Patent Application
20250122796
In the oil and gas industry, engineers and scientists require knowledge of geological parameters or physical characteristics of the hydrocarbon reservoir as a function of spatial position to plan future production operations including the location and trajectory of future wellbores. In particular, the knowledge of the spatial distribution of rock permeability is especially valuable as it may control hydrocarbon production rates.
Knowledge of the physical characteristics, such as permeability, may be obtained from core samples and well logging measurements taken from existing wellbores. These physical characteristics may then be interpolated or extrapolated, often guided by deep sensing surface measurements, between existing wellbore locations to form a reservoir model describing the spatial distribution of physical characteristics across the extent of the hydrocarbon reservoir.
However, core samples and well logs access only a very small region around the wellbore and an extremely small fraction of the entire hydrocarbon volume. Furthermore, rocks surrounding the wellbore may be altered or damaged by the drilling process and changes in the stress field produced by the presence of the wellbore. Consequently, the geological parameters or physical characteristics determined from core samples or well logging measurements may not be representative of the parameters and characteristics of the undisturbed rock formation. Thus, there is a pressing need to sample the parameters and characteristics of the undisturbed rock formation.
This summary is provided to introduce a selection of concepts that are further described below in the detailed description. This summary is not intended to identify key or essential features of the claimed subject matter, nor is it intended to be used as an aid in limiting the scope of the claimed subject matter.
The present disclosure presents methods and systems for measuring a fluid flow characteristic of a subterranean region of interest. The method includes installing a fluid detection sensor in a first lateral extension from a primary wellbore, establishing a fluid conduit from a well-head to a second lateral extension from the primary wellbore, pumping a marker fluid through the fluid conduit from the well-head to the second lateral extension and into the subterranean region of interest. The method further includes detecting, using the fluid detection sensor, the marker fluid in the first lateral extension, wherein the marker fluid in the first lateral extension has flowed from the second lateral extension through the subterranean region of interest and determining the fluid flow characteristic of the subterranean region of interest based, at least in part, on the detected marker fluid.
The system includes a primary wellbore extending from a well-head into the subterranean region of interest, a first lateral extension from a primary wellbore, equipped with a fluid detection sensor configured to detect a marker fluid in the first lateral extension, and a second lateral extension from the primary wellbore, fluidically connected to the well-head through a fluid conduit. The system further includes a pump configured to pump a marker fluid through the fluid conduit from the well-head to the second lateral extension and from the second lateral extension through a portion of the subterranean region of interest to the first lateral extension and a computer processor, configured to determine the fluid flow characteristic of the subterranean region of interest based, at least in part, on the detected marker fluid.
Other aspects and advantages of the claimed subject matter will be apparent from the following description and the appended claims.
Specific embodiments of the disclosed technology will now be described in detail with reference to the accompanying figures. Like elements in the various figures are denoted by like reference numerals for consistency. The size and relative positions of elements in the drawings are not necessarily drawn to scale. For example, the shapes of various elements and angles are not necessarily drawn to scale, and some of these elements may be arbitrarily enlarged and positioned to improve drawing legibility. Further, unless explicitly specified, the particular shapes of the elements as drawn are not necessarily intended to convey any information regarding the actual shape of the particular elements and have been solely selected for ease of recognition in the drawing.
In the following detailed description of embodiments of the disclosure, numerous specific details are set forth in order to provide a more thorough understanding of the disclosure. However, it will be apparent to one of ordinary skill in the art that the disclosure may be practiced without these specific details. In other instances, well-known features have not been described in detail to avoid unnecessarily complicating the description.
Throughout the application, ordinal numbers (e.g., first, second, third, etc.) may be used as an adjective for an element (i.e., any noun in the application). The use of ordinal numbers is not to imply or create any particular ordering of the elements nor to limit any element to being only a single element unless expressly disclosed, such as using the terms “before,” “after,” “single,” and other such terminology. Rather, the use of ordinal numbers is to distinguish between the elements. By way of an example, a first element is distinct from a second element, and the first element may encompass more than one element and succeed (or precede) the second element in an ordering of elements.
It is to be understood that the singular forms “a,” “an,” and “the” include plural referents unless the context clearly dictates otherwise. Thus, for example, reference to a “wellbore” includes reference to one or more of such wellbores.
Terms such as “approximately,” “substantially,” etc., mean that the recited characteristic, parameter, or value need not be achieved exactly, but that deviations or variations, including for example, tolerances, measurement error, measurement accuracy limitations and other factors known to those of skill in the art, may occur in amounts that do not preclude the effect the characteristic was intended to provide.
