Method of Controlling Tensile-Splitting and Hydro-Shearing Parameters During Completion of Enhanced Geothermal System Wells
20250075593 ยท 2025-03-06
Inventors
- Michael Roy Chambers, Sr. (Lindale, TX, US)
- Timothy David Gray Hillesden Lines (Hayling Island, GB)
- Carl Bradley Pate (Fort Smith, AR, US)
- Robert Mansell Pearson (Calgary, CA)
- David Walter Edward Brown (Calgary, CA)
- David Lynn Copeland (Carrollton, TX, US)
Cpc classification
E21B43/305
FIXED CONSTRUCTIONS
F24T50/00
MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
E21B41/0035
FIXED CONSTRUCTIONS
E21B49/008
FIXED CONSTRUCTIONS
F24T2010/53
MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
E21B2200/22
FIXED CONSTRUCTIONS
F24T2010/56
MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
International classification
Abstract
Methods and systems for geothermal energy production wherein multiple horizontal or vertical wells may be used to pass fluids through the Earth from an injector well to a producer well through induced cracks, splits, fractures, conduits, or channels in the rock. Such methods and systems may include controlling tensile-split conduits in a subterranean geothermal formation by providing an injection well, providing a production well, configuring the injection well for injection of a tensile-splitting fluid into a production zone, configuring the production well to produce a heated fluid from the production zone, applying pressure to the production well, creating a plurality of tensile-split conduits, raising or lowering the pressure in the production well, establishing fluid communication between the injection well and the production well, and producing the heated fluid to the surface.
Claims
1. A method of drilling naturally fractured geothermal reservoirs, comprising: drilling a vertical pilot well in a formation comprising a geothermal heat reservoir; obtaining data on the properties of the formation, wherein the properties are derived from core or electric logs, wherein the data comprises temperature data on the formation; determining the direction and depth of a potential horizontal lateral; determining the orientations of fractures in the formation; drilling a managed pressure horizontal lateral until one of the fractures is encountered; modifying drilling operations for the managed pressure horizontal lateral employing under balanced drilling; running one or more cementing sleeves and one or more flow-control sleeves into the managed pressure horizontal lateral; isolating a rock interval with cement; stimulating one or more conduits using the DCM method; employing a closed-loop circulation method; and producing from the vertical pilot well.
2. The method of claim 1, wherein the step of modifying drilling operations for the managed pressure horizontal lateral employs managed pressure drilling.
3. The method of claim 1, wherein the step of modifying drilling operations for the managed pressure horizontal lateral employs blind drilling.
4. The method of claim 1, wherein the step of stimulating one or more conduits employs the FEN method.
5. The method of claim 1, wherein the step of obtaining data employs cooled, standard MWD tools until the relevant temperatures of the formation exceed the operating limits of the standard MWD tools.
6. The method of claim 5, wherein a slick line deployed system is employed as a backup if the relevant temperatures of the formation cannot be reduced.
7. The method of claim 1 further comprising employing a new intermediate casing to install a stage collar in a section of the vertical pilot well.
8. The method of claim 7 further comprising circulating cooling fluid into an annulus of the vertical pilot well.
9. The method of claim 1 further comprising conducting selective cementing operations in the horizontal lateral.
Description
BRIEF DESCRIPTION OF THE DRAWINGS
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DETAILED DESCRIPTION
1. Introduction
[0181] A detailed description will now be provided. The purpose of this detailed description, which includes the drawings, is to satisfy the statutory requirements of 35 U.S.C. 112. For example, the detailed description includes a description of the inventions defined by the claims and sufficient information that would enable a person having ordinary skill in the art to make and use the inventions. In the figures, like elements are generally indicated by like reference numerals regardless of the view or figure in which the elements appear. The figures are intended to assist with the description and to provide a visual representation of certain aspects of the subject matter described herein. The figures are not all necessarily drawn to scale, nor do they show all the structural details of the systems, nor do they limit the scope of the claims.
[0182] Each of the appended claims defines a separate invention which, for infringement purposes, is recognized as including equivalents of the various elements or limitations specified in the claims. Depending on the context, all references below to the invention may in some cases refer to certain specific embodiments only. In other cases, it will be recognized that references to the invention will refer to the subject matter recited in one or more, but not necessarily all, the claims. Each of the inventions will now be described in greater detail below, including specific embodiments, versions, and examples, but the inventions are not limited to these specific embodiments, versions, or examples, which are included to enable a person having ordinary skill in the art to make and use the inventions when the information in this patent is combined with available information and technology. Various terms used herein are defined below, and the definitions should be adopted when construing the claims that include those terms, except to the extent a different meaning is given within the specification or in express representations to the Patent and Trademark Office (PTO). To the extent a term used in a claim is not defined below or in representations to the PTO, it should be given the broadest definition persons having skill in the art have given that term as reflected in any printed publication, dictionary, or issued patent.
[0183] The embodiments disclosed herein disclose novel approaches to extracting geothermal heat and/or minerals from deep beneath the Earth's surface. For example, in embodiments tensile-splitting or hydro-shearing the rock between an injector well and one or more producer wells may occur simultaneously in order to connect these wells to one another with flow conduits. In other embodiments involving an injector well and a plurality of producer wells, the flow conduits being created may be steered in specific directions towards specific wells. Additionally, in other embodiments an injector well and a producer well may have multiple conduits, and control over the flow of fluids through each conduit may be controlled independently of the other conduits. Plus, in embodiments tensile-splitting and hydro-shearing to establish flow conduits between an injector well and one or more producer wells may be accomplished in granites and other crystalline and volcanic rocks, metamorphic rocks, naturally and artificially cemented solid materials, and sedimentary rocks and shales. These are merely some of the unique aspects of the embodiments disclosed herein. Further, the embodiments disclosed herein substantially decrease the risk and cost of extracting heat and/or minerals from impermeable or low-permeability rock that needs to be tensile-split or hydro-sheared to enable extraction fluids to be circulated through it. In embodiments, this may be achieved by precisely controlling the geomechanical stress between injector and producer wells and thus enabling the reliable creation of flow conduits of known and pre-determined dimensions between them.
[0184] Additionally, other embodiments disclosed herein disclose novel approaches to determining the orientation of shear-stress induced tensile-splitting or other types of tensile-splitting or of hydro-shearing to create conduits within the rock deep beneath the Earth's surface. For example, in embodiments tensile-splitting the rock from a vertical well to intersect a near-horizontal uncemented lateral is proposed. Methods to determine the intersection point along the lateral by the conduit created from the vertical well using temperature, gamma ray detection, velocity, acoustics, etc. are contemplated. Such temperature sensing methods include optical fibers deployed along the length of the lateral or traditional temperature, gamma ray, and other logging tools deployed by pumping down on wire and wire line retrieval. Tractors, coiled tubing, or other means of insertion and retrieval are also contemplated.
2. Certain Specific Embodiments
[0185] Now, certain specific embodiments are described, which are by no means an exclusive description of the inventions. Other specific embodiments, including those referenced in the drawings, are encompassed by this application and any patent that issues therefrom.
