CN1014336B - In-situ Steam Flooding Oil Recovery Method - Google Patents

Abstract

An oil and water-containing subterranean reservoir can be heated in a manner capable of inducing an economically feasible production of oil from zones which were initially so impermeable as to be undesirably unproductive in response to injections of oil recovery fluids. Treatment zones of specified thickness are conductively heated from boreholes arranged in a specified pattern of heat-injecting and fluid-producing wells and heated to above about 600degree C.

Description

The present invention is a method for recovering oil from underground oil reservoirs through in-situ steam flooding by conduction heating. More specifically, the present invention relates to the treatment of the following underground oil reservoirs, which have relatively high porosity and contain a large amount of oil and water, but The permeability is so low that there is almost no fluid production for the injection of displacement fluids such as water, steam, hot gas or oil-miscible solvents.

Some of the Diatomite/Brown shale formations in the Belridge field (USA) are typical of such reservoirs. These formations are characterized by a depth greater than 60 meters, a thickness of approximately 300 meters, a porosity of approximately 50%, an oil saturation of approximately 40%, an oil API gravity of approximately 30 degrees, and a water saturation of approximately 60%, although within the formation Natural fractures exist, but with a permeability of less than 1 mD. It is found that in these formations, in the process of primary oil recovery, the ratio of the production volume to the formation oil content is very low, such as only 5% or lower. And they are largely unresponsive to conventional secondary or tertiary oil recovery processes. Publications such as SPE 10773, "Causes of Production Decline in the Belridge-Diatomite Oil Field: An Examination of Rock Mechanics," published in San Francisco in March 1982, typify this type of recovery problem. This article is a study undertaken to explain the rapid decline in oil production. Paper No. SPE10966, "Fractured Results of Diatomite Formation in South Bellridge Field, California," published in New Orleans, September 1982, also discusses this decline in production. The article states that representative calculated production curves over the range of conditions encountered indicate cumulative oil recovery of only about 1-14% of original geologic reserves.

Oil recovery from underground oil shale by heat transfer was invented in Sweden by F·Jingstroem (Ljungstroem). This method is described in Swedish Patent No. 121737, 123136, 123137, 123138, 125712 and 126674, U.S. Patent No. 2732195 and some articles in magazines, such as IVA1953 Volume 24, "According to Jiang Stowe on pages 118-123 of No. 3 Underground pyrolysis of shale oils by the Momm method" and "Net incremental energy available for in situ dielectric heating of oil shale" published in Proceedings of the Oil Shale Conference, Vol. 11, pp. 311-330 (1978). Described (this method was invented in the 1940s and had a small-scale industrial application in the 1950s). In the method, both the heat injection well and the solution production well are completed in the same permeable oil shale formation close to the surface, and the gap between the well holes is less than three meters. Heat injection wells are equipped with electric or other heating elements that are surrounded by a variety of materials (such as sand or cement) that allow them to transfer heat to the oil shale while preventing any inflow or outflow of fluids. When designing and testing this method for oil shale with a continuous inflow of groundwater, the water needs to be pumped continuously to avoid unnecessary energy loss in evaporating the groundwater.

U.S. Patent No. 3113623 describes a method for heating formations to facilitate hydrocarbon recovery. The method employs a counter-flow type burner through which fuel flows into the burner through a gas permeable tubing system so that the entire slit of the formation can be induced to burn.

For those deposits that are virtually completely impermeable, relatively deep and thick, and potentially oil-producing, such as tar sands or oil shale deposits (such as those found in the Piceance Basin in the United States), heat transfer processes are used to recover oil, According to previous theories and views, it is definitely not feasible economically. For example, in the above-mentioned Oil Shale Conference Proceedings the Gingerstrom method is described as a method "...that successfully recovers shale oil by embedding tubular electric heating elements in high-grade shale deposits." This method relies on the usual Thermal diffusion heats the shale. Obviously, thermal diffusion requires high temperature gradients, so the heating is very uneven; it takes several months to completely retort a block of shale the size of a room. Moreover, due to insufficient heating of the shale area outside the edge of the retort zone, the shale closest to the heat source is overheated and a large amount of thermal energy is wasted. The latter issue is particularly important for western shales, because above about 600 °C endothermic reactions occur, and thermal energy in superheated regions cannot be fully recovered by diffusion (p. 313).

