Patent Application
20130112403
1. Field of the Invention
The present invention relates to the field of hydrocarbon recovery from subsurface formations. More specifically, the present invention relates to the in situ recovery of hydrocarbon fluids from organic-rich rock formations including, for example, oil shale formations, coal formations and tar sands formations. The present invention also relates to methods for heating a subsurface formation using electrical energy.
2. General Discussion of Technology
This section is intended to introduce various aspects of the art, which may be associated with exemplary embodiments of the present disclosure. This discussion is believed to assist in providing a framework to facilitate a better understanding of particular aspects of the present disclosure. Accordingly, it should be understood that this section should be read in this light, and not necessarily as admissions of prior art.
Certain geological formations are known to contain an organic matter known as “kerogen.” Kerogen is a solid, carbonaceous material. When a substantial amount of kerogen is imbedded in rock formations, the mixture is referred to as oil shale. This is true whether or not the rock is, in fact, technically shale, that is, a rock formed from compacted clay.
Kerogen is subject to decomposing upon exposure to heat over a period of time. Upon heating, kerogen molecularly decomposes to produce oil, gas, and carbonaceous coke. Small amounts of water may also be generated. The oil, gas and water fluids become mobile within the rock matrix, while the carbonaceous coke remains essentially immobile.
Oil shale formations are found in various areas world-wide, including the United States. Such formations are notably found in Wyoming, Colorado, and Utah. Oil shale formations tend to reside at relatively shallow depths and are often characterized by limited permeability. Some consider oil shale formations to be hydrocarbon deposits which have not yet experienced the years of heat and pressure thought to be required to create conventional oil and gas reserves.
The decomposition rate of kerogen to produce mobile hydrocarbons is temperature dependent. Temperatures generally in excess of 270° C. (518° F.) over the course of many months may be required for substantial conversion. At higher temperatures substantial conversion may occur within shorter times. When kerogen is heated to the necessary temperature, chemical reactions break the larger molecules forming the solid kerogen into smaller molecules of oil and gas. The thermal conversion process is referred to as pyrolysis, or retorting.
Attempts have been made for many years to extract oil from oil shale formations. Near-surface oil shales have been mined and retorted at the surface for over a century. In 1862, James Young began processing Scottish oil shales. The industry lasted for about 100 years. Commercial oil shale retorting through surface mining has been conducted in other countries as well. Such countries include Australia, Brazil, China, Estonia, France, Russia, South Africa, Spain, Jordan and Sweden. However, the practice has been mostly discontinued in recent years because it proved to be uneconomical or because of environmental constraints on spent shale disposal. (See T. F. Yen, and G. V. Chilingarian, “Oil Shale,” Amsterdam, Elsevier, p. 292.) Further, surface retorting requires mining of the oil shale, which limits that particular application to very shallow formations.
In the United States, the existence of oil shale deposits in northwestern Colorado has been known since the early 1900's. While research projects have been conducted in this area from time to time, no serious commercial development has been undertaken. Most research on oil shale production was carried out in the latter half of the 1900's. The majority of this research was on geology, geochemistry, and retorting in surface facilities.
In 1947, U.S. Pat. No. 2,732,195 issued to Fredrik Ljungstrom. That patent, entitled “Method of Treating Oil Shale and Recovery of Oil and Other Mineral Products Therefrom,” proposed the application of heat at high temperatures to the oil shale formation in situ. The purpose of such in situ heating was to distill hydrocarbons and produce them to the surface. The '195 Ljungstrom patent is incorporated herein in its entirety by reference.
Ljungstrom coined the phrase “heat supply channels” to describe bore holes drilled into the formation. The bore holes received an electrical heat conductor which transferred heat to the surrounding oil shale. Thus, the heat supply channels served as early heat injection wells. The electrical heating elements in the heat injection wells were placed within sand or cement or other heat-conductive material to permit the heat injection wells to transmit heat into the surrounding oil shale while substantially preventing the inflow of fluids. According to Ljungstrom, the subsurface “aggregate” was heated to between 500° C. and 1,000° C. in some applications.
Along with the heat injection wells, fluid producing wells were completed in near proximity to the heat injection wells. As kerogen was pyrolyzed upon heat conduction into the aggregate or rock matrix, the resulting oil and gas would be recovered through the adjacent production wells.
Ljungstrom applied his approach of thermal conduction from heated wellbores through the Swedish Shale Oil Company. A full-scale plant was developed that operated from 1944 into the 1950's. (See G. Salamonsson, “The Ljungstrom In Situ Method for Shale-Oil Recovery,” 2nd Oil Shale and Cannel Coal Conference, v. 2, Glasgow, Scotland, Institute of Petroleum, London, p. 260-280 (1951).
Additional in situ methods have been proposed. These methods generally involve the injection of heat and/or solvent into a subsurface oil shale formation. Heat may be in the form of heated methane (see U.S. Pat. No. 3,241,611 to J. L. Dougan), flue gas, or superheated steam (see U.S. Pat. No. 3,400,762 to D. W. Peacock). Heat may also be in the form of electric resistive heating, dielectric heating, radio frequency (RF) heating (U.S. Pat. No. 4,140,180, assigned to the ITT Research Institute in Chicago, Ill.) or oxidant injection to support in situ combustion. In some instances, artificial permeability has been created in the matrix to aid the movement of pyrolyzed fluids upon heating. Permeability generation methods include mining, rubblization, hydraulic fracturing (see U.S. Pat. No. 3,468,376 to M. L. Slusser and U.S. Pat. No. 3,513,914 to J. V. Vogel), explosive fracturing (see U.S. Pat. No. 1,422,204 to W. W. Hoover, et al.), heat fracturing (see U.S. Pat. No. 3,284,281 to R. W. Thomas), and steam fracturing (see U.S. Pat. No. 2,952,450 to H. Purre).
It has also been disclosed to run alternating current or radio frequency electrical energy between stacked conductive fractures or electrodes in the same well in order to heat a subterranean formation. Examples of early patents discussing the use of electrical current for heating include:
U.S. Pat. No. 3,642,066 titled “Electrical Method and Apparatus for the Recovery of Oil,” provides a description of resistive heating within a subterranean formation by running alternating current between different wells. Others have described methods to create an effective electrode in a wellbore. See U.S. Pat. No. 4,567,945 titled “Electrode Well Method and Apparatus;” and U.S. Pat. No. 5,620,049 titled “Method for Increasing the Production of Petroleum From a Subterranean Formation Penetrated by a Wellbore.”
In 1989, U.S. Pat. No. 4,886,118 issued to Shell Oil Company. That patent, entitled “Conductively Heating a Subterranean Oil Shale to Create Permeability and Subsequently Produce Oil,” declared that “[c]ontrary to the implications of . . . prior teachings and beliefs . . . the presently described conductive heating process is economically feasible for use even in a substantially impermeable subterranean oil shale.” (col. 6, ln. 50-54). Despite this declaration, it is noted that few, if any, commercial in situ shale oil operations have occurred other than Ljungstrom's. Shell's '118 patent proposed controlling the rate of heat conduction within the rock surrounding each heat injection well to provide a uniform heat front. The '118 Shell patent is incorporated herein in its entirety by reference.
Additional history behind oil shale retorting and shale oil recovery can be found in co-owned U.S. Pat. No. 7,331,385 entitled “Methods of Treating a Subterranean Formation to Convert Organic Matter into Producible Hydrocarbons,” and in U.S. Pat. No. 7,441,603 entitled “Hydrocarbon Recovery from Impermeable Oil Shales.” The Backgrounds and technical disclosures of these two patent publications are incorporated herein by reference.