[0186] One or more specific embodiments disclosed herein includes a method of controlling tensile-split conduits in a subterranean geothermal formation, comprising the following steps: providing an injection well extending from a surface to a subterranean geothermal formation, wherein the injection well comprises a plurality of cemented casing sleeves, wherein each of the plurality of cemented casing sleeves is capable of being opened, closed, or choked; providing a production well extending from the surface to the subterranean geothermal formation, wherein the production well comprises an uncemented liner, wherein the uncemented liner comprises a slotted/predrilled liner; configuring the injection well for injection of a tensile-splitting fluid into a production zone, wherein the production zone is defined within the subterranean geothermal formation, and further wherein the production zone requires tensile-splitting to enhance fluid conductivity; configuring the production well to produce a heated fluid from the production zone; applying pressure to the production well at a pressure below the tensile-splitting initiation point, wherein the shear stress is increased in the maximum horizontal stress direction and a tensile-splitting conduit is encouraged to intersect the production well; creating a plurality of tensile-split conduits by injecting the tensile-splitting fluid into the production zone of the injection well, and further wherein each of the plurality of tensile-split conduits intersects the production well; raising or lowering the pressure in the production well in response to acquired real-time data during the tensile-splitting operation, wherein the raising or lowering of the pressure in the production well facilitates changing the height, width, and/or length parameters of the induced plurality of tensile-splitting conduits, and further wherein the pressure is raised in the production well by pumping a pressure fluid into the production well while simultaneously pumping the pressure fluid into the injection well, and further wherein the pressure is lowered in the production well by lowering the hydrostatic level by employing a pump, jetting, or flowing, and further wherein the real-time data comprises pressure, temperature, seismic information, or a combination thereof, wherein the real-time data is input into a computer equipped with artificial intelligence; establishing fluid communication between the injection well and the production well by imposing a hydraulic pressure above the hydro-shear pressure and below the tensile-splitting pressure on the plurality of tensile-split conduits, wherein the plurality of tensile-split conduits are maintained in an open condition, in order to extract heat by circulating a supercritical carbon dioxide between the injection well and the production well; and producing the heated fluid to the surface, wherein the heated fluid is employed as direct heat, for electricity generation, or for creating energy carrier fluids.
[0187] In any one of the methods or systems described herein, each of the plurality of tensile-split conduits may be created simultaneously.
[0188] In any one of the methods or systems described herein, fluid communication between the injection well and the production well may be improved by employing a mined or man-made proppant.
[0189] In any one of the methods or systems described herein, operations may be halted and pressures bled when the mined or man-made proppant is detected in the production well.
[0190] In any one of the methods or systems described herein, the production well may comprise a tubular string.
[0191] In any one of the methods or systems described herein, the method may further comprise circulating a circulating fluid, wherein the circulating fluid removes the mined or man-made proppant.
[0192] In any one of the methods or systems described herein, fluid communication between the injection well and the production well may be improved by employing an expandable electrophilic acid-gas-reactive fracturing and recovery fluid.
[0193] In any one of the methods or systems described herein, a mechanical device may be employed in the production well, wherein a rock near the production well is weakened in the direction of the injection well.
[0194] In any one of the methods or systems described herein, the step of establishing fluid communication between the production well and the injection well may employ a cooled fluid, wherein the cooled fluid causes the subterranean geological formation to fracture from the thermal shock effect.
[0195] In any one of the methods or systems described herein, the method may further comprise creating an energy storage reservoir by injecting an injection fluid to increase the pressure of the plurality of tensile-splitting conduits, wherein the depressurizing of the injection fluid provides energy to generate electricity or to distribute direct heat.
[0196] In any one of the methods or systems described herein, an artificial intelligence system may be utilized to optimize the well layout, stimulation, rate of heat extraction, heat exchanger selection and design, power generation equipment selection and design to economically optimize heat extraction from the reservoir.
[0197] In any one of the methods or systems described herein, perforations may be employed within the injection well as an alternative to the plurality of cemented casing sleeves.
[0198] One or more specific embodiments disclosed herein includes a method of determining the orientation of shear-stress induced tensile-split conduits, and conduits induced or reactivated by other means, in a subterranean geothermal formation, comprising the following steps: providing a vertical well extending from a surface to a subterranean geothermal formation, wherein the injection well comprises a cemented casing penetrating a geothermal formation; providing a production well extending from the surface to the subterranean geothermal formation, wherein the production well comprises an uncemented tubular (like drill pipe, tubing, or casing), configured to circulate fluid from the surface to the toe of the lateral and returned to surface, wherein the production zone is defined within the subterranean geothermal formation, and further wherein the production zone requires shear-stress induced tensile-splitting to enhance fluid conductivity, or conduits induced or activated by other means,, perforating the vertical well casing at the same subsurface depth (below sea level) as the horizontal lateral (or by installing an openable frac sleeve at the depth), deploying a tubular system in the wellbore in which a temperature sensitive fiber can be installed into (or acoustic fiber or strain fiber or any combination of the three) the horizontal lateral from the surface to the toe of the well by pumping a reel containing the fiber at 1-2 barrels/minute (BPM), the fiber is connected to an optical process unit (like a DTS), creating a shear-stress induced tensile-split conduit using fluid pumped at high pressures through the perforations (or frac sleeve) in the vertical well and further wherein each of the shear-stress induced tensile-split conduits intersects the production well, evaluating the induced change in the fiber properties along the production well to determine the intersection point, calculating the distance of the conduit and calculating the orientation between the vertical well and the intersection point, continuing to pump tensile-splitting fluid in the injection well and producing the fluid in the production well at surface to determine the fracture properties.
[0199] In any one of the methods or systems described herein, the fiber may be substituted with conventional wireline-deployed real-time temperature, gamma ray, noise, collar locators, flow meters, etc. data-collection instruments that can be used after intersection of the conduit from the vertical well has been detected, and could be slowly retrieved from the toe of the horizontal wellbore to determine the intersection point.
[0200] In any one of the methods or system described herein, the fiber may be attached on the outside of the drill pipe or the inside of coiled tubing. To cool the tools, surface fluids can be circulated while running the drill pipe in the hole. Likewise, placement of the fiber can be installed in the horizontal well after the intersection connection between the vertical and horizontal wells has been detected. This will allow lower temperature rated tools to be used in reservoirs with higher temperatures than they are rated for.
[0201] In any one of the methods or systems described herein, the real-time downhole data collection instruments may be substituted for memory-battery-operated tools that can be used after the intersection of the conduit from the vertical well has been detected, and could be slowly retrieved from the toe of the horizontal wellbore to determine the intersection point.
[0202] In any one of the methods or systems described herein, the data recording instruments could be run singularly or in tandem with one another.
[0203] In any one of the methods or systems described herein, the long-term fluid communication and conductivity between the injection well and the production well may be improved by placing a mined or man-made proppant in the conduit.
[0204] In any one of the methods or systems described herein, the tensile-stress stimulation fluid temperature could be measured after intersection to gather additional data on the thermal heat recovery from the system.
[0205] In any one of the methods or systems described herein, an in-situ natural fracture conduit intersecting both the vertical wellbore and horizontal lateral, could be substituted for the shear-stress induced tensile-split conduit and the orientation and dimensions of the natural conduit could be determined using the same methods.
[0206] In any one of the methods or systems described herein, radioactive or non-radioactive materials could be inserted during the tensile-stress splitting process and recorded at the horizontal lateral using a gamma ray tool.
[0207] In any one of the methods or system described herein, the horizontal lateral may be drilled in a pattern like arc to improve the chance of the shear-stress induced tensile-split conduit intersecting the lateral.
[0208] In any one of the methods or systems described herein, artificial intelligence could be used from the data gathered to utilized to optimize the well layout, stimulation processes and parameters, rate of heat extraction, heat exchanger selection and design, power generation equipment selection and design to economically optimize heat extraction from the reservoir.
[0209] In any one of the methods or systems described herein, a casing sleeve containing a choke position could be substituted for perforations in the vertical well to evaluate the ability to regulate flow.
[0210] In any one of the methods or systems described herein, the lateral section of the horizontal well may be used to locate two or more shear-stress induced tensile-split conduits generated from two or more vertical wells.
[0211] In any one of the methods or systems described herein, a shear-stress induced tensile-split conduit may have originated from the lateral of a horizontal well.
3. Specific Embodiments in the Figures
[0212] The drawings presented herein are for illustrative purposes only and are not intended to limit the scope of the claims. Rather, the drawings are intended to help enable one having ordinary skill in the art to make and use the claimed inventions.
[0213] In the drawings and descriptions that follow, like parts are typically marked throughout the specification and drawings with the same reference numerals. The drawn figures are not necessarily to scale. Certain features of the embodiments may be presented exaggerated in scale or in somewhat schematic form, and some details of conventional elements may be excluded in the interest of clarity and conciseness. The present invention may be implemented in embodiments of different forms. Specific embodiments are described in detail and are shown in the drawings, with the understanding that the present disclosure is to be considered an exemplification of the principles of the invention, and is not intended to limit the invention to that illustrated and described herein. It is to be fully recognized that the different teachings of the embodiments discussed herein may be employed separately or in any suitable combination to produce desired results.