It is to be understood that one or more of the steps shown in the method may be omitted, repeated, and/or performed in a different order than the order shown. Accordingly, the scope disclosed herein should not be considered limited to the specific arrangement of steps shown in the method.
Although multiple dependent claims are not introduced, it would be apparent to one of ordinary skill that the subject matter of the dependent claims of one or more embodiments may be combined with other dependent claims.
In the following description of
Typically, “overburden” (110) refers to the column of rocks lying above the hydrocarbon reservoir (102) that are of lesser interest to those exploring for, or producing, hydrocarbons from the hydrocarbon reservoir (102). The overburden (110) may include a cap rock (112), or seal. Typically, the cap rock (112) forms an impermeable layer above the hydrocarbon reservoir (102) through which hydrocarbons cannot flow. Below the hydrocarbon reservoir (102) lie further rock layers, sometimes called an “underburden” (114) or “basement”. In some cases, the underburden (114) may contain the source rock from which the hydrocarbon has been produced from biological material under the combined effect of heat and pressure over geological time periods.
In some cases, a subterranean region of interest (100) may contain two or more hydrocarbon reservoirs disposed at different depths. In such cases a shallow hydrocarbon reservoir may form part of the overburden (110) for a deeper hydrocarbon reservoir.
The hydrocarbon reservoir (102) may itself be subdivided into different layers (or “legs”. For example, the shallowest layer within the hydrocarbon reservoir (102) may predominantly contain gas with the pores of the rock and be referred to as the “gas leg” (104). In addition, below the gas leg (104) may lie an “oil leg” (106) where the pores are predominantly filled with oil.
Typically, the lowest level form a “water leg” (108) where the pores are predominantly filled with water or brine. This ordering, with a gas leg (104) lying above an oil leg (106), lying in turn above a water leg (108), is controlled by the relative buoyancy of gas, oil and water and the gradual flow or movement of the three fluids through the pores of the rock over geological time. Although, all three layers may be present in some hydrocarbon reservoirs, other may contain only two, for example oil and water.
Producing hydrocarbon from a hydrocarbon reservoir may require the drilling of a wellbore using a drilling system (118). The wellbore may be drilled directly from the surface of the Earth (120) to the hydrocarbon reservoir (102). Such a wellbore, drilled from the surface to the reservoir, may be called a “primary wellbore” (116). In other embodiments, the wellbore may be drilled from a primary wellbore. Such a wellbore may be termed a “lateral extension” (122) or simply lateral, or a sidetrack. The lateral extension (122) may be initiated from the primary wellbore (116) thousands of feet below the surface of the Earth (120). More than one lateral extension, such as lateral extension (122), may originate from the same primary wellbore (116).
To determine the structure of a subterranean region of interest (100) a reservoir modeling system, such as reservoir modeling system (204) shown in
Reservoir data (202) may include remote sensing data, such as seismic survey data, electromagnetic survey data, and gravity survey data that may be recorded from the surface of the Earth (120). Reservoir data (202) may also include data recorded with sensors within a wellbore. These sensors may be permanently emplaced, for example behind casing, or may be conveyed on wireline, coiled tubing, or on the drillstring. For example, these sensors may record, without limitation, gamma ray emission, resistivity, spontaneous potential, density, porosity, or acoustic wave speed of the rock formations surrounding the formation. Reservoir data (202) may further include production and injection data from existing wellbore penetrating the hydrocarbon reservoir, including flow rates, fluid compositions, pressures and temperatures.
Reservoir data may further be combined to determine rock formation characteristics, such as permeability, porosity and elastic moduli, by the reservoir modeling system. The reservoir modeling system may further interpolate and/or extrapolate the measured sensor values, and the determined rock formation characteristics into the space between the wellbores, to produce a digital representation of the subterranean region of interest including the hydrocarbon reservoir. Such a digital representation may be termed a reservoir model (206). The reservoir model (206) may include values of rock formation and pore fluid characteristics on a three-dimensional (3D) Cartesian or irregular grid spanning the subterranean region of interest.
In some embodiments, the reservoir model may be the input to a reservoir simulator (208). A reservoir simulator comprises functionality for simulating the flow of fluids, including hydrocarbon fluids such as oil and gas, through a hydrocarbon reservoir composed of porous, permeable reservoir rocks in response to natural and anthropogenic pressure gradients.
A reservoir simulator (208) may solve a set of mathematical governing equations that represent the physical laws that govern fluid flow in porous, permeable media. For example, the flow of a single-phase slightly compressible oil with a constant viscosity and compressibility the equations capture Darcy's law, the continuity condition and the equation of state and may be written as:
where p represents fluid in the reservoir, x is a vector representing spatial position and t represents time. φ, μ, ct, and k represent the physical and petrophysical properties of porosity, fluid viscosity, total combined rock and fluid compressibility, and permeability, respectively. ∇2 represents the spatial Laplacian operator.