A need exists for improved processes for the production of shale oil. In addition, a need exists for improved methods for heating organic-rich rock formations in connection with an in situ pyrolyzation process. Still further, a need exists for methods that facilitate an expeditious and effective subsurface heater well arrangement using an electrically conductive granular material placed within an organic-rich rock formation.
The methods described herein have various benefits in improving the recovery of hydrocarbon fluids from an organic-rich rock formation such as a formation containing heavy hydrocarbons or solid hydrocarbons. In various embodiments, such benefits may include increased production of hydrocarbon fluids from an organic-rich rock formation, and avoiding areas of high electrical resistivity near heat injection wells during formation heating.
A method for heating a subsurface formation using electrical resistance heating is first provided. In one embodiment, the method first includes the step of placing a first electrically conductive proppant into a fracture. The fracture has been formed within an interval of organic-rich rock in the subsurface formation. The organic-rich rock may be, for example, a heavy oil such as bitumen. Alternatively, the organic-rich rock may be oil shale that comprises kerogen.
The first electrically conductive proppant is preferably comprised of metal shavings, steel shot, graphite, calcined coke, or other electrically conductive material. The first proppant has a first bulk resistivity.
The method also includes placing a second electrically conductive proppant into or adjacent the fracture, and in contact with the first proppant. The second electrically conductive proppant also is preferably comprised of metal shavings, steel shot, graphite, or calcined coke. The second proppant has a second bulk resistivity that is lower than the first bulk resistivity.
The second electrically conductive proppant is placed in electrical communication with the first electrically conductive proppant. The electrical communication is provided at three or more distinct terminals. Each terminal provides a local region of relatively high electrical conductivity in comparison to the first electrically conductive proppant. In this way, inordinate heat is not generated proximate the wellbore as the current enters or leaves the fracture.
In one embodiment, the second proppant is continuous and the terminals are simply different locations along a wellbore. In another embodiment, the second proppant provides three or more discrete second proppant portions along a single wellbore. In still another embodiment, the second proppant provides proppant portions within distinct wellbores that intersect the fracture. In any arrangement, each terminal has its own electrically conductive lead extending to the surface.
The method also comprises passing electric current through the second electrically conductive proppant at a first terminal. The current passes through the second electrically conductive proppant and through the first electrically conductive proppant. In this way, heat is generated within the at least one fracture by electrical resistance.
It is understood that the current travels along a circuit that includes an electrical source. Thus, an electrical source is provided at the surface. The electrical source may be electricity obtained from a regional grid. Alternatively, electricity may be generated on-site through a gas turbine or a combined cycle power plant. The circuit will also include an insulated electrical cable, rod, or other device that delivers the current to the selected terminal as an electrically conductive lead.
After passing through the second electrically conductive proppant and then through the first electrically conductive proppant in the fracture, the current travels back to the surface. In returning to the surface, the current may travel back to the first wellbore and return through a separate electrically conductive lead. Alternatively, the current may travel through a separate wellbore to the surface.
The method further includes monitoring resistance. Resistance is monitored at the first terminal while current passes through that location. The method then includes switching the flow of electricity from the first terminal to a second terminal such that electric current is passed through the second electrically conductive proppant at the second terminal, and then through the first electrically conductive proppant to generate heat within the at least one fracture. Switching the terminals may be done to provide a more efficient flow of electrical current through the fracture.
In one aspect of the method, the steps of passing electric current serve to heat the subsurface formation adjacent the at least one fracture to a temperature of at least 300° C. This is sufficient to mobilize heavy hydrocarbons such as bitumen in a tar sands development area. This also is sufficient to pyrolyze solid hydrocarbons into hydrocarbon fluids in a shale oil development area.
A separate method of heating a subsurface formation using electrical resistance heating is also provided herein. The alternate method first includes the step of forming a first wellbore. The first wellbore penetrates an interval of organic-rich rock within the subsurface formation. The wellbore may be a single wellbore completed either vertically or substantially horizontally. Alternatively, the wellbore may be a multi-lateral wellbore wherein more than one deviated production portion is formed from a single parent wellbore.
The method also includes forming at least one fracture in the subsurface formation. The fracture is formed from the first wellbore and within the interval of organic-rich rock.
The method also comprises placing a first electrically conductive proppant into the at least one fracture. The first electrically conductive proppant has a first bulk resistivity. The step of placing the first electrically conductive proppant into the fracture is preferably done by pumping the proppant into the fracture using a hydraulic fluid.
The method also includes placing a second electrically conductive proppant into or adjacent the fracture. The second proppant is placed in contact with the first proppant. The second proppant is tuned to have a second bulk resistivity that is lower than the first bulk resistivity. This permits electrical current to flow from the wellbore without creating undesirable hot spots. Preferably, the resistivity of the first electrically conductive proppant is about 10 to 100 times greater than the resistivity of the second electrically conductive proppant. In one aspect, the resistivity of the first electrically conductive proppant is about 0.005 to 1.0 Ohm-Meters.
The method further includes placing the second electrically conductive proppant in electrical communication with the first electrically conductive proppant. Electrical communication is provided at three or more terminals. In one embodiment, the second proppant is continuous and the terminals are simply different locations along a wellbore. In another embodiment, the second proppant provides three or more discrete proppant portions along a single wellbore. In still another embodiment, the second proppant provides proppant portions within distinct wellbores that intersect the fracture. In any arrangement, each terminal has its own electrically conductive lead extending to the surface.
The method also comprises passing electric current through the second electrically conductive proppant at a first terminal. The current passes through the second electrically conductive proppant and through the first electrically conductive proppant. In this way, heat is generated within the at least one fracture by electrical resistivity.
An electrical source is provided at the surface for the current. The electrical source is designed to generate or otherwise provide an electrical current to the first electrically conductive proppant located within the fracture. The electrical source may be electricity obtained from a regional grid. Alternatively, electricity may be generated on-site through a gas turbine or a combined cycle power plant.
After passing through the second electrically conductive proppant and then through the first electrically conductive proppant in the fracture, the current travels back to the surface. In returning to the surface, the current may travel back to the first wellbore and return through a separate electrically conductive lead at a different terminal. Alternatively, the current may travel through a separate wellbore to the surface.
Current is directed from the electrical source at the surface to the terminals using electrical connections. The electrical connections are preferably insulated copper wires or cables that extend through the wellbore. However, they may alternatively be insulated rods, bars, or metal tubes. The only requirement is that they transmit electrical current down to the interval to be heated, and that they are insulated from one another.
The method also includes switching the flow of electricity from the first terminal to a second terminal. In this way, electric current is passed through the second electrically conductive proppant at the second terminal, and through the first electrically conductive proppant to generate heat within the at least one fracture.
In one aspect of the method, passing electric current through the fracture heats the subsurface formation adjacent the at least one fracture to a temperature of at least 300° C. This is sufficient to mobilize heavy hydrocarbons such as bitumen in a tar sands development area. This also is sufficient to pyrolyze solid hydrocarbons into hydrocarbon fluids in a shale oil development area.
So that the present inventions can be better understood, certain drawings, charts, graphs and flow charts are appended hereto. It is to be noted, however, that the drawings illustrate only selected embodiments of the inventions and are therefore not to be considered limiting of scope, for the inventions may admit to other equally effective embodiments and applications.
As used herein, the term “hydrocarbon” refers to an organic compound that includes primarily, if not exclusively, the elements hydrogen and carbon. Hydrocarbons may also include other elements, such as, but not limited to, halogens, metallic elements, nitrogen, oxygen, and/or sulfur. Hydrocarbons generally fall into two classes: aliphatic, or straight chain hydrocarbons, and cyclic, or closed ring hydrocarbons, including cyclic terpenes. Examples of hydrocarbon-containing materials include any form of natural gas, oil, coal, and bitumen that can be used as a fuel or upgraded into a fuel.