[0214] Unless otherwise specified, use of the terms connect, engage, couple, attach, or any other like term describing an interaction between elements is not meant to limit the interaction to direct interaction between these elements and may also include indirect interaction between these elements.
[0215] Unless otherwise specified, use of the terms up, upper, upward, uphole, upstream, or other like terms shall be construed as generally toward the surface of the formation and of shallower depth below exposed earth. Likewise, use of the terms down, lower, downward, downhole, or other like terms shall be construed as generally toward the bottom, terminal end of a well, regardless of the well orientation. Use of any one or more of the foregoing terms shall not be construed as denoting positions along a perfectly vertical axis.
[0216] Unless otherwise specified, use of the term subterranean formation shall be construed as encompassing both areas below exposed earth and areas below earth covered by water such as ocean or fresh water.
[0217] Unless otherwise specified, use of the terms tensile-splitting, hydro-shearing, soft hydraulic simulation, hydraulic fracturing, and conduit creation refer to cracking, splitting, opening, or reopening the rock and extending the created crack in three dimensions. Whereas tensile-splitting typically refers to the initial splitting of the rock and hydro-shearing typically refers to reopening and or extending existing fissures or fractures or splits in the rock.
[0218] Unless otherwise specified, use of the terms conduit, created conduits, flow channel, and crack refer to the void in the rock between the rock's faces.
[0219] Unless otherwise specified, the heel is the start of the horizontal (or inclined) production/injection interval, and the toe is the far end of it.
[0220] Unless otherwise specified, the terms producer, producer well, production well, and production wellbore are used synonymously in this patent. Further, unless otherwise specified, the terms injector, injector well, injection well, and injection wellbore are used synonymously in this patent.
[0221] Unless otherwise specified, the term casing is a steel tubing of a particular diameter that is inserted into a well to, e.g., shore up the hole and/or to isolate a particular rock interval. The casing may be cemented to the rock and/or to a larger casing through which it has been inserted, or a void may be left between them. Unless otherwise specified, the term liner is a casing that does not extend back to the surface.
[0222] Tensile-splitting a deep hot impermeable formation to create new conduits between wells to flow fluids and capture heat is relatively new. The fracturing of shales and hydrocarbon reservoirs is fairly well understood, but with the emphasis of stimulating production in the well whilst avoiding frac hits with other wells at all costs.
[0223] However, for geothermal applications it is most desirable for flow channels to connect wells. To achieve the optimum flow connection between wells, the tensile-splitting parameters must be controlled in both the well where fluid is being injected and any other wells where there is a desire for the conduit to intersect and/or to establish fluid communication with. Further, to achieve the optimum flow connection between wells, the orientation of the tensile-splitting conduit is critical to the ability to connect in formations like granite. Likewise, it is desirable to understand the flow capacity of created conduits and the amount of heat they can extract from the reservoir.
[0224] It has long been understood what controls the parameters of height, width, and length in tensile-split and hydro-sheared channels and conduits. Part of the tool kit to change these parameters is the type of stimulation fluid and its characteristics such as its viscosity, density, flow rate and compressibility. Likewise, how pressure applied to rock affects and changes a rock's maximum and minimum stresses is well understood.
[0225] In EGS methods, the (near)-parallel horizontal wells may be from 50 feet apart to more than 1,000 feet apart, with the wider separation accessing a larger area from which to draw heat. However, depending on rock stress in granite type formations, wing lengths (i.e., the length of a conduit created from one well towards another) of greater than 350 feet may be difficult to reliably obtain using current technology, but the disclosure herein foresees no absolute upper limit to that distance.
[0226] The wells may be vertical or inclined rather than horizontal. The lengths of the production (or injection) intervals through which fluids flow to/from the rock range from 50 feet to more than 15,000 feet, with 3,000 feet to 5,000 feet commonplace.
[0227] Injectors and producers are typically nearly parallel, but it is not required to maintain an exact distance between them, and deviations of over 50 feet do not materially affect calculated performance. Furthermore, deviations from parallel are sometimes intended to help stabilize the flood front of water advancing through the many conduits from the injector(s) to the producer(s) as explained below.
[0228] Tensile-splitting and hydro-shearing conduits may have heights of many hundreds, or even thousands of feet, and this allows latitude in the well placements.
[0229] In the production/injection interval, casing diameters of 4 inch to 9 inch are typical, but larger sizes are possible. Selection of casing size is influenced by balancing the higher cost of larger sizes against the lower friction of the circulating fluid at the flowrate required to recover the desired thermal power. For example, in reservoirs at 350 F. it may be desirable to have 5 or 7 casing sizes to reduce circulation friction when pumping 20 barrels per minute (BPM-a barrel is 42 U.S. gallons or 5.615 cubic feet) between wells 5,000 feet long and 350 feet apart containing 20 to 100 tensile-split conduits to recover enough heat to generate 5 MW.sub.e of net electrical power.
[0230] It is desirable to equalize the fluid flow injected into each tensile-split-enhanced and hydro-shear-enhanced conduit from the injector to create a stable flood front moving toward the producer(s). This reduces the bypassing of areas of hot rock. The challenge increases with the length of the injection interval and the number of conduits. At high circulation rates the pressure at the heel of the well will be materially higher than at the toe and will therefore force more fluid to enter the conduits near the heel than the toe. Sleeves, like those made by NCS Multistage, may be open, closed, or choked. These types of sleeves facilitate the initial creation of multiple conduits and then permit the conduits to be closed or choked to maintain a stable flood front. A supporting technique is to deviate the injector and producer(s) from parallel so that the toes of the two wells are nearer than the heels. This helps control the stability of the flood front since the injection pressure decreases through flow friction from heel to toe and the production pressure reduces through flow friction from toe to heel.
[0231] Stimulation fluids may be recovered from the producer and reused, resulting in less use of chemicals and water.
[0232] Knowledge of how to effect rock stresses during stimulation operation in wells is discussed in U.S. Pat. No. 10,801,307, but those efforts have been focused on how to space conduits so they will not come in contact, and only with operations performed in one well at a time rather than simultaneously.
[0233] Computer-generated heat models may be used (e.g., TOUGH2, DARTS, Waiwera, GeoDT, ResFrac and Geophires) to calculate the optimum lateral lengths, distances apart, flow conduits, and circulation rates for a specific geologic temperature and thermal heat capacity of the formation.
[0234] The embodiments disclosed herein relate to developing conventional oil field fracturing and tensile-splitting methods further, thereby providing a method to optimize the placement of the tensile-split and hydro-sheared conduits to ensure contact and communication with another well and a conduit with sufficient permeability (permeability is a measure of the ability of fluids to flow through rocks and conduits) to circulate fluids without undue friction losses.
[0235] Knowing if and when the tensile-split-created conduits come into contact with the target well allows optimization of the stimulation treatment. Chemicals and proppants used in the treatment, as well as equipment hire, are expensive. Knowing when to stop the treatment is a major contributor to optimizing its cost-effectiveness.
[0236] Placement of the tensile-split conduit can be optimized by coupling the actions undertaken in the injector and in the producer, as well as leveraging the sensory information collected from the wells.
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[0238] Generally, a formation is a rock unit that is distinctive enough in appearance that a geologic mapper can tell it apart from the surrounding rock layers. Sedimentary rock formations typically have significantly higher permeability than igneous and metamorphic rocks. Permeability in igneous and metamorphic formations is generally through fractures. Depths of formations may range from a surface 115 increasing to a depth very much greater than 16,000 feet below the surface 115.