Additional, and more complicated equations are required when more than one fluid, or more than one phase, e.g., liquid and gas, are present in the reservoir. Further, when the physical and petrophysical properties of the rocks and fluids vary as a function of position the governing equations may not be solved analytically and must instead be discretized into a grid of cells or blocks. The governing equations must then be solved by one of a variety of numerical methods, such as, without limitation, explicit or implicit finite-difference methods, explicit or implicit finite element methods, or discrete Galerkin methods.
The reservoir simulator (208) may be used to predict one or more fluid flow and production scenario (210). For example, the reservoir simulator (208) may be used to predict the changes in fluid flow, including fluid flow into well penetrating the reservoir, as a result of fluid injection and/or extraction of time. For example, the reservoir simulator may be used to predict changes in hydrocarbon production rate that would result from the injection of water into the reservoir from wells around the hydrocarbon reservoir's periphery. Similarly, the reservoir simulator (208) may be used to predict the hydrocarbon production rate that would result from proposed new wellbores.
Fluid flow and production scenarios (210) may be used to form or update a reservoir production plan (212). The reservoir production plan may specify where and in what order to drill wellbores to penetrate the hydrocarbon and which wellbore may be used to inject fluids, such as water, rather than to produce hydrocarbons. The reservoir production plan (212) may specify which planned wellbores are to be primary wellbores, such as primary wellbore (116) and which planned wellbore are to be lateral extensions, such as lateral extension (122).
Similarly, the reservoir production plan (212) may specify wellbore completions. In particular, the reservoir production plan may specify the location and parameters of another form of lateral extension that wellbores may undergo, namely hydraulic fracturing. In hydraulic fracturing the fluid pressure inside a wellbore may be increase by injecting fluid from the surface until the rock formation surrounding the wellbore cracks or fractures creatin a subterranean fissure emanating from the wellbore lateral to the axis of the wellbore. Further, proppant, often a fine sand may be pumped from the surface of the Earth into the hydraulic fracture. As the term suggests, proppant props the hydraulic fracture at least partially open when the fluid pressure is reduced thus creating a hydraulic pathway from the wellbore into the body of the hydrocarbon reservoir.
Drilling systems (214) may be used to drill further wellbores, both primary wellbores (116) and lateral extensions (122) guided by the reservoir production plan (212). Further the wellbores (116, 122) drilled by the drilling system (214) may be used to collect additional reservoir data (202).
The drillstring (308) may comprise a plurality of sections of drillpipe attached at the uphole end to the drive shaft (316) and downhole to a bottomhole assembly (“BHA”) (318). The BHA may be composed of a plurality of sections of heavier drillpipe and one or more measurement-while-drilling (“MWD”) tools configured to measure drilling parameters, such as torque, weight-on-bit, drilling direction, temperature, etc., and one or more logging-while-drilling (“LWD”) tools configured to measure parameters of the rock surrounding the wellbore (302), such as electrical resistivity, density, sonic propagation velocities, gamma-ray emission, etc.
The wellbore (302) may traverse a plurality of overburden (110) layers and one or more cap-rock (112) layers to a hydrocarbon reservoir (102) within the subterranean region of interest (100), and specifically to a drilling target (324) within the hydrocarbon reservoir (102). The wellbore trajectory (304) may be a curved or a straight trajectory. All or part of the wellbore trajectory (304) may be vertical, and some portions of the wellbore trajectory (304) may be deviated or be horizontal. One or more portions of the wellbore (302) may be cased with casing (326) in accordance with the wellbore plan.
To start drilling, or “spudding in” the well, the hoisting system lowers the drillstring (308) suspended from the derrick (312) towards the planned surface location of the wellbore. An engine, such as a diesel engine, may be used to supply power to the top drive (314) to rotate the drillstring (308). The weight of the drillstring (308) combined with the rotational motion enables the drill bit (306) to bore the wellbore.
The near-surface is typically made up of loose or soft sediment or rock, so large diameter casing (326), e.g., “base pipe” or “conductor casing,” is often put in place while drilling to stabilize and isolate the wellbore. At the top of the base pipe is the wellhead, which serves to provide pressure control through a series of spools, valves, or adapters. Once near-surface drilling has begun, water or drill fluid may be used to force the base pipe into place using a pumping system until the wellhead is situated just above the surface of the Earth (120).
Drilling may continue without any casing (326) once deeper, or more compact rock is reached. While drilling, a drilling mud system (328) may pump drilling mud from a mud tank on the surface of the Earth (120) through the drill pipe. Drilling mud serves various purposes, including pressure equalization, removal of rock cuttings, and drill bit cooling and lubrication.