As used herein, the term “hydrocarbon fluids” refers to a hydrocarbon or mixtures of hydrocarbons that are gases or liquids. For example, hydrocarbon fluids may include a hydrocarbon or mixtures of hydrocarbons that are gases or liquids at formation conditions, at processing conditions or at ambient conditions (15° C. and 1 atm pressure). Hydrocarbon fluids may include, for example, oil, natural gas, coalbed methane, shale oil, pyrolysis oil, pyrolysis gas, a pyrolysis product of coal, and other hydrocarbons that are in a gaseous or liquid state.
As used herein, the terms “produced fluids” and “production fluids” refer to liquids and/or gases removed from a subsurface formation, including, for example, an organic-rich rock formation. Produced fluids may include both hydrocarbon fluids and non-hydrocarbon fluids. Production fluids may include, but are not limited to, pyrolyzed shale oil, synthesis gas, a pyrolysis product of coal, carbon dioxide, hydrogen sulfide and water (including steam).
As used herein, the term “fluid” refers to gases, liquids, and combinations of gases and liquids, as well as to combinations of gases and solids, and combinations of liquids and solids.
As used herein, the term “gas” refers to a fluid that is in its vapor phase at ambient conditions.
As used herein, the term “condensable hydrocarbons” means those hydrocarbons that condense to a liquid at about 15° C. and one atmosphere absolute pressure. Condensable hydrocarbons may include a mixture of hydrocarbons having carbon numbers greater than 4.
As used herein, the term “non-condensable” means those chemical species that do not condense to a liquid at about 15° C. and one atmosphere absolute pressure. Non-condensable species may include non-condensable hydrocarbons and non-condensable non-hydrocarbon species such as, for example, carbon dioxide, hydrogen, carbon monoxide, hydrogen sulfide, and nitrogen. Non-condensable hydrocarbons may include hydrocarbons having carbon numbers less than 5.
As used herein, the term “heavy hydrocarbons” refers to hydrocarbon fluids that are highly viscous at ambient conditions (15° C. and 1 atm pressure). Heavy hydrocarbons may include highly viscous hydrocarbon fluids such as heavy oil, tar, and/or asphalt. Heavy hydrocarbons may include carbon and hydrogen, as well as smaller concentrations of sulfur, oxygen, and nitrogen. Additional elements may also be present in heavy hydrocarbons in trace amounts. Heavy hydrocarbons may be classified by API gravity. Heavy hydrocarbons generally have an API gravity below about 20 degrees. Heavy oil, for example, generally has an API gravity of about 10-20 degrees, whereas tar generally has an API gravity below about 10 degrees. The viscosity of heavy hydrocarbons is generally greater than about 100 centipoise at about 15° C.
As used herein, the term “solid hydrocarbons” refers to any hydrocarbon material that is found naturally in substantially solid form at formation conditions. Non-limiting examples include kerogen, coal, shungites, asphaltites, and natural mineral waxes.
As used herein, the term “formation hydrocarbons” refers to both heavy hydrocarbons and solid hydrocarbons that are contained in an organic-rich rock formation. Formation hydrocarbons may be, but are not limited to, kerogen, oil shale, coal, bitumen, tar, natural mineral waxes, and asphaltites. A formation that contains formation hydrocarbons may be referred to as an “organic-rich rock.”
As used herein, the term “tar” refers to a viscous hydrocarbon that generally has a viscosity greater than about 10,000 centipoise at 15° C. The specific gravity of tar generally is greater than 1.000. Tar may have an API gravity less than 10 degrees. “Tar sands” refers to a formation that has tar in it.
As used herein, the term “kerogen” refers to a solid, insoluble hydrocarbon that principally contains carbon, hydrogen, nitrogen, oxygen, and sulfur.
As used herein, the term “bitumen” refers to a non-crystalline solid or viscous hydrocarbon material that is substantially soluble in carbon disulfide.
As used herein, the term “oil” refers to a hydrocarbon fluid containing primarily a mixture of condensable hydrocarbons.
As used herein, the term “subsurface” refers to geologic strata occurring below the earth's surface. Similarly, the term “formation” refers to any definable subsurface region. The formation may contain one or more hydrocarbon-containing layers, one or more non-hydrocarbon containing layers, an overburden, and/or an underburden of any geologic formation. An “overburden” and/or an “underburden” is geological material above or below the formation of interest.
An overburden or underburden may include one or more different types of substantially impermeable materials. For example, overburden and/or underburden may include sandstone, shale, mudstone, or wet/tight carbonate (i.e., an impermeable carbonate without hydrocarbons). An overburden and/or an underburden may include a hydrocarbon-containing layer that is relatively impermeable. In some cases, the overburden and/or underburden may be permeable.
As used herein, the term “hydrocarbon-rich formation” refers to any formation that contains more than trace amounts of hydrocarbons. For example, a hydrocarbon-rich formation may include portions that contain hydrocarbons at a level of greater than 5 percent by volume. The hydrocarbons located in a hydrocarbon-rich formation may include, for example, oil, natural gas, heavy hydrocarbons, and solid hydrocarbons.
As used herein, the term “organic-rich rock” refers to any rock matrix holding solid hydrocarbons and/or heavy hydrocarbons. Rock matrices may include, but are not limited to, sedimentary rocks, shales, siltstones, sands, silicilytes, carbonates, and diatomites. Organic-rich rock may contain kerogen or bitumen.
As used herein, the term “organic-rich rock formation” refers to any formation containing organic-rich rock. Organic-rich rock formations include, for example, oil shale formations, coal formations, and tar sands formations.
As used herein, the term “pyrolysis” refers to the breaking of chemical bonds through the application of heat. For example, pyrolysis may include transforming a compound into one or more other substances by heat alone or by heat in combination with a catalyst. Pyrolysis may include modifying the nature of the compound by addition of hydrogen atoms which may be obtained from molecular hydrogen, water, or other hydrocarbon-bearing compound. Heat may be transferred to a section of the formation to cause pyrolysis.
As used herein, the term “hydraulic fracture” refers to a fracture at least partially propagated into a formation, wherein the fracture is created through injection of pressurized fluids into the formation. While the term “hydraulic fracture” is used, the inventions herein are not limited to use in hydraulic fractures. The invention is suitable for use in any fracture created in any manner considered to be suitable by one skilled in the art. The fracture may be artificially held open by injection of a proppant material. Hydraulic fractures may be substantially horizontal in orientation, substantially vertical in orientation, or oriented along any other plane.
As used herein, the term “monitor” or “monitoring” means taking one or more measurements in real time. Monitoring may be done by an operator, or may be done using control software. In one aspect, monitoring means taking measurements to calculate an average resistance over a designated period of time.
As used herein, the term “wellbore” refers to a hole in the subsurface made by drilling or insertion of a conduit into the subsurface. A wellbore may have a substantially circular cross section, or other cross-sectional shape (e.g., an oval, a square, a rectangle, a triangle, or other regular or irregular shapes). As used herein, the term “well”, when referring to an opening in the formation, may be used interchangeably with the term “wellbore.”
The inventions are described herein in connection with certain specific embodiments. However, to the extent that the following detailed description is specific to a particular embodiment or a particular use, such is intended to be illustrative only and is not to be construed as limiting the scope of the inventions.
The hydrocarbon development area 100 also has a subsurface 120. The subsurface 120 includes various formations, including one or more near-surface formations 122, a hydrocarbon-bearing formation 124, and one or more non-hydrocarbon formations 126. The near surface formations 122 represent an overburden, while the non-hydrocarbon formations 126 represent an underburden. Both the one or more near-surface formations 122 and the non-hydrocarbon formations 126 will typically have various strata with different mineralogies therein.
