding claims, wherein the injection mixture comprises carbon dioxide, wherein at least part of the carbon dioxide in the injection mixture is derived from the combustion of hydrocarbons, preferably hydrocarbons collected from the hydrocarbon reservoir..

15) Method according to any of the preceding claims, wherein

combustion of hydrocarbons, and

optionally, the injection mixture comprises carbon dioxide, wherein at least part of the carbon dioxide is derived from the combustion of hydrocarbons,

wherein at least part of the combusted hydrocarbons are collected from the natural hydrocarbon reservoir.