[0239] As shown in
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[0241] In embodiments, the graphical representations are presented to explain the enhanced geothermal, potential well configurations, and completion methods. In embodiments, well 210 may comprise a producer well, and well 215 may comprise an injector well. In other embodiments, well 210 may comprise an injector well, and well 215 may comprise a producer well. In embodiments, wells 210 and 215 may have parallel horizontal laterals 230 and 235, respectfully. In other embodiments, such wells may have non-parallel horizontal laterals. In the embodiment of
[0242] In embodiments, heat reservoir 245 may convey the DCM completion process. In embodiments, well 210 may be intended to be an injector well and have tensile-split conduits 250 and 255 emanating at lateral 230 and growing to intersect lateral 235, which may be intended to be a producer well. In
[0243] In another alternative embodiment, heat reservoir 240, noted in the cross-hatched lines, describes the FEN completion process. In embodiments, well 210 may comprise an injector well and comprise tensile-split conduits 260 and 265 emanating from lateral 230. In embodiments, tensile-split conduits 260 and 265 may or may not intersect lateral 235. In embodiments, well 215 may comprise a producer well and also be either open hole (bare foot) or be cased and cemented and have tensile-split conduits 270 and 275 emanating from lateral 235. Similarly, in embodiments, open hole methods using packers and sleeves may be employed. In embodiments, the tensile-split conduits 270 and 275 may or may not intersect lateral 230. In embodiments, hydro-shearing of in-situ micro cracks in the rock comprising granite formation 225 may also enable communication between the tensile-split conduits 270 and 260, as well as between the conduits 275 and 265.
[0244] In embodiments, in either the DCM (depicted in heat reservoir 240) or FEN (depicted in heat reservoir 245) process completion described above, a pumping facility 280 and a generator facility 285 would not be limited to only two wells 210 and 215. In embodiments, a plurality of wells may be employed, wherein the plurality of wells may be horizontal, vertical, deviated or a combination thereof. While the operating environment depicted in
[0245] Stresses of varying magnitudes and orientations may be present within a geothermal-heat-containing subterranean formation. Although the stresses present may be complex and numerous, they may be effectively simplified to three principal stresses.
[0246] As shown in
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[0248] In embodiments, it may be assumed that the stress acting along the z-axis is approximately equal to the weight of the formation above (e.g., toward the surface) a given location in the subterranean granite formation 225. With respect to the stresses acting along the horizontal axes, cumulatively referred to as the horizontal stress field, for example in
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[0250] Referring to
[0251] In embodiments, wells used to extract heat from subterranean formations may be vertical, deviated, horizontal, or a combination of these.
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[0257] In embodiments, geothermal well completions may target granite and other impermeable formations, which are extremely robust, may act like casing, and will not collapse.
[0258] In embodiments,
[0259] Further, in
[0260] Disclosed herein are one or more methods, systems, and/or apparatuses suitably employed for enhancing tensile-splitting (or hydro-shear) conduit parameters in a subterranean formation. As used herein, reference to enhancing tensile-splitting (or hydro-shear) conductivity may include the modification of a conduit's length, width, height, and/or flow conductivity. Further disclosed is the interaction of the tensile-split (or hydro-shear) conduit by affecting the formation stress properties from two or more different wells with laterals suitably placed in the same plane of orientation. Returning to
TABLE-US-00003 TABLE 1 Injector 380-Lateral 400 Producer 385-Lateral 405 Gauge Gauge 420 Pump 425 Flow Reading Rate Reading Rate Step Procedure FIG. Item (psi) (BPM) Procedure FIG. Item (psi) (BPM) 1 Breakdown 6A 415 7500 5 Monitor 6A 405 5000 0 Formation Pressure* 2 Pump Pad 6A 410 8500 25 Monitor 6A 405 5000 0 Pressure* 3 Pump Pad 6B 430 8500 25 Pressure 6B 435 6200 0 Contact 4 Pump 6B 430 8000 25 Monitor 6B 435 7000 4 Proppant Fluid 5 Stop 6B 430 6500 0 Proppant 6B 435 6500 0 Pumping Noted 6 Observe 6B 420 6200 0 Bleed to 6B 435 6200 1 Pressure Closure Pressure 7 Injectivity 6B 420 3000 2 Flow Well 6B 435 2800 2 Test
[0261] In embodiments, in step 1 the formation may be broken down and the conduit initiated in injector lateral 400, while simultaneously pressuring producer lateral 405 adjacent to the created conduit 410 in injector lateral 400 to slightly below tensile-splitting pressure.
[0262] In embodiments, in step 2, pad (stimulation fluid without a means to prop or hold open the fracture without pressure) may be pumped into conduit 410 while monitoring the pressure in lateral 405. In embodiments, this process may be continued until pressure significantly changes in lateral 405 indicating the conduit 430 has intersected lateral 405 at point 435, as shown in
[0263] In embodiments, in step 4 proppant may be pumped into injector lateral 400 and monitored in producer lateral 405 by circulating fluid to surface or through downhole sensors. This can be seen in step 4 where the flow rate in lateral 405 has increased from 0 BPM to 4 BPM. The corresponding pressure has also increased from 6,200 psi to 7,000 psi.
[0264] In embodiments, in step 5 proppant may be detected in sufficient quantities in producer lateral 405 and pumping may be stopped. This can be seen where the pump rate and flow rate are both 0 BPM and the pressures are the same 6,500 psi.
[0265] In embodiments, in step 6, while observing the pressure in injector lateral 400, the pressure may be reduced or bled off in producer lateral 405 until closure of the tensile-split wall aperture onto the proppant has occurred. In embodiments, if there is no need to evaluate the aperture closure, operations may be concluded. This can be seen in both laterals 400 and 405 where the pressures had decreased to 6,200 psi while flowing lateral 405 at 1 BPM.
[0266] However, in embodiments where there may be a desire to test the conduits' permeability and communication to ensure sufficient pump rates can be achieved at desired pressures, operations may proceed to step 7 wherein an injection rate may be established in injector lateral 400, and the flow rate in producer lateral 405 may be choked to match the injection rate for injector lateral 400 to establish the circulation rate and pressure in both laterals 400 and 405. This can be seen where the pump rates are identical and pressures are different due to friction losses in the reservoir.
[0267] In embodiments, if pressure increases in the injector lateral 400 and then reaches a plateau, the rate may be acceptable, and operations may cease and proceed to step 8 where operations may move to the next tensile-splitting location. However, in embodiments, if pressure in injector lateral 400 continues to rise, a decision may be made to either retreat and restart at step 2 or accept the lower permeability and communication.
[0268]
[0269] In embodiments, step 1 may comprise the formation being tensile-split using water or gel to initiate conduit 560 in lateral 400, while simultaneously monitoring the pressure of lateral 405 in well 385 at a location normal to the created conduit 560 in well 380. This can be seen in the following Table 2 where the pressure and rate in well 380 is higher than that in well 385. In embodiments, an operator may start stimulation at the toe of well 380, which may be an injector well, through sleeve or perforations (pumping gel or fresh water).
TABLE-US-00004 TABLE 2 Well 380-Injector Well 385-Producer Surface Gauge Pump/Flow Rate Surface Gauge Pump/Flow Step Press (psi) (BPM) Press (psi) Rate (BPM) 1 7500 20 6000 0 2 6500 0 6000 0 3 6000 0 7500 20 4 6000 0 6000 0 5 8500 25 6500 0 6 6500 0 8500 25 7 7000 0 8500 25 8 2000 0 2000 0 9 2500 2 2300 2 10 0 0 0 0 Formation Parting Pressure = 6,200 psi
[0270] In embodiments, in step 2 after pumping and creating conduit 560 of approximately 50 feet emanating from lateral section 400, the rate may be stopped and the pressure held at above fracture closure stress. In alternative embodiments, the pressure after stopping pumping in well 380 may be bled to below fracture closure pressure. This can be seen in Table 2 where both well 380 and well 385 show 0 rate but the pressure is higher in well 380 than well 385.