The hydrocarbon development area 100 is for the purpose of producing hydrocarbon fluids from the hydrocarbon-bearing formation 124. The hydrocarbon-bearing formation 124 defines a rock matrix having hydrocarbons residing therein. The hydrocarbons may be solid hydrocarbons such as kerogen. Alternatively, the hydrocarbons may be viscous hydrocarbons such as heavy oil that do not readily flow at formation conditions. The hydrocarbon-bearing formation 124 may also contain, for example, tar sands that are too deep for economical open pit mining. Therefore, an enhanced oil recovery method involving heating is desirable.
It is understood that the representative formation 124 may be any organic-rich rock formation, including a rock matrix containing kerogen, for example. In addition, the rock matrix making up the formation 124 may be permeable, semi-permeable or non-permeable. The present inventions are particularly advantageous in shale oil development areas initially having very limited or effectively no fluid permeability. For example, initial permeability may be less than 10 millidarcies.
The hydrocarbon-bearing formation 124 may be selected for development based on various factors. One such factor is the thickness of organic-rich rock layers or sections within the formation 124. Greater pay zone thickness may indicate a greater potential volumetric production of hydrocarbon fluids. Each of the hydrocarbon-containing layers within the formation 124 may have a thickness that varies depending on, for example, conditions under which the organic-rich rock layer was formed. Therefore, an organic-rich rock formation such as hydrocarbon-bearing formation 124 will typically be selected for treatment if that formation includes at least one hydrocarbon-containing section having a thickness sufficient for economical production of hydrocarbon fluids.
The richness of one or more sections in the hydrocarbon-bearing formation 124 may also be considered. For an oil shale formation, richness is generally a function of the kerogen content. The kerogen content of the oil shale formation may be ascertained from outcrop or core samples using a variety of data. Such data may include Total Organic Carbon content, hydrogen index, and modified Fischer Assay analyses. The Fischer Assay is a standard method which involves heating a sample of a hydrocarbon-containing-layer to approximately 500° C. in one hour, collecting fluids produced from the heated sample, and quantifying the amount of fluids produced.
An organic-rich rock formation such as formation 124 may be chosen for development based on the permeability or porosity of the formation matrix even if the thickness of the formation 124 is relatively thin. Subsurface permeability may also be assessed via rock samples, outcrops, or studies of ground water flow. An organic-rich rock formation may be rejected if there appears to be vertical continuity and connectivity with groundwater.
Other factors known to petroleum engineers may be taken into consideration when selecting a formation for development. Such factors include depth of the perceived pay zone, continuity of thickness, and other factors. For instance, the organic content or richness of rock within a formation will effect eventual volumetric production.
In order to access the hydrocarbon-bearing formation 124 and recover natural resources therefrom, a plurality of wellbores is formed. The wellbores are shown at 130, with some wellbores 130 being seen in cut-away and one being shown in phantom. The wellbores 130 extend from the surface 110 into the formation 124.
Each of the wellbores 130 in
In one aspect, the purpose for heating the organic-rich rock in the formation 124 is to pyrolyze at least a portion of solid formation hydrocarbons to create hydrocarbon fluids. The organic-rich rock in the formation 124 is heated to a temperature sufficient to pyrolyze at least a portion of the oil shale (or other solid hydrocarbons) in order to convert the kerogen (or other organic-rich rock) to hydrocarbon fluids. In either instance, the resulting hydrocarbon liquids and gases may be refined into products which resemble common commercial petroleum products. Such liquid products include transportation fuels such as gasoline, diesel, jet fuel and naphtha. Generated gases may include light alkanes, light alkenes, H2, CO2, CO, and NH3.
The solid formation hydrocarbons may be pyrolyzed in situ by raising the organic-rich rock in the formation 124, (or heated zones within the formation), to a pyrolyzation temperature. In certain embodiments, the temperature of the formation 124 may be slowly raised through the pyrolysis temperature range. For example, an in situ conversion process may include heating at least a portion of the formation 124 to raise the average temperature of one or more sections above about 270° C. at a rate less than a selected amount (e.g., about 10° C., 5° C.; 3° C., 1° C., or 0.5° C.) per day. In a further embodiment, the portion may be heated such that an average temperature of one or more selected zones over a one month period is less than about 375° C. or, in some embodiments, less than about 400° C.
The hydrocarbon-rich formation 124 may be heated such that a temperature within the formation reaches (at least) an initial pyrolyzation temperature, that is, a temperature at the lower end of the temperature range where pyrolyzation begins to occur. The pyrolysis temperature range may vary depending on the types of formation hydrocarbons within the formation, the heating methodology, and the distribution of heating sources. For example, a pyrolysis temperature range may include temperatures between about 270° C. and 800° C. In one aspect, the bulk of a target zone of the formation 124 may be heated to between 300° C. and 600° C.
For in situ operations, the heating and conversion process occurs over a lengthy period of time. In one aspect, the heating period is from three months to four or more years.
Conversion of oil shale into hydrocarbon fluids will create permeability in rocks in the formation 124 that were originally substantially impermeable. For example, permeability may increase due to formation of thermal fractures within a heated portion caused by application of heat. As the temperature of the heated formation 124 increases, water may be removed due to vaporization. The vaporized water may escape and/or be removed from the formation 124 through the production wells “P.” In addition, permeability of the formation 124 may also increase as a result of production of hydrocarbon fluids generated from pyrolysis of at least some of the formation hydrocarbons on a macroscopic scale. For example, pyrolyzing at least a portion of an organic-rich rock formation may increase permeability within a selected zone to about 1 millidarcy, alternatively, greater than about 10 millidarcies, 50 millidarcies, 100 millidarcies, 1 Darcy, 10 Darcies, 20 Darcies, or even 50 Darcies.
It is understood that petroleum engineers will develop a strategy for the best depth and arrangement for the wellbores 130 depending upon anticipated reservoir characteristics, economic constraints, and work scheduling constraints. In addition, engineering staff will determine what wellbores “I” should be formed for initial formation heating.
In an alternative embodiment, the purpose for heating the rock in the formation 124 is to mobilize viscous hydrocarbons. The rock in the formation 124 is heated to a temperature sufficient to liquefy bitumen or other heavy hydrocarbons so that they flow to a production well “P.” The resulting hydrocarbon liquids and gases may be refined into products which resemble common commercial petroleum products. Such liquid products include transportation fuels such as diesel, jet fuel and naphtha. Generated gases may include light alkanes, light alkenes, H2, CO2, CO, and NH3. For bitumen, the resulting hydrocarbon liquids may be used for road paving and surface sealing.
In the illustrative hydrocarbon development area 100, the wellbores 130 are arranged in rows. The production wells “P” are in rows, and the heat injection wells “I” are in adjacent rows. This is referred to in the industry as a “line drive” arrangement. However, other geometric arrangements may be used such as a 5-spot arrangement. The inventions disclosed herein are not limited to the arrangement of production wells “P” and heat injection wells “I” unless so stated in the claims.
In the arrangement of
In the view of
The production wells “P” and the heat injection wells “I” are also arranged at a pre-determined spacing. In some embodiments, a well spacing of 15 to 25 feet is provided for the various wellbores 130. The claims disclosed below are not limited to the spacing of the production wells “P” or the heat injection wells “I” unless otherwise stated. In general, the wellbores 130 may be from about 10 feet up to even about 300 feet in separation.
Typically, the wellbores 130 are completed at shallow depths. Completion depths may range from 200 to 5,000 feet at true vertical depth. In some embodiments, an oil shale formation targeted for in situ retorting is at a depth greater than 200 feet below the surface, or alternatively 400 feet below the surface. Alternatively, conversion and production occur at depths between 500 and 2,500 feet.