At planned depth intervals, drilling may be paused and the drillstring (308) withdrawn from the wellbore. Sections of casing (326) may be connected and inserted and cemented into the wellbore. Casing string may be cemented in place by pumping cement and mud, separated by a “cementing plug,” from the surface of the Earth (120) through the drill pipe. The cementing plug and drilling mud force the cement through the drill pipe and into the annular space between the casing and the wellbore wall. Once the cement cures, drilling may recommence. The drilling process is often performed in several stages. Therefore, the drilling and casing cycle may be repeated more than once, depending on the depth of the wellbore and the pressure on the wellbore walls from surrounding rock.
Due to the high pressures experienced by deep wellbores, a blowout preventer (BOP) may be installed at the wellhead to protect the rig and environment from unplanned oil or gas releases. As the wellbore becomes deeper, both successively smaller drill bits and casing string may be used. Drilling deviated or horizontal wellbores may require specialized drill bits or drill assemblies.
A drilling system (214) may be disposed at and communicate with other systems in the well environment. The drilling system (214) may control at least a portion of a drilling operation by providing controls to various components of the drilling operation. In one or more embodiments, the system may receive data from one or more sensors arranged to measure controllable parameters of the drilling operation. As a non-limiting example, sensors may be arranged to measure weight-on-bit, drill rotational speed (RPM), flow rate of the mud pumps (GPM), and rate of penetration of the drilling operation (ROP). Each sensor may be positioned or configured to measure a desired physical stimulus. Drilling may be considered complete when a drilling target (324) is reached, or the presence of hydrocarbons is established.
In many cases, the drilling target (324) may be a portion of the hydrocarbon reservoir (102) that the reservoir model (206) predicts to be a region of high porosity and high permeability, since regions such as these may both contain significant amounts of hydrocarbons and allow them to flow with relative ease from the rock formation to the wellbore.
In contrast, cross-section (410) depicts a rock sample with high porosity but low permeability. Although, the pores (408) between the grains (406) contributes a much larger fraction of the volume of rock sample depicted in cross-section (410) than of rock sample depicted in cross-section (402), and hence has a higher porosity, these pores (408) are not well connected by pathways through which pore fluid may flow. Hence, cross-section (410) depicts a rock sample with low permeability.
Cross-section (420) depicts a rock sample with low porosity, i.e., a small fraction of the volume of the rock sample is composed of pores, it does exhibit continuous pathways between the pores, such as pathway (422) indicated by the dashed line, through which fluid may flow. Thus, cross-section (420) depicts a rock sample with higher permeability than either cross-section (402) or cross-section (410) but a lower permeability than cross-section (410).
Finally, cross-section (430) depicts a rock sample with both high porosity and high permeability. That is, cross-section (430) both has a high volume fraction of pore space and flow pathways through which pore fluid may flow when subjected to a pressure gradient.
Predicting characteristics of the hydrocarbon reservoir (102) surrounding a primary wellbore (116) from reservoir data recorded along said primary wellbore (116) presents several difficulties. In particular, predicting permeability of the reservoir (102) is challenging.
Firstly, a hydrocarbon reservoir may exhibit significant spatial heterogeneity in its characteristics both vertically and laterally. This makes simple interpolation inaccurate. Such heterogeneity may include discontinuous changes, due to the presence of a fault intersecting the reservoir, as well as gradual continuous changes.
Secondly, even in a mature hydrocarbon reservoir (102) penetrated by numerous primary wellbores (116), only a fraction of the volume of the hydrocarbon reservoir (102) may be sampled. This is particularly apparent when it is understood that reservoir data collected from each primary wellbore (116) has a depth of investigation into the rock formation of only one or two wellbore diameters at most, i.e., a foot or two feet (0.3 to 0.6 meters). In contrast, neighboring primary wellbores (116) may be separated by several hundred, if not, thousands of feet.
Thirdly, the process of drilling a primary wellbore (116) may damage the rock adjacent to the primary wellbore (116). For example, the surrounding rock may suffer micro-cracking and changes in the stress field as a result of the creating of the wellbore. Further, the rock adjacent to the primary wellbore (116) may experience infiltration of the drilling mud used to lubricate the drill bit and flush rock fragments.
When the drilling mud infiltrates the rock, the drilling mud may replace the pore fluids originally saturating the rock, and the grains of the rock may undergo chemical changes, e.g., swelling, as a result of exposure to the drilling mud. Furthermore, the rock may undergo thermal changes, such as heating or cooling, during the drilling of the primary wellbore (116). Each of these changes, and others not listed, may change the physical characteristics of the rock formation adjacent to the primary wellbore (116).