Creating and maintaining a permeable zone through which heated oil or high temperature cracking products can flow is a difficult task in a substantially impermeable formation. U.S. Patent No. 3468376 once stated (in columns 1 and 2): "There are two mechanisms for heat transfer through oil shale, namely, heat transfer in the solid matrix of oil shale by conduction and heat transfer by convection. The above heat transfer. Conduction heat transfer is a relatively slow process. The average thermal conductivity and average thermal diffusivity of oil shale are similar to those of refractory bricks. The permeability of oil shale solid matrix is extremely low, which is similar to that of unglazed porcelain Very similar. Thus, convective heat transfer is limited to the heating of fluids flowing in communicating channels throughout the oil shale. These flow channels can be natural fractures and artificially induced fractures.  … When heated, immediately adjacent to the channels A zone of pyrolyzed oil shale is formed. This layer is an inorganic mineral matrix containing varying degrees of carbon. This layer acts as an expanding barrier to heat flow from the heating fluid in the channels." This patent involves circulating and heating an oil shale-pyrolysis fluid through a flow channel, and at the same time adding abrasive particles to the circulating fluid to erode the pyrolysis oil shale layer formed adjacent to the channel. U.S. Patent No. 3,284,281 talks about (column 1, lines 3 to 21): "Attempts to heat shale by various methods, such as...resistance heaters..., have had little success in recovering oil from oil shale. In the use of intralayer combustion or other methods of heating previous oil shale fracturing treatments, which have rarely been successful, which is Partial or complete closure of fractures occurs due to shale expansion that occurs with heating. The patent describes a sequential process that involves heating (and thus expanding) oil shale, injecting fluids to hydraulically fracture the expanded shale, and repeating these steps until a thermally stable fracture is extended to production U.S. Patent No. 3,455,391 discloses that hydraulically induced fractures in formations are mostly vertical fractures, allowing thermal fluid to flow through the vertical fractures, thermally expanding the rock and closing the fractures, so fluids can be injected under a pressure sufficient to form horizontal fractures.

It is an object of the present invention to provide an improved method of heating a highly impermeable subterranean oil reservoir and then recovering oil from the reservoir. According to the present invention, at least two wells are completed to a treatment interval having a thickness of at least about 30 meters in the oily water zone of a reservoir that is unfavorably unfavorable for the injected displacement fluid. Permeability and non-productivity. The wells are arranged such that at least one of the heat injection well and the fluid production well extends substantially throughout the treatment interval, the boreholes are substantially parallel, and are separated by a substantially equal distance of at least about 6 meters. For each heat injection well substantially penetrating the treated interval, in order to prevent fluid flow between the wellbore and the reservoir, the oil surface is sealed with a solid material or cement with relatively good thermal conductivity and substantially impermeable to fluid. In each fluid production well substantially throughout the treatment interval, fluid communication is established between the wellbore and the reservoir to enable the wells to produce fluids from the reservoir. Heating within each injector well throughout at least substantially the entire treatment interval at a rate or rates capable of (a) increasing the temperature inside the wellbore to at least about 600°C, and (b) maintaining The temperature inside the wellbore is at least about 600°C, but not so high that the equipment in the wellbore is thermally damaged, and at the same time, the speed of heat transfer out of the wellbore is not significantly higher than the rate allowed by the reservoir heat transfer itself.

The present invention is premised, at least in part, on the discovery that The treatment process functions when the reservoir of the type specified in the present invention is treated in a specified manner. The following mechanism appears to be involved.

The injected heat seeps into the formation only by conduction. However, when the formation temperature rises, say to 250-300°C, both water and hydrocarbons will form steam, and high pressure will be generated due to the expansion of these fluids. Under the action of this pressure gradient created, the fluid flows to the production well either at the low velocity allowed by the low natural permeability, or flows to the production well through fractures created or interconnected by extension when the pore pressure approaches the overburden pressure. well.

As water and hydrocarbon vapors travel toward production wells, they condense in cooler parts of the formation, and the latent heat released preheats the formation to a so-called "steam" temperature, which is approximately equal to the wet steam at overlying pressure. temperature. Some of the heat is thus transferred by convection, greatly speeding up the process than if all the heat were transferred by conduction only.