A production fluids processing facility 150 is also shown schematically in
In order to carry out the process described above in connection with
As alluded to above, several designs have been previously offered for electrical heater wells. One example is found in U.S. Pat. No. 3,137,347 titled “In Situ Electrolinking of Oil Shale.” The '347 patent describes a method by which electric current is flowed through a fracture connecting two wells to get electric flow started in the bulk of the surrounding formation. Of interest, heating of the formation occurs primarily due to the bulk electrical resistance of the formation itself. F. S. Chute and F. E. Vermeulen, Present and Potential Applications of Electromagnetic Heating in the In Situ Recovery of Oil, AOSTRA J. Res., v. 4, p. 19-33 (1988) describes a heavy-oil pilot test where “electric preheat” was used to flow electric current between two wells to lower viscosity and create communication channels between wells for follow-up with a steam flood.
Another example is found in U.S. Pat. No. 7,331,385, mentioned briefly above. That patent is entitled “Methods of Treating a Subterranean Formation to Convert Organic Matter into Producible Hydrocarbons.” The '385 patent teaches the use of electrically conductive fractures to heat oil shale. According to the '385 patent, a heating element is constructed by forming wellbores in a formation, and then hydraulically fracturing the oil shale formation around the wellbores. The fractures are filled with an electrically conductive material which forms the heating element. Preferably, the fractures are created in a vertical orientation extending from horizontal wellbores. An electrical current is passed through the conductive fractures from about the heel to the toe of each well. To facilitate the current, an electrical circuit may be completed by an additional transverse horizontal well that intersects one or more of the vertical fractures. The process of U.S. Pat. No. 7,331,385 creates an “in situ toaster” that artificially matures oil shale through the application of electric heat. Thermal conduction heats the oil shale to conversion temperatures in excess of about 300° C., causing artificial maturation.
Yet another example of electrical heating is disclosed in U.S. Patent Publ. No. 2008/0271885 published on Nov. 6, 2008. This publication is entitled “Granular Electrical Connections for In Situ Formation Heating.” In this publication, a resistive heater is formed by placing an electrically conductive granular material within a passage formed along a subsurface formation and proximate a stratum to be heated. In this disclosure, two or three wellbores are completed within the subsurface formation. Each wellbore includes an electrically conductive member. The electrically conductive member in each wellbore may be, for example, a metal rod, a metal bar, a metal pipe, a wire, or an insulated cable. The electrically conductive members extend into the stratum to be heated.
Passages are also formed in the stratum creating fluid communication between the wellbores. In some embodiments, the passage is an inter-connecting fracture; in other embodiments, the passage is one or more inter-connecting bores drilled through the formation. Electrically conductive granular material is then injected, deposited, or otherwise placed within the passages to provide electrical communication between the electrically conductive members of the adjacent wellbores.
In operation, a current is passed between the electrically conductive members. Passing current through the electrically conductive members and the intermediate granular material causes resistive heat to be generated primarily from the electrically conductive members within the wellbores. FIGS. 30A through 33 of U.S. Patent Publ. No. 2008/0271885 are instructive in this regard.
U.S. Patent Publ. No. 2008/0230219 describes other embodiments wherein the passage between adjacent wellbores is a drilled passage. In this manner, the lower ends of adjacent wellbores are in fluid communication. A conductive granular material is then injected, poured or otherwise placed in the passage such that granular material resides in both the wellbores and the drilled passage. In operation, a current is again passed through the electrically conductive members and the intermediate granular material to generate resistive heat. However, in U.S. Patent Publ. No. 2008/0230219, the resistive heat is generated primarily from the granular material. FIGS. 34A and 34B are instructive in this regard.
U.S. Patent Publ. No. 2008/0230219 also describes individual heater wells having two electrically conductive members therein. The electrically conductive members are placed in electrical communication by conductive granular material placed within the wellbore at the depth of a formation to be heated. Heating occurs primarily from the electrically conductive granular material within the individual wellbores. These embodiments are shown in FIGS. 30A, 31A, 32, and 33.
In one embodiment, the electrically conductive granular material is interspersed with slugs of highly conductive granular material in regions where no or minimal heating is desired. Materials with greater conductivity may include metal filings or shot; materials with lower conductivity may include quartz sand, ceramic particles, clays, gravel, or cement.
Co-owned U.S. Pat. Publ. No. 2010/0101793 is also instructive. That application was published on 29 Apr. 2010 and is entitled “Electrically Conductive Methods for Heating a Subsurface Formation to Convert Organic Matter into Hydrocarbon Fluids.” The published application teaches the use of two or more materials placed within an organic-rich rock formation and having varying properties of electrical resistance. Specifically, the granular material placed proximate the wellbore is highly conductive, while the granular material injected into a surrounding fracture is more resistive. An electrical current is passed through the granular material in the formation to generate resistive heat. The materials placed in situ provide for resistive heat without creating hot spots near the wellbores.
Co-owned U.S. Pat. No. 7,331,385, U.S. Pat. Publ. No. 2010/0101793, and U.S. Patent Publ. No. 2008/0230219 each present efficient means for forming wellbores used for generating electrically resistive heat. However, each also preferably requires the use of two or more wellbores completed in close proximity with intersecting materials. Therefore, it is desirable to reduce the number of wells to be drilled while still taking advantage of the efficiencies offered through the use of conductive granular material.
Additional wellbore arrangements and methods for heating a formation containing organic-rich rock using electrically conductive granular material are offered herein.
Referring now to
In one aspect, the organic-rich rock formation 216 comprises solid hydrocarbons. Examples of solid hydrocarbons include kerogen, shungites, and natural mineral waxes. In this instance, heating the organic-rich rock formation 216 pyrolyzes the solid hydrocarbons into hydrocarbon fluids. The hydrocarbon fluids may then be produced through production wells to an earth surface 205 for further processing and commercial sale.
In another aspect, the organic-rich rock formation 216 comprises heavy hydrocarbons such as heavy oil, tar, and/or asphalt. The heavy oil might make up a so-called “tar sands” formation. In this instance, heating the organic-rich rock formation 216 serves to mobilize bitumen or tar so that hydrocarbons may flow as a fluid through production wells (not shown) to the surface 205.
In the arrangement of
Pressure gauges at the surface 205 should inform the operator when a linking of fractures has taken place. In this respect, the operator will observe a drop in pressure as fracturing fluid injected into one wellbore begins to communicate with the fracture formed from the other wellbore Linking the two fractures allows for an electrically conductive proppant to become a single electrically conductive body. The merger of two fracture planes is called coalescence. The concept of fracture coalescence has been discussed in SPE Paper No. 27, 718, published in 1994. See K. E. Olson and A. W. M. El-Rabaa, “Hydraulic Fracturing of the Multizone Wells in the Pegasus (Devonian) Field, West Texas,” SPE Paper No. 27,718 (Mar. 16-18, 1994).
In
It is important to note that the fracture 220 extends parallel to the wellbores 230, 240. Because the wellbores 230, 240 are vertical, this means the plane of the fracture 220 is formed at a depth where the fracture plane is also oriented vertically. According to principles of geomechanics, fracture planes tend to form in a direction perpendicular to the direction of least minimum principal stress. For formations that are less than 1,000 feet, for example, fracture planes typically tend to form horizontally. For formations that are greater than about 1,000 feet in depth, fracture planes tend to form vertically. Thus, the vertical wellbore embodiment shown in
The fracture 220 contains a first electrically conductive proppant (not shown). The first proppant is placed in the fracture 220 by injecting a hydraulic fluid containing the proppant through the wellbores 230, 240. The hydraulic fluid is injected into the subsurface formation 210 at a pressure that exceeds a formation parting pressure, as is known in the art. A first electrically conductive proppant fills the fracture plane 220. The first electrically conductive proppant is carried into the wellbores 230, 240, through respective perforations, and into the fracture 220 via hydraulic fluid or other carrier medium.