Thus, sensors deployed in the primary wellbore (116) may not measure physical characteristics representative of the hydrocarbon reservoir (102) as a whole. As a consequence, the unrepresentative physical characteristics may be erroneously interpolated or extrapolated using the reservoir modeling system. Inaccurate determination of physical characteristics is damaging to the drilling and completion of the hydrocarbon reservoir (102).
As such, the ability to accurately determine the physical characteristics of the hydrocarbon reservoir (102) as a whole is beneficial. Therefore, embodiments disclosed herein outline systems and methods that can be used to accurately determine the physical characteristics of the hydrocarbon reservoir (102) by mimicking multi-well testing using a single primary wellbore (116).
The embodiments disclosed herein create lateral extensions, and/or hydraulic fractures, from a primary wellbore (116). The lateral extensions may be created using any means in the art, such as drilling a sidetracked wellbore, using tunneling equipment to create tunnels, etc. The lateral extensions, and/or hydraulic fractures, are used to measure the formation properties of the reservoir (102) located between neighboring lateral extensions, and/or hydraulic fractures.
The lateral extensions/hydraulic fractures work together, or work with the primary wellbore (116), to create an injection/production system. At least one of the lateral extensions/hydraulic fractures or primary wellbore (116) is formed as an “injection side” and at least one of the lateral extensions/hydraulic fractures or primary wellbore (116) is formed as an “observation side”.
The observation side is equipped with measurement tools to help determine the formation properties in-situ between the injection side and the observation side. Such measurements will give a better understanding of the reservoir (102) permeability at different orientations. Any combination of number and orientation of lateral extensions may be used without departing from the scope of the disclosure herein.
In
In some embodiments, the lateral extensions (510a-510f) may deviate several feet to several hundred feet or more from the primary wellbore (116). In some embodiments, the lateral extensions (510a-510f) may themselves have a length of a few feet to a few hundred feet, and a diameter of an inch to several inches. However, the example length range and diameter range of the lateral extensions should not be regarded as limiting to the claimed invention.
The lateral extensions (510a-510f) shown in
In terms of tunnels, the lateral extensions (510a-510f) are drilled using tunneling technology. Tunneling technology typically requires less surface equipment than the equipment required to fully sidetrack a well. Tunneling technology may use lasers, high pressured water, acid, miniature drill bits, etc., to form the tunnels. Tunneling technology may also use coiled tubing or wireline to deploy the downhole tunneling tools.
From the injection zone (514), the marker fluid may flow, under an imposed pressure gradient, through the hydrocarbon reservoir (102) to one or more of the reception portions (512) of the lateral extensions (510a-510f). In some embodiments, the imposed pressure gradient may be produced by elevating the pressure in the injection zone (514). In other embodiments, the pressure gradient may be produced by lowering the pressure in the reception portions (512). In further embodiments, a pressure gradient may be produced by raising the pressure in the injection zone (514) while simultaneously lowering the pressure in the reception portions (512).
In the embodiments described above, the injection zone (514) lies in the primary wellbore (116) and the reception portions (512) lie in the lateral extensions (510a-510f). However, this should not be regarded as limiting to the scope of the invention. In particular and in other embodiments, the injection zone (514) may lie in one or more of the lateral extensions (510a-510f) and the reception portions (512) may lie in the primary wellbore (116). In further embodiments, the injection zone (514) may be called the active side and the reception portions (512) may be called the receiving or observation sides.
In further embodiments, the reception portions (512) may be completed to allow the marker fluid to enter the reception portion (512) from the surrounding reservoir (102). Once the marker fluid has entered the reception portion (512), the marker fluid may flow out of the reception portion (512) to one or more sensors disposed further within the lateral extension (510a-510f). For example, the completion may include a casing disposed within each reception portion (512). The casing may be perforated to allow the marker fluid to enter the reception portions (512).
In other embodiments, the reception portion (512) of the lateral extensions (510a-510f) may remain uncompleted and coiled tubing, or temporary tubing, may be connected to or deployed within the reception portion (512). In this scenario, the marker fluid may be injected into the reservoir (102) using at least one of the injection zones (514). The marker fluid may travel through the reservoir (102) to be received by the coiled tubing, or temporary tubing, in the reception portion (512). The coiled tubing or temporary tubing may be equipped with the sensors and may detect arrival time and other fluid properties of the marker fluid. This data may be used to determine the permeability of the reservoir (102) between the injection zone (514) and the reception portion (512).