Such water vapor and hydrocarbon steam generation, pressurization and displacement through the oil-bearing parts of the reservoir are in situ steam flooding. This displacement has many features of the so-called "steam distillation displacement" described by B.T. Willman, V.V. Walleroy, G.W. Runherg, A.J. Cornelius (Cornelius) and L.W. Paul Worth (Powers) in the Journal of the American Institute of Mining and Metallurgy Engineers (AIME), July 1961, page 681, "Laboratory studies of oil recovery by steam injection". Therefore, many of the phenomena found in steam distillation flooding are expected to occur in this process as well, especially with regard to the mixing of hydrocarbon condensates with virgin oil in cooler parts of the formation. The hydrocarbon condensate is more volatile and less viscous than the original oil. When the vaporization front reaches the point where the original oil has been diluted with hydrocarbon condensate , pressurized steam distillation of the resulting diluent oil vaporizes more of the oil fraction than the original oil itself heated to the same temperature and pressure. This mechanism can enhance the displacement efficiency of in situ generated steam flooding proposed by this process beyond that obtained by simple steam distillation from virgin crude oil.

Furthermore, Applicants have now found that in certain circumstances it is advantageous to apply the following procedure. The best way to create a fluid-impermeable barrier between the reservoir and the portion of the wellbore where the heater is located is to install the heater in a bottom-sealed casing or tubing string surrounded by thermally stable and Materials that conduct heat, such as cement. The optimum rate of heat generation in the injection well is about 1200 to 2400 kilojoules per hour per meter, or about 330 to 660 watts per meter for electric resistance heaters in the case of electrical heating. Examples of commonly applicable speeds are from 264 to 726 watts per meter or the corresponding speed expressed in kilojoules. In formations that have a tendency to squeeze and collapse around the wellbore when the fluid pressure in the wellbore is relatively low (such as diatomaceous earth/palm shale formations), the fluid pressure in the fluid production well should be kept high enough to prevent extrusion. In this case the heat injection well is preferably continued to be heated until fluid is driven into at least one fluid production well. Fluid outflow from each fluid production well (that is, the well into which the fluid is driven) is preferably limited to the extent necessary to allow the fluid pressure in the well to increase sufficiently to prevent significant compression of adjacent formations. limit. Generally speaking, this increase in fluid pressure in the wellbore should increase the reservoir fluid pressure to 7 to 14 bar above the natural fluid pressure of the adjacent formation. Gas pressure (steam, methane, etc.) generated in the injection well maintains high pore pressure and prevents extrusion. Squeeze can occur regardless of temperature in diatomaceous earth formations when the effective pressure exceeds about 35 bar, for example, when the overburden pressure minus the fluid pressure in the reservoir, that is, the effective stress is about 35 bar or higher , the formation will be squeezed.

Thus, although the present invention does not depend on any particular mechanism, its functioning at least in key aspects involves the steam distillation displacement process, and the steam is generated in situ by conduction of heat from the very hot injection well. of.

The present invention is now explained in more detail with reference to the accompanying drawings, in which:

Figure 1 is a schematic diagram of the temperature distribution around a heat injector at a typical stage of the process.

Figure 2 similarly illustrates the temperature distribution at different stages of the process, the time t of the process being expressed in years.

Figure 3 is the relationship curve between the oil production rate P (barrel/day) and time t (year) of each heat injection well.

Fig. 4 is the curve of the time t (year) of the process as a function of well spacing Dw (m).

Figure 5 is the relationship curve of the heat demand (kJ/barrel of oil) versus the time required for the process (years).

Figures 6 and 7 show the relationship between oil recovery and time obtained by simulating the heat transfer process for reservoir intervals containing layers of different permeability.

Figure 1 schematically illustrates the temperature distribution in the reservoir surrounding the injector well during a typical stage of the process. And it is assumed that the heat flows radially, so the formation temperature is only a function of the distance γ from the center of the heat injection well.

Zone I in Figure 1, which is located between the wellbore radius (γw) and the vaporization front (γb), where all the water is vaporized. In a practical sense heat flows only by conduction. Conductive flow with radial symmetry of heat generally produces a linear variation of temperature with the logarithm of γ over an extremely large range. The above facts can be equivalently described as: the temperature distribution in zone I can be accurately described by the steady-state solution of the differential equation.

The pore volume with I contains a small amount of liquid or solid heavy hydrocarbon residues. These residues account for only a small part of the original geological oil reserves, and are composed of heavy hydrocarbon components in crude oil that cannot be vaporized by steam distillation. At the prevailing temperatures in Zone I (for example, 300-800°C) these hydrocarbons crack and form coke and light hydrocarbon gases which will displace most of the steam previously present. For this reason we assume that the pore space in zone I not occupied by heavy hydrocarbons is filled with methane, in other words, no water in any form exists in zone I.