In the heater well arrangement 200 of
In accordance with the methods herein, the first electrically conductive proppant has a first bulk resistivity. Similarly, the second electrically conductive proppant has a second bulk resistivity. The second bulk resistivity is lower than the first bulk resistivity, meaning that the second electrically conductive proppant is more electrically conductive than the first electrically conductive proppant. This beneficially serves to prevent regions of excess heating, or “hot spots,” that might naturally occur in connection with the flow of electricity into and out of the fracture 220.
The combination of the two wellbores 230, 240 along with the linking fracture 220 and the placement of first and second electrically conductive proppants provide a useful heater well arrangement 200. In order to heat the organic-rich rock formation 216 using the heater well arrangement 200, electric current is passed from the surface 205 and down the first wellbore 230, through the second proppant in zone 225′, through the first proppant in fracture 220, through the second proppant in zone 225″, and up the second wellbore 240. In this manner, the organic-rich rock formation 216 may be heated from the fracture 220 using electrically resistive heating.
Additional details of the heater well arrangement 200 are shown in the progressive views of
Wellbore 230 has been completed with a string of casing 232. The string of casing 232 defines a bore 235 through which fluids may be injected or equipment may be placed. The casing 232 is secured in place with a cement sheath 234. The cement sheath 234 resides within an annular region formed between the casing 232 and the surrounding near-surface formation 212. The cement sheath 234 isolates any aquifers or sensitive zones along the near-surface formation 212.
Similarly, wellbore 240 has been completed with a string of casing 242. The string of casing 242 defines a bore 245 through which fluids may be injected or equipment may be placed. The casing 242 is secured in place with a cement sheath 244. The cement sheath 244 resides within an annular region formed between the casing 242 and the surrounding near-surface formation 212. The cement sheath 244 isolates any aquifers or sensitive zones along the near-surface formation 212.
Wellbore 230 has been perforated along the organic-rich rock 216. Perforations are shown at 236. Similarly, wellbore 240 has been perforated along the organic-rich rock 216, with perforations shown at 246.
Moving now to
In order to form the fracture 220, a hydraulic fluid laden with proppant is injected through the perforations 236, 246. The injection is at a pressure greater than the parting pressure of the subsurface formation 210. The proppant comprises electrically conductive particles such as metal shavings, steel shot, calcined coke, metal coated particles, graphite, or combinations thereof. The hydraulic fluid laden with proppant leaves a first electrically conductive proppant 222 within the fracture 220.
It can be seen in
Each lead 238, 248 is preferably a copper or other metal wire protected within its own insulated cover. However, the leads 238, 248 may alternatively be steel rods, pipes, bars or cables that are insulated down to the subsurface formation 210. In any embodiment, the leads 238, 248 have a tip that is exposed to the second electrically conductive proppant 227.
As an additional feature to the heater well arrangement 200, at least one of the wellbores 230, 240 includes three or more terminals. In the wellbore 230, terminals are indicated at 231, while in the wellbore 240 terminals are indicated at 241. Individual leads 238 extend down to respective terminals 231, while individual leads 248 extend down to respective terminals 241. In this way, current may be passed into the second electrically conductive proppant 227 through wellbore 230 at one of the selected terminals 231, while current may be passed out of the second electrically conductive proppant 227 through wellbore 240 at one of the selected terminals 241.
To further demonstrate the relationship between the leads 238 and the terminals 231,
Each electrically conductive lead 238a, 238b, 238c is insulated with a tough rubber or other non-electrically conducting exterior. However, the tips 233 of the conductive leads 238a, 238b, 238c are exposed. This allows the internal metal portions of the leads 238a, 238b, 238c to contact the second proppant 227 (not shown in
In order to form an electrical circuit for the heater well arrangement 200, an electricity source is provided at the surface 205. Returning to
The control system 256 controls the delivery of electrical power to the terminals 231, 241. In this respect, the operator may monitor electrical resistance at the initially selected terminals 231, 241, and change the selected terminals 231, 241 as resistance changes over time. For instance, electrical current may initially be delivered through line 255′ to electrical lead 238a and down to terminal 231a for a designated period of time. As solid hydrocarbons are pyrolyzed (or as heavy hydrocarbons are mobilized), a shift may take place in the host organic-rich rock formation 216, causing a break-up in electrical connectivity with the first proppant 222 near wellbore 230. The shift may take place, for example, as a result of strain on the rock hosting the proppant 222, 227.
It is understood that the process of heating rock in situ, especially rock containing solid hydrocarbons, causes thermal expansion. Thermal expansion is followed by pyrolysis and a loss of solid material supporting the overburden and acting down against the underburden. All of this increases the stress on the fracture 220. This, in turn, may decrease the electrical resistance along any current flow paths in a manner proportional to increased stress on that part of the fracture. In this respect, increased stress on the granular conductor material improves contacts and decreases resistance. On the other hand, a loss of supporting rock matrix could create gaps in proppant 222 or 227, decreasing conductivity. Also, if the stress in the formation drops, resistance will increase even without actual gaps forming. As a result, the operator may choose to switch the delivery of electrical current to, for example, electrical lead 238c and, accordingly, through terminal 231c.
The control system 256 may simply be a junction box with manually operated switches. In this instance, the operator may take periodic measurements of resistance through the fracture 220 at various terminal locations. Alternatively, the control system 256 may be controlled through software, providing for automated monitoring. Thus, for example, if resistance (or average resistance) at one terminal increases over a designated period of time, the control system 256 may automatically switch to a different terminal. A new average resistance will then be measured and monitored.
A correlation exists between resistance and in situ temperatures. If data from the control system 256 indicates that hydrocarbon fluids are being generated at too high of a temperature, then the current path may be modified to shift energy away from that portion of the fracture 220. Similarly, if resistance measurements suggest that an electrical connection failure has occurred at a first terminal, this will indicate that inadequate heating is taking place. In either instance, the operator may switch the flow of current through a different terminal to obtain heating uniformity. Stated another way, changes in conductivity between different connections after power input is initiated can be used to modulate the power input to different portions of the fracture 220 to optimize performance.
The same process may take place within wellbore 240. Thus, electrical current may initially be received through terminal 241c to electrical lead 248c and up to line 255″ for a designated period of time. As solid hydrocarbons are pyrolyzed (or as heavy hydrocarbons are mobilized), a shift may take place in the second proppant 227, causing a break-up in electrical connectivity with the first proppant 222 near wellbore 240. The operator may then switch the delivery of electrical current from, for example, terminal 241a and, accordingly, through electrical lead 248a to terminal 241b and, accordingly, electrical lead 248b.
Preferably, the operator will eventually switch the flow of current through all terminals 231a-c, 241a-c. By switching the flow of current in this manner, it is believed that a more complete heating of the organic-rich rock formation 216 across the fracture 220 will take place.
Preferably, a portion of the casing strings 232, 242 is fabricated from a non-conductive material.
It is noted that the heater well arrangement 200 is described in terms of electric current flowing down wellbore 230, and back up wellbore 240. However, the polarities of the circuit may be switched in order to reverse the direction of current flow.
In the illustrative heater well arrangement 200 of
As an alternative to using the two-wellbore arrangement of
The heater well arrangement 300 is for the purpose of heating an organic-rich rock formation 316. This, in turn, facilitates the production of hydrocarbon fluids. Hydrocarbon fluids are produced to the surface through production wells, such as wells “P” shown in
In the arrangement of
In
A first electrically conductive proppant has been injected into the fracture 320. The first proppant (not shown) is placed in the fracture 320 by injecting a hydraulic fluid containing the proppant through the perforations along the wellbore 330. The hydraulic fluid is injected into the subsurface formation at a pressure that exceeds a formation parting pressure as is known in the art.