In other embodiments, the coiled tubing or the temporary tubing may be used as a conduit for the marker fluid to travel to the surface of the Earth (120). At the surface of the Earth (120), the marker fluid may be measured or detected using sensors or the human eye.
In further embodiments, coiled tubing or temporary tubing may be connected to or deployed within the injection zone (514). In this scenario, the marker fluid can be injected in the annulus between the coiled tubing, or temporary tubing, and the reservoir (102). The marker fluid then flows through the reservoir (102) to be received or detected at the reception portion (512). The reception portion (512) may include sensors to indicate reception of the marker fluid and/or measure fluid properties of the marker fluid.
In other embodiments, the reception portion (512) may be equipped with casing that acts as a conduit for the marker fluid to travel to the surface of the Earth (120). At the surface of the Earth (120), the marker fluid may be measured or detected using sensors or the human eye.
The marker fluid may include any fluid that is injected into the reservoir (102) from the injection zone (514). In further embodiments, the marker fluid possess at least one measurable characteristic that differ from the fluids already present in the hydrocarbon reservoir. For example, if the hydrocarbon reservoir contains oil and water, then the marker fluid may be gas. Alternatively, if the hydrocarbon reservoir fluid is oil, then the marker fluid may be water. In some embodiments, the marker fluid may be a fluorescent fluid, while in other embodiments the marker fluid may be a radioactive fluid. In still further embodiments, the marker fluid may possess a specific chemical structure, such as a polymer.
Several different characteristics of the marker fluid may be measured at lateral extensions (510a-510f). For example, in some embodiments the arrival time of the marker fluid at the reception portions (512) and/or the lateral extensions (510a-510f) may be recorded. Alternatively, the transit time between the beginning of injection at the injection zone (514) to the detection of the marker fluid at the lateral extensions (510a-510f) may be recorded. In other embodiments, the flow rate, or concentration of the marker fluid once a steady state has been reached, may be recorded.
For example, and as shown in
The hydraulic fractures (520a, 520b) are each located at a distinct position along the length of the primary wellbore (116). In accordance with one or more embodiments, one of the hydraulic fractures, such as hydraulic fracture (520b), may be configured as an injection zone (514) for the marker fluid, while the other hydraulic fracture, such as hydraulic fracture (520a) may be configured as a reception portion (512).
It will be understood that only a limited number of possible lateral extension geometries have been presented here by way of illustration and these examples are not intended to limit the scope of the invention. Other geometries and combinations will be apparent to those skilled in the art. For example, lateral extensions, such as lateral extensions (510a-510h), may be combined with hydraulic fractures, such as hydraulic fractures (520a, 520b).
For example, a hydraulic fracture may be used for injection of the marker fluid and a lateral extension may be used for the deployment of sensors to form a reception portion, or vice versa. Alternatively, one or more lateral extensions may be drilled and a hydraulic fracture may be initiated in the lateral extension. In further embodiments, the lateral extensions can be positioned in different numbers and orientations to enhance the permeability measurements in the X, Y, and Z axis. Also, the flow pattern may be varied from radial to linear by creating parallel fractures.
In accordance with one or more embodiments, one or more physical characteristic of the rock formation of the hydrocarbon reservoir may be determined from the characteristics of the marker fluid. In particular, the permeability of the portion of the hydrocarbon reservoir lying between the injection zone and the reception portion of the lateral extensions may be determined. In accordance with one or more embodiments, permeability of the reservoir (102) between the injection zone (514) and the reception portion (512) can be calculated by the injection pressure, injection rate, measured flow rate, and pressure from the reception portion (512).
It is important to note that these portions of the hydrocarbon reservoir (102) may be tens or hundreds of feet in spatial extent, i.e., much larger volumes than that sensed by sensors located in the primary wellbore (116). Furthermore, the portion of the hydrocarbon reservoir (102) lying between the injection zone (514) and the reception portion (512) of the lateral extensions (510a-510h) may be much less subject to alteration or damage than the rocks immediately surrounding the primary wellbore (116).
In some case, numerical simulation may be required to determine the physical characteristics of the hydrocarbon reservoir (102) from the measured or observed characteristic of the marker fluid. For example, a plurality of fluid flows may be simulated by a reservoir simulator, one for each of a range of physical characteristic values, such as permeability values.
The simulations may be performed using manual estimates of the permeability value, or randomly selected permeability values or within a formal inversion procedure, without departing from the scope of the invention. The value of permeability that produces a simulation that best fits the observed or measured characteristics of the marker fluid may be taken as a reliable estimate of the true permeability value of the hydrocarbon reservoir (102) between the locations of the injection zone (514) and reception portions (512) of the lateral extensions (510a-510f).