In Fig. 1 it is assumed that the temperature of zone II located at the vaporization front (γb) and the condensation front (γf) is fixed. This zone is comparable to the steam zone in conventional steam flooding. In band II it is assumed that the pressure value is equal to the overlay pressure and the temperature is equal to the steam temperature at this pressure. The rationale for this hypothesis is that the permeability of diatomaceous earth/brown shale formations is so low in many places that the pressure may have to be raised to fracture pressure in order to provide flow paths for water and hydrocarbon vapors.

Like steam flooding in this process, it is expected that most of the oil displacement, including oil steam distillation, may occur near the condensation front (γf). We will therefore assume that the pore space within zone II will be filled with water and steam with a saturation S ^II _w corresponding to the original water saturation and containing oil with a saturation S ^II _o .

In zone III (outside the condensation front (γf)), the pore volume contains formation water and oil at substantially the original temperature and saturation.

As mentioned earlier, in contrast to most flooding processes, the vertical sweep efficiency of this process is not determined by the properties of the formation, but by the properties of the heater (at least to a first approximation). Ideally, the heat injection rate is substantially the same from the top to the bottom of the heater so that the injection profile is substantially uniform. When electric heating is applied, the heat injected per unit formation thickness is P ⁵ _H =i ² ν/A, where i is the current passing through the heater, A is the cross-sectional area, and ν is the resistivity of the heating wire.

As a second order approximation, the resistivity of the heating wire increases with temperature. The section of heating wire corresponding to a formation of lower thermal conductivity will be hotter and therefore more resistive than the section of heating wire corresponding to a formation of higher thermal conductivity. This way, it may seem absurd, but the less thermally conductive layer will be able to inject slightly more heat.

During the initial stages of carrying out the process, heat flows radially outward from the injection wells within the well pattern. This may continue until two adjacent tropical fronts begin to overlap. From this point on, the temperature at the midpoint between two adjacent injection wells will rise faster than at a point at the same distance from the heater well but in the direction of the production well (since the midpoint receives heat). Thus we have another seemingly paradoxical situation where the isotherms substantially intersect each other after the first cycle around the injectors and expand rapidly outward, thus rapidly heating the intermediate zone between adjacent injectors. This is where the flow is usually bypassed during oil flooding and results in reduced sweep efficiency.

In contrast, we can expect high horizontal sweep efficiency in this process because the oil is displaced by a thermal gradient that is selectively directed around and inward toward the producing well.

We previously assumed that in this process, as in most steam floods, oil is displaced at the steam condensation front (γf). According to this model, cumulative oil recovery should be proportional to the size of the tropics. Since the heat injection speed is relatively fast in the early stage of this process (assuming that the temperature in the heat injection is constant), the expansion speed of the heated part of the oil layer will also be relatively high, so the oil production rate is relatively high. After the heat injection rate decreases, the oil production rate also decreases.

The process begins with most reservoirs near original oil and water saturation. In the absence of In the case of gas, this means that oil flooding from the hot zone to the cold zone of the reservoir is unlikely to significantly increase the initial oil saturation. We can therefore expect that fluids displaced from the tropics will quickly bring oil into production, at least for those formations that contain little gas. For example, at a depth of about 360 meters in the diatomite/palm shale formation in the Belridge Oilfield, when the temperature in the injection well is maintained at about 500-700°C and the well spacing is about 15 meters, it will recover in about two years. There will be liquid driven to the production well.

Both oil recovery rate and cumulative oil recovery are strongly affected by the amount of oil remaining after Zone II passes. Preliminary experiments show that about 70% (by weight) of the original oil, such as that of the Belridge diatomite formation, is steam distillable. But if the hydrocarbon condensate mixes with the original oil (and drives off some of it), more of the mixture can be vaporized and more than 70% of the oil can be recovered. However, we assume only 60% recovery in the numerical examples discussed below.

A factor that may have a negative impact on cumulative oil recovery is the geometry of the well pattern. The wells are extra closely spaced to heat the formation to the temperature required for the process in a reasonably short time. Well spacing may preferably be as small as 20 meters. Obviously, the boreholes of these wells should be nearly vertical, or at least basically parallel to each other (at least in the interval of the treated reservoir), and a deviation from vertical or parallel of more than 1 meter may seriously affect the horizontal sweep efficiency, thereby affecting the cumulative oil recovery .