In addition, a second electrically conductive proppant has been injected into the wellbore 330. The second proppant (not shown) has been injected along a number of discrete zones 325 using, for example, a straddle packer (not shown). The second electrically conductive proppant partially displaces or overlaps the first electrically conductive proppant to form a plurality of zones 325.
In accordance with the methods herein, the first electrically conductive proppant (in fracture 320) has a first bulk resistivity. Similarly, the second electrically conductive proppant (in zones 325) has a second bulk resistivity. The second bulk resistivity is lower than the first bulk resistivity, meaning that the second electrically conductive proppant is more electrically conductive than the first electrically conductive proppant. This beneficially serves to prevent regions of excess heating, or “hot spots,” that might naturally occur in connection with the flow of electricity into and out of the fracture 320.
Electric current is passed down, and then back up, the wellbore 310 using electrically conductive leads (not shown). Current passes through a first selected zone 325, into the fracture 320, and back to the wellbore through a second selected zone 325. In this manner, the organic-rich rock formation 316 may be heated from the fracture 320 using electrically resistive heating.
Additional details of the heater well arrangement 300 are shown in the progressive views of
The wellbore 330 has been completed with a string of casing 332. The string of casing 332 defines a bore 335 through which fluids may be injected or equipment may be placed. The casing 332 is secured in place with a cement sheath 334. The cement sheath 334 resides within an annular region formed between the casing 332 and the surrounding near-surface formation 312. The cement sheath 334 isolates any aquifers or sensitive zones along the near-surface formation 312.
The wellbore 330 has been formed to have a deviated portion 340. In the arrangement 300, the deviated portion 340 is substantially horizontal. The deviated portion 340 includes a heel 342 and a toe 344. The wellbore 330 has been perforated along the deviated portion 340. Perforations are shown at 346.
Moving now to
In order to form the fracture 320, a hydraulic fluid laden with proppant 322 is injected through the perforations 346. The injection is at a pressure greater than the parting pressure of the subsurface formation 310. The proppant 322 comprises electrically conductive particles such as metal shavings, steel shot, calcined coke, graphite, or combinations thereof. The hydraulic fluid laden with proppant leaves a first electrically conductive proppant 322 within the fracture 320.
It can be seen in
It is preferred that a substantially non-conductive material also be placed within the wellbore 330 along the deviated portion 340 and between the distinct terminals. This insures the isolation of the zones of injection 325. The substantially non-conductive material may include, for example, mica, silica, quartz, cement chips, or combinations thereof.
Each lead 338 is preferably a copper or other metal wire protected within its own insulated cover. However, the leads 338 may alternatively be steel rods, pipes, bars or cables that are insulated down to the subsurface formation 310. In any embodiment, the leads 338 have a tip that is exposed to the second electrically conductive proppant 327. The tip may be fashioned as tip 233 in
In the heater well arrangement 300, each zone 325 represents a discrete terminal. Five illustrative zones 325 are shown, each defining a terminal that receives a respective lead 338. Individual leads 338 extend down to a selected terminal, such as terminals 231a, 231b, 231c of
In order to form an electrical circuit for the heater well arrangement 300, an electricity source 350 is provided at the surface 305. The electricity source 350 may be a local or regional power grid, or at least electrical lines connected to such a grid. Alternatively, the electricity source 350 may be a gas-powered turbine or combined cycle power plant located on-site. In any instance, electrical power is generated or otherwise received, and delivered via line 354 to a control system 356. En route, a transformer 352 may optionally be provided to step down (or step up) voltage as needed to accommodate the needs of the terminals defined by zones 325.
The control system 356 may simply be a junction box with manually operated switches. Alternatively, the control system 356 may be controlled through software or firmware. As with control system 256 of
Preferably, a portion of the casing string 332 is fabricated from a non-conductive material.
In operation, electrical current is distributed through the control system 356, through a first electrical lead 338, through the second electrically conductive proppant 327 at a first zone 325, into the fracture 320 in the organic-rich rock formation 316, through the second electrically conductive proppant 327 in a second zone 325, into a second electrical lead 338, and back up to the control system 356 to complete the circuit.
As noted, the first electrically conductive proppant (in fracture 320) has a first bulk resistivity. Similarly, the second electrically conductive proppant (in zones 325) has a second bulk resistivity. The second bulk resistivity is lower than the first bulk resistivity, meaning that the second electrically conductive proppant is more electrically conductive than the first electrically conductive proppant. In this way, heat is generated within the organic-rich rock formation 316 through resistive heat generated by the flow of current primarily through the first electrically conductive proppant 322.
The heater well arrangement 300 allows for piecemeal power control over the length of a fracture.
Other heater well arrangements may be employed for heating a subsurface formation in situ. For example, multiple wellbores (or multiple lateral boreholes from a single wellbore) may be formed through a fracture plane having a first electrically conductive proppant. A second electrically conductive proppant with corresponding electrical leads may then be placed in the multiple wellbores, providing electrical communication with the first electrically conductive proppant and a control system at the surface.
In the heater well arrangement 400 of
In operation, current is provided from an electrical source (not shown) at the surface 405. The electrical source may be in accordance with the electrical sources 250 or 350 described above. Electricity is carried down well 430 through a selected electrical lead (not shown), and down through one of the selected lateral boreholes 432, 434, 436. Current is then passed through the second proppant and into the fracture 420 through the first proppant. In this way, electrically resistive heating takes place within an organic-rich rock formation 416.
In order to complete the circuit, the current is passed through the second proppant associated with one of the lateral boreholes 442, 444, 446. Current then travels through an electrically conductive lead in well 440 and back up to the surface 405. The operator controls which zones 425 or terminals receive the current within boreholes 442, 444, 446
It is understood that in order to form the lateral boreholes 432, 434, 436, or 442, 444, 446, whipstocks (not shown) are suitably placed in the respective primary wells 430, 440. The whipstocks will have a concave face for directing a drill string and connected milling bit through a window to be formed in the casing. Preferably, the bottom lateral boreholes 436, 446 are formed first. Preferably, non-conductive casing is used in the deviated portions of the lateral boreholes 432, 434, 436, and 442, 444, 446.
In any of the above-described heater well arrangements 200, 300, 400, the heater wells may be placed in a pre-designated pattern. For example, heater wells may be placed in alternating rows with production wells. Alternatively, heater wells may surround one or more production wells. Flow and reservoir simulations may be employed to estimate temperatures and pathways for hydrocarbon fluids generated in situ as they migrate from their points of origin to production wells.
An array of heater wells is preferably arranged such that a distance between each heater well (or operative pairs of heater wells) is less than about 21 meters (70 feet). In alternative embodiments, the array of heater wells may be disposed such that a distance between each heater well (or operative pairs of heater wells) may be less than about 100 feet, or 50 feet, or 30 feet. Regardless of the arrangement or distance between the heater wells, in certain embodiments, a ratio of heater wells to production wells disposed within an organic-rich rock formation may be greater than about 5, 10, or more.
Based upon the illustrative wellbore arrangements 200, 300, 400 described above, methods of heating a subsurface formation using electrical resistance heating are provided herein. Such methods are described in certain embodiments below in connection with
First,
The method 500 first includes the step of placing a first electrically conductive proppant into a fracture. This is shown in Box 510 of
The first electrically conductive proppant is preferably comprised of metal shavings, graphite, steel shot, or calcined coke. The first electrically conductive proppant has a first bulk resistivity. To increase the resistivity, the first electrically conductive proppant may further comprise silica, ceramic, cement, or combinations thereof.