[0271] In embodiments, in step 3 pressure may be bled to a level slightly below the fracture initiation pressure in well 380 while simultaneously tensile-splitting lateral section 405 in well 385 using water or gel at a point along the lateral section 405 within 20 feet of well 380, lateral section 400's most recent tensile-splitting. In embodiments, stimulation may be started at the toe of well 385, which may be a producer well. This can be seen in Table 2 where the pump rate in well 385 is 20 BPM. In embodiments, pumping may be continued in well 385 until a pressure increase is noted in well 380 or, in an alternative embodiment, until after the conduit 560 has extended approximately 50 feet from the initiation point in well 385 and the pumping ceased.
[0272] In embodiments, in step 4 pressure is monitored in well 380 while creation of conduit 565 is underway in well 385. This is shown in Table 2 where contact has been made because the pressure in well 380 increased from 6,000 psi to 6,500 psi.
[0273] In embodiments, in step 5 the proppant material may then be pumped into well 380 until significant pressure is noted in well 385 or proppant is recovered. This can be seen in Table 2 where the pressure in well 385 is 6,500 psi and well 385 is producing fluid to surface as noted by the negative 5 BPM rate.
[0274] In embodiments, in steps 6, 7, and 8, if contact has not been made in well 385 by pumping in well 380, a designed tensile-splitting may be emanated from well 385 while monitoring pressure in well 380. Pumping is continued until contact is made. At the conclusion of pumping the pressure is bled down to approximately 2,000 psi which would be a pressure below fracture closure pressure.
[0275] In embodiments, once the tensile-splitting operation has been completed, an injectivity test may be performed in step 9 by pumping into well 380 with water at the desired rate and recovering fluid from well 385. This can be seen from Table 2 where well 380 has an injection rate of 2 BPM and well 385 has a negative 2 BPM flowrate (i.e. producing to surface). The difference in pressure is attributable to the reservoir friction pressure. In embodiments, if an acceptable rate and pressure for producing operations has been achieved for that conduit, the process is complete. If not, the process may be repeated from step 1. If there were 20 planned flow conduits between well 380 and well 385, then an acceptable rate for a single conduit would be 1/20.sup.th of the designed rate. For example, if the design rate were 20 barrels per minute (bpm) at a pressure of 3,000 psi, then an acceptable rate for one conduit would be 1 bpm at a pressure less than 3,000 psi to account for flow friction along the lateral section. Additional flow conduits can next be created further towards the heel of the lateral sections by moving to step 1, for example, conduit 562 in
[0276] In embodiments, if treating more than one pair of wells at a time, then the methods described in relation to
[0277]
[0278] In embodiments, a second optional method may involve the following. In embodiments, after pressure communication has been determined between the injector 570 and producer 575, proppant or swelling material may be introduced to the injector 570. Further, in embodiments, simultaneously proppant may be monitored in the producer 575. In embodiments, if pressure increases in the injector 570 or additional proppant quantities are desired, pressure may be raised in the producer 575 to increase the conduit aperture width. If, however, proppant is being recovered in the producer 575 and there is a desire to pack the conduit further with proppant, pressure may be reduced, and the aperture and height will decrease.
[0279] In embodiments, a third optional method may involve the following. In embodiments, if after concluding the conduit creation, injectivity is below desired rates, the conduit may be reopened, and additional proppant or swell material may be inserted. In embodiments, rates and pressures higher than the original pump treatment may be required and/or changes to the fluid viscosity may be attempted. Simultaneously, pressures in one or more producers 575 may be raised or lowered depending on the expected outcome.
[0280] In embodiments, monitoring and recording downhole pressure, temperature, seismic, temperature, and other data may enable the optimum placement of a conductive conduit between injector 570 and producer 575, or multiple injectors 570 and producers 575, to be achieved. In embodiments, this monitoring may be used for every newly constructed conduit or only used until the parameters to create the conduit are fully understood.
[0281]
[0282] Micro Seismic is another common means used in the industry to track the creation of conduits. Typically, these types of systems are installed in adjoining wells to collect the data. As described earlier, there are two primary means to execute communication between an injector and a producer or group of injectors and producers. Many of the descriptions described above involved the DCM where fluid may be pumped from a cemented injector well to an uncemented producer well. However, at least as prevalent is the FEM, where both injector and producer wells are cemented, and both have created conduits extending towards one another. The attempt is to have the created conduits intersect or form additional branches or splays, which intersect or contact perpendicular natural fractures which will act as connection points with the bulk formation.
[0283]
[0284] In another embodiment shown in
[0285] In embodiments, the ability of the tensile-split conduits 410 and 615 to intersect may be enhanced with one or more of the following actions: [0286] start tensile-splitting both conduits 410 and 615 at the same time or start one conduit later than the other conduit; [0287] pump much higher rate and pressure in one conduit versus the other conduit; [0288] stop or reduce pumping in one well when intersection is noted in the other well; [0289] pump diverter material in one of the two wells to encourage the generation of branches or splay conduits off the primary conduit; [0290] pump proppant in one well while bleeding pressure in the other well; [0291] change the viscosity of the fluid in one conduit versus the fluid in the other conduit with for example cross-linking one, and pumping swellable material in one conduit while pumping conventional proppant in the other conduit.
[0292] The above list should not be limiting but other methods or combination of the above methods may be effective in some formations and more effective in others.
[0293] In embodiments, it may be important to locate the initiation points for tensile-split conduits in wells. Improper placement in EGS wells may limit efficient injected-fluid circulation to recover heat. In the embodiments shown in
[0294] More specifically,
[0295] In the embodiment shown in
[0296] In embodiment,
[0297] The DCM method employs an open hole methodology to enhance the odds of intersecting a conduit deployed from a parallel horizontal well. To enhance the odds further the target well may be tensile-split beforehand.
[0298] In embodiments, during the completion of a pair of lateral sections where one is a cased hole and the other is an open hole, sand or other proppant added to the stimulation fluid in the cased lateral may enter the open hole lateral once connection is made. There may even be a desire to flow the open hole lateral during the completion to enhance the communication and placement of proppants between the laterals. Once fluid movement has stopped, sand may settle and form a bridge or plug in the open-hole lateral preventing future fluid movement.
[0299] To prevent bridges from forming, or to remove them after forming, a tubular string may be inserted in the open hole lateral at a point near the intersection of the stimulation fluid from the injector. Fluid may be circulated from the surface to the end of the tubing in a conventional or preferred reverse circulation mode to remove sand or other proppants or debris from the lateral. It may be preferable to have the tubular circulation string in the vertical part of the well during the stimulation and use it to remove debris after the conclusion of the stimulation.
[0300] A pump rate of 2 to 5 barrels per minute (Note: rate is for 2 tubing) must be used to keep the solids in suspension. Pads of gel and/or surfactants may be added to the fluid to assist in the removal of the fill.
[0301] The tubular string may be threaded and coupled or a continuous coiled tubing string. Nozzles, beveled ends, or other tools/accessories may be added to the string to assist in the debris removal or other processes. Typical threaded and coupled or coiled tubing sizes used in this process are 2, 2, and 2 although smaller and larger sizes may be used.
[0302] The process described above may be used multiple times during the completion process. For example, the process may be used before, during, or after the completion of each stage. The process may also be used in multiple laterals of a multilateral well by simply moving the tubular string between laterals.
[0303] It is important to have unobstructed laterals during and after the creation of conduits between injector and producer laterals.
[0304] At the conclusion of the creation of flow conduits and wellbore cleanout, tubular member 725 may be positioned near the heel 760 of the well 730 to aid in assisting the producer well 730 to flow through the addition of a lighter fluid or a gas. The tubular string 765 may also be used to aid in circulating kill fluid if the need arises.