Heat demand is defined as the heat injected per barrel of oil produced. This parameter is of paramount importance from an economic point of view. With electrical resistance heating, the heat generated is expensive, and the cost of electricity required per barrel harvested can be high. The model described here is slightly more optimistic about the heat demand of the process. This is due to negligible heat conduction ahead (downstream) of the condensation front. In steam flooding using steam injection, similar assumptions are more accurate because The steam front expands much faster. In this process, all fronts move very slowly, and a large amount of heat will move to the front of the condensation front. We will estimate the size of this error later. The heat loss of the top and bottom rocks is also neglected, but this heat loss is relatively small compared with the loss downstream of the condensate front.

When electric heating is applied, the higher the current in the heating wire, the higher the rate of heat injection. Therefore, the temperature of the heating wire is also higher. When the temperature is too high, the heating wire will melt and the injection well will be damaged.

It is possible to install electric heaters that can work at temperatures up to 1200°C. However, we still recommend that the maximum temperature of the heating wire be kept below about 900°C to prevent the injection well from being damaged and requiring re-drilling. Generally speaking, the rate of heat injection is adjusted so that the internal temperature of the wellbore is maintained at a selected value, not so high as to damage the well equipment, and the rate at which the injected heat is transferred from the well is not significantly increased. Faster than the thermal conductivity of the oil layer allows. The following method is very beneficial to cause the above-mentioned heating speed, that is, the installation of resistance heating elements in the casing with a closed bottom makes the heater resistance arranged along the layer to be heated and the distribution pattern of the thermal conductivity of the formation adjacent to the layer Correlated and echoed, these heaters were activated at an average rate of about 330 to 660 watts per meter of spacing along the interval.

The hypothetical example below presents the calculation of some of the more important process variables for a specific set of process parameters roughly representative of the Belridge Field diatomaceous earth/brown shale formation. This calculation evaluates an average case characterized by the parameter values given in Table 1.

Table 1 Process parameters

Experimental area 4.05×10 ⁶ m ²

h stratum thickness 335 meters

C ^I _g Specific heat of gas in band I 0.6 cal/g °C

Specific heat of Cm rock minerals 0.6 cal/g °C

The specific heat of non-gas hydrocarbons in C ^Ⅰ _O band Ⅰ is 0.4 cal/g°C

The specific heat of non-gas hydrocarbons in C ^Ⅱ _O band Ⅱ is 0.4 cal/g°C

The specific heat of water in C ^Ⅱ _W zone Ⅱ is 1.0 cal/g°C

Hs The heat content of 1 gram of steam is 640 cal/g

γw heat injection well radius 10 cm

Hydrocarbon gas saturation in S ^Ⅰ _g band Ⅰ is 0.9

Saturation of non-gas hydrocarbons in S ^Ⅰ _O zone Ⅰ is 0.1

The non-gas hydrocarbon saturation in S ^Ⅱ _O zone Ⅱ is 0.145

Soi initial oil saturation 0.36

Vapor saturation in Ss zone Ⅱ 0.255

S ^Ⅱ _W zone Ⅱ water saturation 0.6

To original reservoir temperature 40℃

Ts steam temperature 300℃

Tw injection well temperature 800℃

φ porosity 0.55

β formation thermal conductivity temperature relationship coefficient 3×10/℃

The value of λo at 0°C 10 cal/s cm°C

ρ ^Ⅰ The density of hydrocarbon gas in _band Ⅰ is 0.04 g/ ^cm3

ρm rock mineral density 2.5 g/ ^cm3

The density of non-gas hydrocarbons in ρ ^Ⅰ _O band Ⅰ is 1.0 g/ ^cm3

The density of non-gas hydrocarbons in ρ ^Ⅱ _O band Ⅱ is 0.9 g/ ^cm3

ρs vapor density 0.04 g/ ^cm3

The density of water in ρ ^Ⅱ _W band Ⅱ is 0.7 g/ ^cm3

Fig. 2 shows various temperature distributions (marked by respective dashed and solid lines, as shown in Fig. 1) around the injector well determined for different γb values corresponding to different condensation front positions, where the solid line represents vaporization The dotted line indicates the condensation front. A notable feature shown in Figure 2 is that only a relatively small portion of the formation is heated to very high temperatures. For example, at the moment when the vaporization front is 15 meters away from the injection well, the 500°C isotherm moves no more than about 3 meters away from the injection well. Figure 2 further illustrates that the size of the vapor band (Zone II, described in Figure 1) is still relatively small. This is especially important given that we ignore the enthalpy of formations downstream of the condensation front, this heat flowing by conduction ahead of the vapor front must be supplied by further reducing the size of the vapor band. Therefore, we can conclude that only a very small portion of the formation is actually at steam temperature. Most formations are either above (and dry) or below steam temperature.