The method 500 also includes placing a second electrically conductive proppant partially into or adjacent the fracture. This is provided at Box 520. The second proppant is placed in contact with the first proppant.
The second electrically conductive proppant also is preferably comprised of metal shavings, steel shot, graphite, or calcined coke. The second proppant has a second bulk resistivity that is lower than the first bulk resistivity.
The method 500 further includes placing the second electrically conductive proppant in electrical communication with the first electrically conductive proppant. This is shown at Box 530. Electrical communication is provided at three or more terminals. In one embodiment, the second proppant is continuous, with the terminals simply being different locations along a wellbore. In another embodiment, the second proppant provides three or more discrete proppant portions along a single wellbore. In still another embodiment, the second proppant provides proppant portions within distinct wellbores or lateral boreholes that intersect the fracture.
The method 500 also comprises passing electric current through the second electrically conductive proppant at a first terminal. This is provided at Box 540. The current passes through the second electrically conductive proppant and through the first electrically conductive proppant. In this way, heat is generated within the at least one fracture by electrical resistivity.
It is understood that the current travels along a circuit, and that the current is received from an electrical source. The electrical source may be electricity obtained from a regional grid. Alternatively, electricity may be generated on-site through a gas turbine or a combined cycle power plant. The circuit will also include an insulated electrical cable, rod, or other device that delivers the current to the selected terminal.
After passing through the first electrically conductive proppant in the fracture, the current travels back to the electrical source at the surface. In returning to the surface, the current may travel back to the first wellbore and return through a separate electrically conductive lead. Alternatively, the current may travel through a separate wellbore to the surface.
The method 500 further includes monitoring resistance in the second electrically conductive proppant. This is seen at Box 550. Resistance is monitored at the first terminal while current passes through that location. In addition, resistance may be measured across multiple individual and combined terminals. This provides a measure of the connection of each terminal to the proppants in the fracture. It also provides an indication of the electrical continuity of the highly conductive second proppant with the less conductive first proppant. Further, such measurements may indicate differences in resistance of current flow in the first electrically conductive proppant. The results of these measurements may be the basis for deciding how to input power to the fracture. The measurements also provide a baseline for comparison with similar measurements taken after the initiation of heating.
The method 500 also includes switching the flow of electricity from the first terminal to a second terminal such that electric current is passed through the second electrically conductive proppant at the second terminal, and through the first electrically conductive proppant to further generate heat within the at least one fracture. This is shown at Box 560. The switching step is preferably based on an analysis of the resistance through the various terminals. The resistances measured across different paths can be combined to evaluate the homogeneity of the conductivity of the granular proppant within the fracture as the heating process progresses.
In one aspect of the method 500, the steps of passing electric current of Boxes 540 and 560 serve to heat the subsurface formation adjacent the at least one fracture to a temperature of at least 300° C. This is sufficient to mobilize heavy hydrocarbons such as bitumen in a tar sands development area. This also is sufficient to pyrolyze solid hydrocarbons into hydrocarbon fluids in a shale oil development area.
A separate method of heating a subsurface formation using electrical resistance heating is also provided herein.
The method 600 first includes the step of forming a first wellbore. This is provided at Box 610. The first wellbore penetrates an interval of organic-rich rock within the subsurface formation.
The method 600 also includes forming at least one fracture in the subsurface formation. This is seen at Box 620. The fracture is formed from the first wellbore and within the interval of organic-rich rock.
The method 600 also comprises placing a first electrically conductive proppant into the at least one fracture. This is indicated in Box 630. The first electrically conductive proppant is preferably comprised of metal shavings, steel shot, graphite, or calcined coke. The first electrically conductive proppant has a first bulk resistivity. To adjust the resistivity, the first electrically conductive proppant may further comprise silica, ceramic, cement, or combinations thereof.
The method 600 also includes placing a second electrically conductive proppant at least partially into the fracture. This is provided at Box 640. The second proppant is placed in contact with the first proppant.
The second electrically conductive proppant also is preferably comprised of metal shavings, steel shot, graphite, or calcined coke. The second proppant is tuned to have a second bulk resistivity that is lower than the first bulk resistivity. This permits electrical current to flow from the wellbore without creating undesirable hot spots. Preferably, the resistivity of the first electrically conductive proppant is about 10 to 100 times greater than the resistivity of the second electrically conductive proppant. In one aspect, the resistivity of the first electrically conductive proppant is about 0.005 to 1.0 Ohm-Meters.
The method 600 further includes placing the second electrically conductive proppant in electrical communication with the first electrically conductive proppant. This is shown at Box 650. Electrical communication is provided at three or more terminals. In one embodiment, the second proppant is continuous, and the terminals are simply different locations along the first wellbore, a second wellbore, or both. In another embodiment, the second proppant provides three or more discrete proppant portions along a single wellbore which is the first wellbore. In still another embodiment, the second proppant provides proppant portions within distinct wellbores or lateral boreholes that intersect the fracture.
The method 600 also comprises passing electric current through the second electrically conductive proppant at a first terminal. This is provided at Box 660. The current passes through the second electrically conductive proppant and through the first electrically conductive proppant. In this way, heat is generated within the at least one fracture by electrical resistivity.
It is again understood that the current travels along a circuit. Thus, an electrical source is provided at the surface. The electrical source is designed to generate or otherwise provide an electrical current to the first electrically conductive proppant located within the fracture. The electrical source may be electricity obtained from a regional grid. Alternatively, electricity may be generated on-site through a gas turbine or a combined cycle power plant.
After passing through the first electrically conductive proppant in the fracture, the current travels back to the electrical source at the surface. In returning to the surface, the current may travel back to the first wellbore and return through a separate electrically conductive lead. Alternatively, the current may travel through a separate wellbore to the surface.
The electrical connections in Boxes 720, 730, and 740 are preferably insulated copper wires or cables. However, they may alternatively be insulated rods, bars, or metal tubes. The only requirement is that they transmit electrical current as leads down to the interval to be heated, and that they are insulated from one another.
Referring back to the flow chart of
In one aspect of the method 600, the steps of Boxes 660 and 670 of passing electric current heat the subsurface formation adjacent the at least one fracture to a temperature of at least 300° C. This is sufficient to mobilize heavy hydrocarbons such as bitumen in a tar sands development area. This also is sufficient to pyrolyze solid hydrocarbons into hydrocarbon fluids in a shale oil development area.
The method 600 may also optionally include producing hydrocarbon fluids from the subsurface formation to the surface. Production takes place through dedicated production wellbores, or “producers,” separate from the wellbore or wellbores formed for heating.
As can be seen, various methods and systems are provided herein for heating an organic-rich rock within a subsurface formation. The methods and systems may be employed with a plurality of heater wells in a hydrocarbon development area, each of which operates with a planar heat source in such a manner that electrically conductive proppant is placed within a fracture from a wellbore. The methods and systems build on the previous “ElectroFrac™” procedures by employing multiple terminals with highly conductive proppant connections. The use of a highly conductive proppant at multiple locations mitigates the problem of point source heating associated with the transition for electrical source to the resistive proppant, and also allows the operator to measure resistance and change the flow of current through the proppant. Multiple connections also provide redundancy in the event that one of the connections fails due to strain of the rock hosting the proppant.
This application claims the priority benefit of U.S. Provisional Patent Application 61/555,940 filed Nov. 4, 2011 entitled MULTIPLE ELECTRICAL CONNECTIONS TO OPTIMIZE HEATING FOR IN SITU PYROLYSIS, the entirety of which is incorporated by reference herein.
| Number | Date | Country | |
|---|---|---|---|
| 61555940 | Nov 2011 | US |