[0305] Additionally, evenly distributing the injected flowrate between each of the created conduits between a horizontal injection well and one or more horizontal production wells is of utmost importance in the completion design. However, the fluid loses pressure energy to friction as it flows from the source of the injection fluid (the heel) to the far end of the horizontal section (the toe). Because of the higher pressure at the heel, more fluid is forced through the created conduits at the heel than at the toe. As mentioned previously, coiled-tubing-adjustable casing sleeves and perforation distribution are both means of evenly distributing the flowrate through the conduits. In a further embodiment, the relative lateral placement of injection and production wells may be an effective means to evenly distribute flow. In embodiments, the laterals of an injection and a production well may reside in the reservoir at a similar vertical depth, but with the heels of the two laterals placed further apart than the toes, whereby the injected fluid has a further distance to flow between the injector and producer wells at the heels than at the toes. This results in a relatively lower flowrate through the heel conduit due to the increased frictional energy losses from the longer flow path. For example, if the injection and production wells were placed 400 feet apart at the heel and 200 feet apart at the toe, the fluid flowing through the conduit at the heel might suffer twice the pressure drop as that at the toe. Computer modeling is used to balance the frictional energy losses suffered by the fluid flowing from heel to toe along the injector lateral (and toe to heel in the producer lateral) against the frictional energy losses suffered by the fluid flowing a longer distance through the reservoir from the injector to the producer at the heel than at the toe. The modeling is done at a range of fluid flowrates of economic interest.
[0306] Further, to achieve optimum placement and cost it may be required to use the FEN method near the heel and DCM method near the toe of the laterals of the injector and the producer wells. In an embodiment the laterals of injector and producer wells are drilled in a reservoir at the same vertical depth in the reservoir. The heels are placed further apart than the toes. The injector is cased and cemented across the entire lateral. Approximately one half of the lateral of the producer is cased and cemented and the other half is open hole or with an uncemented casing. For example, 20 injector entry points into conduits may be placed across a 5,000-foot lateral. If a total fluid flowrate of 20 barrels per minute (BPM) were pumped from the surface, an average allocation would be 1 BPM exit the injector at each conduit entry point. However, because there is more reservoir contact area between the heels of the wells than between the toes, to achieve a stable flood-front, and so minimize bypass of heat, more fluid would need to be injected near the heel than the toe to create an identical reservoir contact time. Therefore, injection rates near the heel will need to be higher rather than evenly distributed across the horizontal section.
[0307] Reusing suspended and abandoned wells originally drilled to explore for or to produce geothermal energy or hydrocarbons may reduce the cost and risk of constructing EGS horizontal wells. In many wells drilling to the target vertical depth to start the lateral can be more than half the total drilling cost, conferring material economic advantage to this claim. In addition, reusing existing wells may hasten permitting and reduce hurdles for other environmental or regulatory requirements. The mechanical and chemical integrity and longevity of the candidate well, and the suitability of the rock formations for EGS, are first verified using well records, cased logging, and other technologies. A window is then cut in the well casing at the appropriate depth, or the well is deepened to the target depth by drilling through the casing shoe at the bottom of the well. In both cases, the build section, to convert the well direction from vertical to horizontal, and the lateral are then executed.
[0308] When drilling long laterals in geothermal reservoirs containing natural fractures, there is a need to isolate sections of the lateral to allow proper control of fluid movement while simultaneously preserving the natural fracture wellbore connection of zones not requiring isolation. In embodiments, a casing string may be equipped with cementing sleeves containing open and closed positions only, as well as with isolation sleeves containing open, closed, and choked positions. The sleeves may be approximately evenly spaced apart such that zones approximately 350 feet in length may be available for flow and for large cement isolation zones. Zones of lengths ranging from 30 feet to 1,000 feet or more would also be possible. The zones may be spaced appropriately such that when used with the DCM method there would be a large target for the offset well to intersect with a newly created tensile-split conduit. Likewise in reservoirs not containing natural fractures, the sealed wellbore may allow new tensile-split conduits to be created through the isolation sleeves.
[0309] Additionally, in embodiments sleeves may be open, closed, or choked with shifting dogs deployed on coiled or jointed tubing. An example of this method is the Kobold Completions system referenced in Canadian patent CA2928453C.
[0310] In embodiments, small batch-mixed slurries of cement may be pumped into the annulus between the blank casing joints and the formation to form a seal. A circulation sleeve near the heel of the well (or elsewhere in the horizontal casing) may provide a path for return fluids. The newly completed cement plugs may then be used as a seal for flow control or as an isolation method for creating new tensile-split conduits. In embodiments, conventional high-temperature cement formulations, barite, resins, or other products could be used to form sealing plugs in the annulus between the casing and the formation.
[0311]
[0312]
[0313] Geologic understanding of regional rock stress can be used to place lateral section 2025 in an orientation that would have a high degree of certainty of success in connecting the two wells. Likewise, the distance between the vertical second well 2005 and the horizontal first well 2000 in the same plane could be designed to be approximately 100 feet apart or less. Drilling the vertical second well 2005 first would allow an accurate understanding of geologic conditions and enable the optimum location to place the laterals for the eventual reservoir development. The length of lateral section 2025 of the horizontal first well 2000 could be 500 feet or less depending on the degree of certainty of the regional stresses.
[0314]
[0315] The well 2035 may have conventional jet shaped perforating charges perforate a 4-foot section in the casing 2040, with perforations oriented in a spiral pattern to ensure perforations on all sides of the casing 2040. Alternatively, well 2035 may have a frac-sleeve cemented into the casing 2040 at the target depth. A minimum of 4-shots per foot with a minimum 0.25-inch hole may perforate the casing 2040. A shear-stress induced tensile-split conduit 2065 may be initiated by exceeding the formation breakdown pressure of typically between 0.65 and 0.75 psi per foot of depth. The pump rate may be increased and the shear-stress induced tensile-split conduit 2065 may propagate away from the casing 2040. The pump rate should be sufficient to propagate the fracture in a timely manner to overcome any volume losses due to the created conduit geometry or complexity and/or as a result of intersection with natural fractures.
[0316] For depth correlation, fluid may be pumped into the horizontal lateral open hole 2050 of well 2045 and through drill pipe 2055 and a plurality of out ports 2070 and back to the surface. Using the DTS at surface and the known location of the ports 2070, a depth correlation may be made.
[0317] Depicted in
[0318] In embodiments where the regional rock stresses are unknown with any degree of certainty, a horizontal lateral may be drilled in an arc, thus, increasing the probability of an intersection. It is possible to create a conduit parallel to the lateral section of a horizontal well and thus there would not be an intersection point in the configuration discussed in
[0319]
[0320] In designing a development plan for an EGS Geothermal Reservoir it is important to understand the geometry of a shear-stress induced tensile-split conduit. Conduit properties like aperture-width, height, length, transmissivity, or flow capacity etc. are essential inputs to the basis of design.
[0321] Once connection has been made between the injector vertical wellbore 2110 and producer horizontal well 2120 it may be desirable to reverse the directions of the arrows shown in
[0322] Rock stresses in a reservoir may not be uniform or constant from one point in the lateral to another, either initially or as a result of induced shear stresses during tensile-splitting operations. In tectonically active areas there can be significant changes in in-situ stresses across the reservoir. To properly design an EGS development the orientation of future shear-stress induced tensile-split conduits must be understood.
[0323] There are alternatives to using a fiber for the determination of the intersection point of a shear-stress induced tensile-split conduit emanating from a vertical well 2177 and intersecting the hear-horizontal lateral of a horizontal well.
[0324]
[0325] Although
[0326] In place of real-time tools transmitting data to surface on a fiber or wire it would be possible to run memory tools. They could be pumped down and retrieved via the use of a slickline type cable to reduce costs and surface footprints.
[0327] The above methods and procedures could also be used in cases to determine the orientation of natural fractures or fissures where a vertical well and the lateral of a horizontal well intersect the same natural fractures or fissures, by pumping from the vertical well to the lateral and finding the intersection point or points. If more than one intersection were found, this could point toward a much more complex fracture network.
[0328] Another embodiment shows a method to identify the number and potential orientation of a complex network of natural fractures or fissures in the rock.
[0329] One of the primary differences in drilling horizontal wells versus vertical wells is the use of downhole motors and directional measurement assemblies in horizontal wells to the kickoff point and to create a horizontal or near horizontal wellbore. Some vertical or slightly deviated wells may use these tools for a short period to achieve a certain angle but are typically not used for the entire well.