Figure 3 shows the oil recovery rate P (barrels/day). It should be noted here that this "oil production" is actually the amount of oil driven out from the vicinity of the heat injection well. Since the process can be expected to have a high sweep efficiency, most of the displaced oil can be recovered. In the five-point well pattern example, each injection well has a production well, so Figure 3 can describe the oil recovery of each production well relatively accurately. This is especially the case since there is little interference between injection wells until most of the oil (80%) is produced.

In the seven-spot pattern example, the tropical zones of adjacent injector wells begin to overlap when approximately 60% of the oil is produced. On the other hand, each production well in the seven-point well pattern corresponds to two heat injection wells, so the initial oil production rate of each production well will be twice as high as that of the five-point well pattern. When the hot spots of adjacent injection wells begin to overlap, both the heat injection rate and the oil recovery rate begin to decay at a faster rate than calculated from the radial model. But in general, in the case of the seven-point well pattern, the initial higher oil production rate must be more important than the later, more rapid decline. Especially since the equipment of heat injection wells will be cheaper than that of production wells, the seven-point well pattern should be better than the five-point well pattern.

The same point is illustrated in Figure 4, which shows that applying the same well spacing Dw, the process time t (expressed in years) calculated by the seven-point well pattern (second curve) is shorter than that calculated by the five-point well pattern (first curve ) is significantly shorter. This figure also shows that a well spacing Dw of about 20-21 meters is required to ensure a process lifetime of about 20-30 years.

Figure 5 illustrates the heat demand of the process. Except for the early stage, about 460,000 kilojoules of heat are injected per barrel of oil. Due to the negligible heat conduction downstream of the condensation front, the calculated heat demand is optimistic.

For the sake of our model, all fluids (oil and water) are assumed to be produced at original reservoir temperatures. In fact, due to conductive preheating downstream of the steam front, the produced fluid gradually warms up shortly thereafter until it reaches steam temperature (at which point the process ends). Since heat transfer is a slow process, fluids will be produced at original reservoir temperatures during the first few years of the process. In fact it can be stated that at least 25% of the produced fluids are cold.

For a conservative estimate of heat demand, we need to assume that 25% of the produced fluids are at the original formation temperature and the remaining 75% are produced at steam temperatures. for In our example, this very conservative assumption increases the heat demand from 460,000 kJ/barrel to 760,000 kJ/barrel. The true value (acknowledging that the other assumptions are correct) should be somewhere between these two values, and unless we develop a more accurate model, a value of about 600,000 kJ/barrel will be considered reasonable.

So far, we have given the full results of each individual well or each individual well pattern dynamics. In these cases, both the injection rate and the production rate appear to be small. Assuming that the well pattern density is 10-12 wells per 4,000 ^m2 , we can expect to inject electricity and heat at a rate of about 730 megawatts in 27 years, and produce oil at an average rate of 100,000 barrels per day, accumulatively producing 1 billion barrels Oil.

The reservoir to be treated can generally be any subterranean reservoir having relatively thick oil-bearing formations with high porosity, containing large quantities of oil and water, but with such low permeability that injection of conventional production fluids The response is disappointingly no fluid output. Such formations preferably have a porosity times oil saturation product of at least 0.15. The oil has an API gravity of at least about 10° and a water saturation of at least about 30%. The present invention has particular advantages for recovering oil from oil reservoirs having a permeability of less than about 10 mD. Other examples of other reservoirs with similar characteristics are other diatomite formations in California (USA) and elsewhere, and hydrocarbon-bearing white formations, etc.

The heat injection well used in this process consists essentially of any cased or uncased wellbore that (1) penetrates at least substantially through at least about 30 meters of the treatment interval in formations of the type described above, (2) The arrangement in the well pattern makes each wellbore basically parallel in the entire treatment interval, and the distance between the wells and the adjacent wells is about 6 to 24 meters, and (3) contains heat-resistant, heat-conducting, and basic to the fluid An impermeable shell or barrier of solid material to prevent fluid flow between the wellbore and the exposed face of the reservoir and/or fractures communicating with the wellbore. to those skilled in the art It is obvious that, in the application of resistance heating or combustion heating, temperature fluctuations are generally allowed during the heating process. The required heating rate is only an average value along the heating layer, and fluctuations such as temporary shutdown and pressure fluctuations should not have a serious impact on the heating rate.