In some injection-reception geometries, such as those shown in
While not explicitly depicted, the two lateral extensions (610a, 610b) may extend at any angle away from the primary wellbore (116). Furthermore, the two lateral extensions (610a, 610b) need not extend at the same angle. For example, lateral extension (610a) may extend at a 45 degree angle from the primary wellbore (116) while lateral extension (610b) may extend at a 90 degree angle from the primary wellbore, or vice versa. In other embodiments, the lateral extensions (610a, 610b) shown in
In further embodiments, there may be more than two lateral extensions (610a, 610b) extending from the primary wellbore (116). For example, there may be one lateral extension acting as an injection zone (514) with two other lateral extensions acting as reception portions (512). Furthermore, the primary wellbore (116) may be a horizontal wellbore without departing from the scope of the disclosure herein.
The portion of the hydrocarbon reservoir (102) immediately adjacent to the wellbore (116) may be a damaged or altered zone (604) where the rock has been damaged or altered by the process of drilling and completing the wellbore (116). In accordance with one or more embodiments, and as shown in
A packer (612) may be disposed within the primary wellbore (116) between the intersection of the first lateral extension (610a) with the primary wellbore (116) and the intersection of the second lateral extension (610b) with the primary wellbore (116). The packer (612) may form a hydraulic seal, isolating the portions of the wellbore (116) lying on either side. The packer (612) may be deployed on, and penetrated by, a tubing (614) that may form a fluid conduit (616) from the surface to the second lateral extension (610b) through which marker fluid may be pumped.
In accordance with some embodiments, at least one sensor, such as sensors (618a-e) may be disposed in the first lateral extension (610a). In other embodiments, at least one sensor, may be positioned in the primary wellbore (116) close to the intersection between the primary wellbore (116) and the first lateral extension (610a), not shown. The sensors may be connected to the wellhead through a physical communications channel (620), such as a wireline or an optical fiber.
Alternatively, the sensors may have wireless communication with the wellhead. In still other embodiments, the sensors may store data autonomously to be retrieved later by a data retrieval tool (not shown) or by recovering the sensors themselves to the surface. The sensors (618a-e) may be configured to detect the presence and/or characteristics of the marker fluid that may percolate through the hydrocarbon reservoir (102) from the second lateral extension (610b) to the first lateral extension (610a), as indicated by the arrows (618), substantially avoiding the damaged or altered zone (604).
In Step 704 a fluid conduit (616) from a wellhead to a second lateral extension (610b) from the primary wellbore (116) may be established. In some embodiments, the second lateral extension (610b) may be a sidetracked wellbore, a tunnel, or a hydraulic fracture (520a, 520b). In some embodiments, the first lateral extension (610a) and the second lateral extension (610b) are hydraulically isolated within the primary wellbore (116) with an impermeable packer (612) disposed between the lateral extensions (610a, 610b). The fluid conduit (161) may be established by inserting a coiled tubing from the wellhead through the packer (612).
In Step 706 a marker fluid may be pumped through the fluid conduit (616) from the wellhead to the second lateral extension (610b) and into the subterranean region of interest. In some embodiments, the marker fluid may be a radioactive tracer, while in other embodiments the marker fluid may be a fluorescent fluid, or a polymer. In other embodiments the marker fluid may be any fluid with characteristics distinct from the hydrocarbon reservoir pore fluid.
In Step 708 the marker fluid in the first lateral extension (610a) may be detected using at least one fluid detection sensor (618a-e). The detected marker fluid may have flowed to the first lateral extension (610a) from the second lateral extension (610b) through the subterranean region of interest. The fluid detection sensor (618a-e) may detect characteristics of the marker fluid. For example, the marker fluid characteristic may be a steady-state flow rate, or a detection time of the marker fluid after the initiation of injection.
In Step 710, the fluid flow characteristic of the subterranean region of interest may be determined based, at least in part, on the detected marker fluid. In some embodiments, the fluid flow characteristic may be a permeability or one or more components of a permeability tensor. In some embodiments, determining the fluid flow characteristic may include performing fluid flow modelling for a relative geometry of the first lateral extension and the second lateral extension. Such a fluid flow modeling may be performed using a reservoir simulator.
Further, a reservoir model may be determined or updated using a reservoir modeling system, based, at least in part, on the fluid flow characteristic. Still further a reservoir production plan describing planned wellbore drilling and completion operations, and surface production facility construction may be revising based, at least in part, on the updated reservoir model. The reservoir production plan may include the drilling, using a drilling system, of new wellbore, including extended-reach and sidetrack wellbores based, at least in part, on the revised reservoir production plan.