[0330] One of the other primary differences is the potential to intersect multiple fracture systems at various states of depletion. This can cause downhole cross-flow issues from one natural fracture system to another.
[0331] Some authors, like those in patent CA3100013 assigned to Eavor Technologies Inc., recommend a method to sequentially seal fractures in underground reservoirs as the well is being drilled. This option is only limited to those completions where flow of hot-reservoir fluids is not wanted.
[0332]
[0333] The first method is Underbalanced Drilling (UBD) 4015 where the pressure exerted by the ECD is intentionally lower than a rock pore pressure 4005 when drilling through porous rock, or of a borehole stability pressure 4000 when drilling through non-porous impermeable rock. This may be accomplished by aerating the fluid.
[0334] Blind or partial returns of mud fluid (where some of the circulating fluid is lost in natural fractures) has a similar effect to UBD 4015 since the resulting intermittent circulation rates cause the overall fluid weight to be lower than the rock pore pressure 4005.
[0335] The second method is Managed Pressure Drilling (MPD) 4020 where the pressure exerted by the ECD is approximately equal to the rock pore pressure 4005. The third method is Conventional Drilling 4030 where the ECD is greater than the rock pore pressure 4005 (or borehole stability pressure 4000 in non-porous rock) but lower than a rock formation fracturing pressure 4010.
[0336] Tables 3-6 below address when and how each method is used.
TABLE-US-00005 TABLE 3 Under Balanced 4015 Relative Fluid The drilling fluid has a density which exerts a hydrostatic pressure Hydrostatic lower than the rock pore pressure 4005 but greater than the minimum borehole stability pressure 4000. This is commonly accomplished with the injection of a gas (e.g., nitrogen or air) into the drilling fluid at surface to reduce drilling fluid density. Applications/ This technique can be applied to create drilling fluid returns to surface Objectives that are not possible with conventional drilling fluids because of unfavorable combinations of rock pressure 4005, porosity, and permeability/fractures. In this environment, this technique has the following benefits: Allows for effective drill cuttings removal which minimizes the likelihood of nonproductive time (NPT) events. Minimizes the volume/costs associated with drilling fluid losses. Can be used as a method to extend casing string setting depth. Well Control Well control during drilling is maintained by the ECD of the modified Mechanisms fluid and cuttings in the well and the use of surface equipment designed to process the planned production of well fluids. During routine replacement of drill bit and/or Bottom Hole Assembly (BHA) components (tripping), the well is constantly fed fluid from surface to minimize influx of formation fluids. Specialized Standard drilling equipment plus: Surface Rotating Blow Out Preventer (RBOP) installed on top of the Equipment Blow Out Preventer (BOP). This equipment creates a pressure seal around the drill string at surface and is used to create well back pressure. Fluid separation and measurement equipment. If required (e.g., Nitrogen) generation/storage and injection equipment.
TABLE-US-00006 TABLE 4 Blind or partial returns Relative Fluid The drilling fluid hydrostatic pressure is greater than the rock pore Hydrostatic pressure 4005, and fractures or zones of very high permeability are present which result in intermittent drilling fluid returns (partial returns) or 100% loss of drilling fluid (blind). Applications/ This technique can be applied when a limited drilling distance is necessary to complete the hole section. It is not normally applied to long Objectives drilling distances as the risk of NPT is high because the drill cuttings are not being effectively removed from the well. Well Control Well control is maintained by the ECD of the fluid and cuttings in the Mechanisms well. If an unexpected, high-pressure zone is encountered that exceeds the ECD, well control is maintained with the use of surface Blowout Preventers (BOP) and fluid circulation chokes. Specialized Standard drilling equipment Surface Equipment
TABLE-US-00007 TABLE 5 Managed Pressure 4020 Relative Fluid The drilling fluid hydrostatic pressure plus surface back pressure is Hydrostatic precisely controlled to be equal to or slightly greater than the rock pore pressure 4005. This technique may or may not include the use of Nitrogen or other gas to reduce the density of the drilling fluid. Applications/ This technique can be applied towards any of the following objectives: Objectives Improve ROP. Minimize fluid losses or fluid invasion. Extend casing string setting depth. Well Control Well control during drilling is maintained by the ECD of the fluid and Mechanisms cuttings in the well and the use of surface equipment designed to process the planned production of well fluids. During routine replacement of drill bit and/or Bottom Hole Assembly (BHA) components (tripping), the drilling fluid is typically replaced with a fluid with a higher density to create a hydrostatic pressure slightly greater than rock pore pressure 4005. Specialized Standard drilling equipment plus: Surface Rotating BOP (RBOP) installed on top of the drilling rig BOP. Equipment This equipment creates a pressure seal around the drill string at surface and is used to create well back pressure. Fluid separation and measurement equipment. If required, gas (e.g., Nitrogen) generation/storage and injection equipment.
TABLE-US-00008 TABLE 6 Conventional 4030 Relative Fluid The drilling fluid hydrostatic pressure is significantly greater than the Hydrostatic rock pore pressure 4005. Applications/ Most common method of drilling and is applied when manageable well Objectives hazards are present, and rock formations being penetrated are either not sensitive to fluid invasion or will be stimulated. Well Control Well control is maintained by the ECD of the drilling fluid and cuttings Mechanisms in the well. If an unexpected, high-pressure zone is encountered that exceeds the well ECD, well control is maintained with the use of drilling rig surface Blowout Preventers (BOP) and fluid circulation choke(s). Specialized Standard drilling equipment. Surface Equipment
[0337] Both bottom hole and surface drilling fluid temperatures behave differently in vertical versus horizontal drilling. As shown in
[0338] Penetrating naturally flowing fractures while drilling can accelerate the increase in drilling fluid temperatures because heat conduction from the solid rock is enhanced by advection and convection from the naturally flowing fractures.
[0339] An additional consideration is drilling at elevated drilling fluid circulating temperatures. Referring to
[0340] If the drilling fluid returns to surface at temperatures greater than 100 degrees Celsius (212 degrees Fahrenheit), back pressure is required to prevent the water/mix from flashing to steam in the well, which would create a dangerous well control situation. For example, if the drilling fluid returns to surface were about 200 degrees Celsius (292 degrees Fahrenheit), about 1.5 MPa (220 psi) back pressure would be necessary to prevent the fluid from flashing to steam in the well.
[0341] While drilling, a rotating head is required to maintain the necessary back pressure. At surface, a choke and separator are used to vent the steam and return the remaining water to the mud pits for further cooling before pumping back down hole. A continuous supply of fresh water is required to make up for the fluid loss to steam.
[0342] With regard to high-temperature elastomer seals, EPDM (ethylene propylene diene monomer) synthetic rubber elastomers rated to as high as 250 degrees Celsius (482 degrees Fahrenheit) can be used in the BOP, rotating head, and other pressure containing equipment.
[0343] Ensuring equipment suitability at extreme temperatures is only part of the risk as this environment creates significant HSE risk that must be effectively managed.
[0344] As to potential hole collapse, when drilling horizontal wells in fractured reservoirs there is a heightened probability of hole collapse. Rubble zones may accumulate where the hole intersects fractures.
[0345] Detailed precautionary measures to minimize the hole collapsing and the drill-string sticking are presented below. And in cases of drill-string sticking, methods to minimize financial loss of tools and to enhance the chance of recovery are also presented. [0346] Drillingmeasure the return flow rate to calculate whether the well fluid is in turbulent flow. Maintain mechanical agitation through rotation and reciprocation of the drill string. [0347] Conduct regular wiper trips to ensure the well stays clear and free of cuttings build-up. [0348] Blind drilling may be more advantageous than aeriated muds if only a very short section of hole is to be drilled. [0349] It may be possible to detect fractures through an increase in a specific mineral like calcite, or the occurrence of small fractures in the cuttings.