The fluid production wells used in the present invention can generally be any wells in the above-mentioned specified well pattern. In terms of arrangement, it is required to be adjacent to at least one heater well, to be in fluid communication with the oil layer, and to at least basically run through the entire treatment interval. When producing fluid while maintaining the fluid pressure in the wellbore, the fluid pressure in the well should be lower than the fracture pressure of the oil layer.

The means of heating the inside of the well can be actually any wellbore heating device that can raise the temperature and maintain the temperature inside the wellbore at the above-mentioned specified value. Such heating means may be electric or gas-fired. Among them, the electric heating device is the best. The electrical components, for easier maintenance, are preferably installed in a section of casing with a closed bottom. This section of casing is sealed in a heat transfer, impermeable shell, which is in contact with the oil layer. The heating method should preferably reach a temperature of at least about 600°C relatively quickly (preferably 800°C), but maintain the temperature below 1000°C (preferably 900°C) for a long time, while requiring heat transfer from the wellbore to the outside The speed cannot be significantly faster than the thermal conductivity of the oil layer will allow.

Those thermally stable, thermally conductive and fluid-impermeable materials that form the barrier between the reservoir and the heater are preferably steel pipes surrounded by thermally conductive material that is in contact with the reservoir and/or fractures communicating with the wellbore . Since the influx of fluids from the formation is often the most troublesome fluid flow pattern between the wellbore and the reservoir, it may be necessary in some cases to pressurize the barrier or casing in order to prevent and/or terminate this flow. way of fluid inflow. The gas used in the pressurization process is preferably a gas such as nitrogen or an inert gas. The material surrounding this barrier and in contact with the oil layer should be heat resistant in the temperature range of approximately 600 to 1000°C and have good thermal conductivity. heat resistant cement or concrete for this over It is the most suitable material for this application in the process. Such suitable cements are described in patents such as US 3,507,332.

We found that in heterogeneous formations, such as Belridge's diatomite formation, failures of many heat transfer processes can occur. Differential thermal conductivity of the formation may result in uneven heating temperatures. Due to the electrical properties of copper, more heat will be injected into the "rich" layers with poor thermal conductivity than into the "lean" layers with better thermal conductivity. Since thermal conductivity is a function of solid density, a more porous layer of diatomaceous earth will absorb more heat than a less porous layer. This is undesirable because higher porosity formations are more permeable formations, and in these formations a lower temperature process can be effective if less heat enters.

In extreme cases, if a heater with a fixed cross-section is used, in the rich layer heat injection will continue after the process has been completed. And the heat injected into the lean layer is not enough.

Therefore, relatively increasing the injection rate in lean zones with poor porosity and permeability will result in significant improvements in the oil recovery and thermal efficiency of the process. This can be achieved by using copper heaters of variable cross-section and/or by using parallel heating cables, placing more cables along the leaner layer than along the richer layer, or by other means of varying the heating rate.

In order to illustrate the influence of permeability on process dynamics, Figure 6 and Figure 7 show the mathematical simulation production dynamics of three layers with different permeability and the same other properties. The difference between the two examples is the injection speed. In Fig. 6 the heat injection rate is the same for various permeability. The speed is measured in watts per meter, 500 watts for the first 3 years, 410 watts for the next 3 years, 330 watts for the next 2 years, and 250 watts for the last 3 years.

The heat injection rates in Figure 7 are different, in the layers of 1 and 2 mD decreased and increased in the 0.3 mD layer. The rate of injection into the 1 mD layer is reduced by 10%, the rate of injection into the 2 mD layer is reduced by 15%, and the rate of injection into the 0.3 mD layer is increased by 15%.

In the first case (Fig. 6), the heat injection lasted 11 years. It can be seen that although no oil has been produced from the most permeable zone heat continues to be injected into this zone, while the least permeable zone does not get enough heat to complete the process.

In the second case (Fig. 7), heat is injected until all zones achieve the same oil recovery, but the overall heat consumption is reduced. Although the process completion time of the 1 and 2 mD layers was delayed, the recovery rate of the 0.3 mD layer was greatly improved in addition to the advance of the process completion time.

The recovery factor and thermal efficiency of the process are summarized in Table 2.

Table 2. Overview of process recovery and thermal efficiency

The heat injection amount of each layer is the same Change the heat injection amount of each layer

layer (millidarcy) 0.3 1.0 2.0 0.3 1.0 2.0

Recovery factor (%) 8 84 84 83 83 83

Thermal efficiency 421 398 400 427 380 339

(10 kJ/barrel ground oil)

Process Completion Time 22 12 10 14 13 12

(Year)

The simulation results show that the thermal efficiency is improved by about 10%. This suggests that, applying this modified heat injection method, the heat savings of approximately 10-15% can be achieved by producing a certain amount of oil from a given type of reservoir.