The illustrated computer (802) is intended to encompass any computing device such as a server, desktop computer, laptop/notebook computer, wireless data port, smart phone, personal data assistant (PDA), tablet computing device, one or more processors within these devices, or any other suitable processing device, including both physical or virtual instances (or both) of the computing device. Additionally, the computer (802) may include a computer that includes an input device, such as a keypad, keyboard, touch screen, or other device that can accept user information, and an output device that conveys information associated with the operation of the computer (802), including digital data, visual, or audio information (or a combination of information), or a graphical user interface (GUI).
The computer (802) can serve in a role as a client, network component, a server, a database or other persistency, or any other component (or a combination of roles) of a computer system for performing the subject matter described in the instant disclosure. The illustrated computer (802) is communicably coupled with a network (830). For example, a generic computer (802), reservoir modeling system (204), and reservoir simulator (208) may be communicably coupled using a network (830). In some implementations, one or more components of the computer (802) may be configured to operate within environments, including cloud-computing-based, local, global, or other environment (or a combination of environments).
At a high level, the computer (802) is an electronic computing device operable to receive, transmit, process, store, or manage data and information associated with the described subject matter. According to some implementations, the computer (802) may also include or be communicably coupled with an application server, e-mail server, web server, caching server, streaming data server, business intelligence (BI) server, or other server (or a combination of servers).
The computer (802) can receive requests over network (830) from a client application, for example, executing on another computer (802) and responding to the received requests by processing the said requests in an appropriate software application. For example, since seismic processing and seismic interpretation may be not be sequential, each computer (802) system may receive requests over a network (830) from any other computer (802) and respond to the received requests appropriately. In addition, requests may also be sent to the computer (802) from internal users (for example, from a command console or by other appropriate access method), external or third-parties, other automated applications, as well as any other appropriate entities, individuals, systems, or computers.
The computer (802) includes an interface (804). Although illustrated as a single interface (804) in
The computer (802) also includes at least one computer processor (805). Although illustrated as a single computer processor (805) in
The computer (802) further includes a memory (806) that holds data for the computer (802) or other components (or a combination of both) that can be connected to the network (830). For example, memory (806) can be a database storing data consistent with this disclosure. Although illustrated as a single memory (806) in
The application (807) is an algorithmic software engine providing functionality according to particular needs, desires, or particular implementations of the computer (802), particularly with respect to functionality described in this disclosure. For example, application (807) can serve as one or more components, modules, applications, etc. Further, although illustrated as a single application (807), the application (807) may be implemented as multiple applications (807) on the computer (802). In addition, although illustrated as integral to the computer (802), in alternative implementations, the application (807) can be external to the computer (802).
Each of the components of the computer (802) can communicate using a system bus (803). In some implementations, any or all of the components of the computer (802), both hardware or software (or a combination of hardware and software), may interface with each other or the interface (804) (or a combination of both) over the system bus (803) using an application programming interface (API) (812) or a service layer (813) or a combination of the API (812) and service layer (813). The API (812) may include specifications for routines, data structures, and object classes. The API (812) may be either computer-language independent or dependent and refer to a complete interface, a single function, or even a set of APIs.
The service layer (813) provides software services to the computer (802) or other components (whether illustrated or not) that are communicably coupled to the computer (802). The functionality of the computer (802) may be accessible for all service consumers using this service layer. Software services, such as those provided by the service layer (813), provide reusable, defined business functionalities through a defined interface. For example, the interface may be software written in JAVA, C++, or other suitable language providing data in extensible markup language (XML) format or another suitable format. While illustrated as an integrated component of the computer (802), alternative implementations may illustrate the API (812) or the service layer (813) as stand-alone components in relation to other components of the computer (802) or other components (whether or not illustrated) that are communicably coupled to the computer (802). Moreover, any or all parts of the API (812) or the service layer (813) may be implemented as child or sub-modules of another software module, enterprise application, or hardware module without departing from the scope of this disclosure.
There may be any number of computers (802) associated with, or external to, a computer system containing computer (802), wherein each computer (802) communicates over network (830). For example, one computer system may be specifically configured for reservoir simulation and denoted the reservoir simulator (208). Another computer system may be specifically configured for reservoir modeling and denoted the reservoir modeling (204). In some embodiments, seismic processing, such as steps 502-522 of
Further, the term “client,” “user,” and other appropriate terminology may be used interchangeably as appropriate without departing from the scope of this disclosure. Moreover, this disclosure contemplates that many users may use one computer (802), or that one user may use multiple computers (802).
Although only a few example embodiments have been described in detail above, those skilled in the art will readily appreciate that many modifications are possible in the example embodiments without materially departing from this invention. Accordingly, all such modifications are intended to be included within the scope of this disclosure as defined in the following claims.