[0350] The following is an explanation of the pre-planning phase. Review offset drilling information and other available records: [0351] Expected list of formations and associated lithological description and depths [0352] Anticipated mud/strip logs to identify shows and cuttings description etc. [0353] Historical well design [0354] Identifying potential drilling hazards (lost circulation, over pressure, borehole instability). [0355] ROP and bit type planned [0356] Anticipated NPT summary [0357] Anticipated drilling fluid circulating temperature [0358] Evaluation activities i.e. core, DST, open/cased hole logging, testing
[0359] Define well design parameters: [0360] Sub surface target definition: [0361] Final Well Depth (True Vertical, lateral length if Hz) [0362] Target entry coordinates and profile [0363] Production/Injection flow rate [0364] Fluid composition, temperature, pressure [0365] Completion design and stimulation method [0366] Evaluation requirements during drilling/frac/test/production [0367] Completion/stimulation [0368] Drilling hazard registry [0369] Lithological definition [0370] Pore pressure profile
[0371] Design the well to minimize friction or minimize parasitic loads: [0372] Design well production casing and tubing for proper metallurgy to minimize corrosion. [0373] Design well to limit friction flowing or circulation or injection pressures to less than 10% of produced electrical capacity generated on-site with reservoir fluid. [0374] Design well location to minimize surface use but still allow simultaneous operations of workovers or completion activities.
[0375] Establish preferred surface location/options: The surface location for the well should be picked after analyzing the geologic layout of fractures and rock stresses and surface constraints like roads, population centers, electrical transmission facilities, water availability and options of water discharge. [0376] Geological constraints and hazards: [0377] major fractures and their direction [0378] regional rock stresses [0379] formation permeability and composition [0380] till etc. [0381] Regulatory design requirements e.g. base of ground water etc. [0382] Surface proximity to population centers, electrical transmission facilities, road access for heavy and wide equipment. [0383] Water availability for drilling, stimulation, cooling, etc. [0384] Water discharge options [0385] Cuttings disposal options
[0386] Pilot well detailed planning and field execution: A vertical pilot well should be drilled to capture geologic reservoir information as well as temperature and interaction between drilling bits and methods. The drilling of this well can either be a decision point to stop the investment or the well could be used as a kickoff point for a horizontal lateral or as an observation well or used to assist in determining the direction of induced or natural fractures. [0387] Establish program objectives [0388] Develop conceptual well design, operations plan and budget class cost estimate [0389] Assess risks and probability of success-pilot hole
[0390] Pilot well investment decision: [0391] Prepare detailed well design, AFE class cost estimate and detailed operations plan [0392] Drill and evaluate/test vertical pilot well [0393] Assess risks and probability of success-horizontal pilot hole [0394] Take core and other electrical logs to evaluate for future stimulation or production options [0395] Test whether electromagnetic tools will transmit data in through the formations to surface.
[0396] Once the pilot well has been drilled the well may be used as a kickoff point for a horizontal well, as a vertical producer if it intersected natural fractures, or as an observation well for obtaining orientation of stimulated tensile-shear conduits using micro seismic, or long-term reservoir temperature measurements.
[0397] Horizontal well investment decision: [0398] Plug back, kick off, build to Horizontal, option to set liner [0399] Drill horizontal/lateral section [0400] Evaluate and test-open hole horizontal section [0401] Complete and suspend well as required
[0402] Observation well investment decision: [0403] Stimulation [0404] Fracture Orientation [0405] Reservoir Temperature Measurement
[0406] It is also important to mitigate operational risks. There are two primary operational risks which may be encountered with drilling long horizontal laterals in hot geothermal rock with natural fractures. The situation may be exacerbated in existing rock where fluids may have been drained in some fractures, but others may be at original pressure or even be above original pressure in trapped zones.
[0407] There is a risk of lost circulation where drilling fluids may be leaking off and no longer reaching the surface or even crossflow in the lateral from one fracture system to another. These losses may result in improper hole cleaning with cuttings debris piles forming in the lateral.
[0408] In a preferred embodiment, as the well is being drilled, close observation is made of the drilling fluid returns to the surface measuring the return fluid flow rate to ensure there are no losses. If losses were to occur the drill string would be pulled back and the situation evaluated before proceeding.
[0409] In another preferred embodiment, a low-cost drilling assembly would be run in case it became stuck and could be abandoned in the hole.
[0410] In another preferred embodiment, Managed Pressure Drilling 4020 or Underbalanced drilling 4015 methods may be used to ensure all cuttings are removed from the well. These types of methods typically are used in conjunction with EM measurement (survey) tools.
[0411] There is a risk of wellbore instability when drilling long laterals in hot geothermal naturally fractured formations. In this instance, the entire sections of the hole may collapse. This may occur because the formation is unconsolidated or from a drop in downhole pressure due to drilling fluid losses.
[0412] In a preferred embodiment, when drilling in a reservoir suspected to have hole stability issues special precautions must be taken. These include drilling only short sections (+/3 meters) (+/10 feet) of new hole at a time; continuously ream/clean the hole and conduct regular wiper trips of the entire open hole sections.
[0413] The operator should have ready access to wireline pump-down tools to locate where the drill string is stuck (free point indicator), and either sever (cut) the drill string at the point it is stuck or apply reverse torque and set off a charge to break and unscrew the connection above the stuck point. Lower cost mud motors and survey tools may be used to reduce the cost if needed to be abandoned.
[0414] Elastomers and electronic components of directional drilling survey tools may have limits on exposure times to elevated downhole temperatures. In a preferred embodiment, MPD 4020/UPD 4015 methods should be employed and should include: [0415] Cool the drilling fluid returns using surface heat exchangers (mud coolers). [0416] Dump/dilute a portion of the drilling fluid returns with fresh, ambient temperature water. [0417] Utilize drilling pipe coatings as insulation to reduce the heat exchange capacity across the drill string.
[0418] In a preferred embodiment a cementing stage collar or sliding sleeve is inserted into the intermediate casing string. After cementing the intermediate casing, the annulus between the surface and intermediate casing is used as a conduit to pump cooling fluid to reduce the temperature of the fluid in the drill pipe which is being used to cool the downhole tools.
[0419] Maintaining proper fluid circulation by using MPD 4020 and UPD 4015 drilling methods while keeping close observation of drilling fluid rates and pressures is key to drilling hot naturally fractured geothermal reservoirs. Once the well has been drilled, completion designs may then be implemented to configure the well to produce the optimal amount of heat energy.
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[0421]
[0422] Method 4130 may be used from the pre planning of the development in block 4135 through the drilling of the pilot hole in block 4140 and into the drilling of the start of the horizontal lateral in block 4150, through the drilling of the lateral in block 4155, appropriately casing the lateral in block 4160 and into the final stimulation or completion of the lateral combined with other wells in block 4165.
[0423] In the preplanning of method 4130, block 4135, the location, number of wells, lengths of laterals, and information to be gained from the pilot hole is planned.
[0424] In the pilot well drilling block 4140 of method 4130, the drilling parameters are learned, rock properties are taken, induced and or natural fracture directions may be understood and the final plan for the drilling of the horizontal lateral is made.
[0425] In the start of lateral block 4150 of method 4130, drilling parameters are understood, including drilling speed, reservoir pressure and temperature, and localized natural fracture conductivity for flowing or drilling losses.
[0426] In the drilling of the lateral in block 4155 of method 4130, the optimum drilling method is determined. For example, if it is determined to drill underbalanced, air may be added to the drill fluid to use the UBD 4015, or losses may be tolerated, and the drill blind method may be used.
[0427] In the casing option block 4160 of method 4130, the final completion casing selection can be made. For example, if the cased and partial cement method is chosen then the location of cementing sleeves, frac sleeves and cement isolation zones are chosen and implemented. If it is determined to use either EGS completion method DCM or FEN then appropriately placed cemented sections will be implemented and fracture collars installed at the appropriate location.
[0428] In the final completion design block 4165 of method 4130 the casing configuration chosen from block 4160 is implemented. For example, it may be chosen to open all the sleeves and equip the well with a closed loop single well circulating fluid production method.
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