In a best practice, the determination of the rate of heat injection for each zone in a given situation is based on known overall properties of the formation as well as economic analysis. In some cases, it may also be economically beneficial to overinject in certain formations in order to recover oil earlier.

Claims (14)

1, descends the oil production method on oil-containing and water stratum heatedly, being included in heat injection well and the fluid extraction well each class all has at least flatly and handles completion on the interval on above-mentioned stratum, this oil reservoir is thick at least about 30 meters, while oil-containing and water, reaction for the oil recovery fluid that injects is both impermeable can not production, the method is characterized in that:

To make the well that runs through these wells of handling interval substantially parallel during by these wells of row, and separate with about at least 6 meters distance that equates substantially;

In running through every mouthful of heat injection well handling interval, come the Seal Oil aspect with the impervious substantially solid material barrier of the better convection cell of thermal conductivity;

In running through every mouthful of fluid extraction well handling interval, fluid is communicated with between well and oil reservoir, and to make fluid can be in oil reservoir output, and

In running through every mouthful of heated well handling interval at least substantially, heat, its firing rate requires can (a) to make the well internal temperature to be increased to 600 ℃ and (b) make the well internal temperature maintain about 600 ℃ at least at least, but can not make temperature high to making the well internal equipment because of the overheated degree of damaging, leave the limit that the heat transfer rate of well can not be allowed apparently higher than the oil reservoir capacity of heat transmission simultaneously.

By the described method of claim 1, it is characterized in that 2, the means of heating heat injection well well inside should be able to make temperature remain on about 600 to 900 ℃.

3, by the described method of claim 1, it is characterized in that heating at least, the means of a bite heat injection well inside are electric heater.

4, by the described method of claim 1, it is characterized in that the solid material of Seal Oil aspect is the cement or the concrete of heat conduction.

5,, it is characterized in that to handle the interval place be substantially parallel running through for described heat injection and fluid extraction well, and at least in this interval, about 6 to 24 meters of each interval by the described method of claim 1.

6, by the described method of claim 1, it is characterized in that, most of heat injection wells and fluid extraction well with basically in vertical direction by five-spot, 7 methods or ten line-of-sight course well pattern well spacing.

7, by the described method of claim 1, it is characterized in that, till heating will proceed to always and have fluid to drive in the well of a bite fluid extraction well at least, and every mouthful of fluid external flux of being driven to fluid extraction well wherein will be limited in and borehole fluid pressure is increased to be enough to stop the obviously desired degree of extruding of oil reservoir.

By the described method of claim 7, it is characterized in that 8, described fluid pressure need be increased to approximately higher by 7 * 10 than the natural hydrostatic pressure in next-door neighbour stratum ⁵To 14 * 10 ⁵Handkerchief.

9,, it is characterized in that firing rate is or in every meter about 1200 to 2400 kJ (kilojoule)s per hour by the described method of claim 1.

10, by the described method of claim 1, it is characterized in that described solid material barrier is made of heat-resisting sleeve pipe, the sleeve pipe lower end is tight sealing for fluid, and be cement around.

11, by the described method of claim 10, it is characterized in that, described for barrier around well inside be heated by resistive the device heating, its heating power is approximately 330 to 660 watts every meter.

12, by the described method of claim 1, it is characterized in that, described oil reservoir, contain a relatively not too layer of infiltration at least, the permeability of this layer to be lower than significantly at least one in handling interval other layer; This method further comprises the steps;

Definite edge is a bite heat injection well and run into the position of above-mentioned relative low-permeability layer at least; With

In the above-mentioned heat injection of a bite at least well, increase the relative velocity of heat injection along the lower layer of above-mentioned at least one permeability, make its speed above the speed along above-mentioned at least one permeability higher level, the quantity of its increase is relevant with permeability higher level permeability value added.

13, by the described method of claim 12, it is characterized in that, with resistive element heating heat injection well, and at least in a bite heat injection well, the arrangement of heating element will make the resistance of unit length heater higher relatively along the permeability lower level, so that above-mentioned high relatively heat injection speed is provided.

14, by the described method of claim 12, it is characterized in that, with resistive element heating heat injection well, and at least in a bite well, the arrangement of resistive element will comprise many parallel straties in handling interval, and the number along the resistive element of permeability lower level will be more than another layer at least in this interval, so that above-mentioned high relatively firing rate is provided.

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