Patent Grant
10450860
Operations, such as surveying, drilling, wireline testing, completions, production, planning and field analysis, are typically performed to locate and gather valuable downhole fluids. Surveys are performed using acquisition methodologies, such as seismic scanners or surveyors to obtain data about underground formations. During drilling and production operations, data is typically collected for analysis and/or monitoring of the operations. Such data may include, for instance, information regarding subterranean formations, information detailing how the drilling and/or production equipment are operating, information regarding the amount of fluid that is obtained or used, and/or other data. Typically, simulators use the gathered data to model specific behavior of discrete portions of the operations.
In general, in one aspect, embodiments related to a method for characterizing a subterranean formation traversed by a wellbore. The method includes generating a reservoir model using data collected from the formation, generating a perturbation object comprising a perturbation of the wellbore, integrating the perturbation object with the reservoir model, and forming a geological model wherein the perturbation object is integrated in the reservoir model.
In general, in one aspect, embodiments related to a system for characterizing a subterranean formation traversed by a wellbore. The system includes a computer processor, a data repository for storing a perturbation object representing a perturbation, and a perturbation object modeling module, executing on the computer processor. The perturbation object modeling module is configured to generate the perturbation object, and integrate the perturbation object with a reservoir model. The system further includes a reservoir modeling package, executing on the computer processor. The reservoir modeling package includes a well log modeling module configured to generate the reservoir model using data collected from the formation, and an interface configured to display a geological model wherein the perturbation object is integrated in the reservoir model.
In general, in one aspect, embodiments relate to a non-transitory computer readable medium that includes computer readable program code embodied therein for generating a reservoir model using data collected from a subterranean formation, generating a perturbation object representing a perturbation along a well trajectory at a hydrocarbon reservoir, integrating the perturbation object with the reservoir model, and forming a geological model wherein the perturbation object is integrated in the reservoir model.
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.
Embodiments of integrating invasion modeling with reservoir modeling are described with reference to the following figures. The same numbers are used throughout the figures to reference like features and components.
Specific embodiments 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.
In the following detailed description of embodiments, numerous specific details are set forth in order to provide a more thorough understanding. However, it will be apparent to one of ordinary skill in the art that the invention 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.
In general, embodiments are directed to characterizing a subterranean formation traversed by a wellbore. As a practical matter, throughout this specification, the terms wellbore and borehole are used interchangeably to indicate a void in a subterranean formation often created by a drill or other earth moving device. The void may be cased or uncased. The cross sectional area may be cylindrical, elliptical, random, or a combination thereof.
Specifically, embodiments integrate reservoir modeling with modeling of a perturbation along the wellbore trajectory at a hydrocarbon reservoir. A perturbation object representing the perturbation is generated and integrated with a reservoir model. Integrating the perturbation object and the reservoir model includes accounting for the affects of, knowledge gained from the perturbation on the reservoir by adjusting the reservoir model based on the perturbation object, and accounting for the affects of, and knowledge gained from the reservoir on the perturbation by adjusting the perturbation object based on the reservoir model. A geological model that has the perturbation object integrated with the reservoir model is formed.
In general, a perturbation is a variation of the formation resulting from introducing a borehole into the formation. A single or multiple perturbations may exist along the same wellbore trajectory. Further, a perturbation is not necessarily rare or seldom occurring. Rather, a perturbation may occur with some frequency. For example, a perturbation may be an invasion, such as an invasion of mud filtrate, in a wellbore. As another example, a perturbation may be borehole shape change. Such shape change may be a breakout or a widening or narrowing or the borehole in one or more embodiments. In the second example, a borehole shape change may be a deviation from the borehole being in a cylindrical form.
In the case of invasion, embodiments provide a method and apparatus for analyzing data when an invasion exists. In one or more embodiments, an invasion is the movement of fluid, such as mud filtrate and/or other fluid, into a formation around a borehole. The invasion of the fluid may affect the accuracy of determining in-situ formation properties. One or more embodiments include functionality to generate an invasion model and integrate the invasion model with a reservoir model. Thus, both the invasion model integrated with the reservoir model may be displayed for the user and/or used to more accurately determine formation properties and/or geometry that account for the invasion. Further, one or more embodiments include functionality to modify drilling and/or production operations based on the revised determination of the formation properties.
Sensors (S), such as gauges, may be positioned about the field to collect data relating to various field operations as described previously The data gathered by the sensors (S) may be collected by the surface unit (134) and/or other data collection sources for analysis or other processing. The data collected by the sensors (S) may be used alone or in combination with other data. Further, the data outputs from the various sensors (S) positioned about the field may be processed for use. The data may be collected in one or more databases and/or all or transmitted on or offsite. All or select portions of the data may be selectively used for analyzing and/or predicting operations of the current and/or other wellbores. The data may be may be historical data, real time data or combinations thereof. The real time data may be used in real time, or stored for later use. The data may also be combined with historical data or other inputs for further analysis. The data may be stored in separate data repositories, or combined into a single data repository.
The collected data may be used to perform analysis, such as modeling operations. For instance, seismic data output may be used to perform geological, geophysical, and/or reservoir engineering. The reservoir, wellbore, surface and/or process data may be used to perform reservoir, wellbore, geological, geophysical or other simulations. The data outputs from the operation may be generated directly from the sensors (S), or after some preprocessing or modeling. These data outputs may act as inputs for further analysis.
The data is collected and stored at the surface unit (134). One or more surface units (134) may be located at the field (100), or connected remotely thereto. The surface unit (134) may be a single unit, or a complex network of units used to perform the necessary data management functions throughout the field (100). The surface unit (134) may be a manual or automatic system. The surface unit (134) may be operated and/or adjusted by a user.
The surface unit (134) may be provided with a transceiver (137) to allow communications between the surface unit (134) and various portions of the field (100) or other locations. The surface unit (134) may also be provided with or functionally connected to one or more controllers for actuating mechanisms at the field (100). The surface unit (134) may then send command signals to the field (100) in response to data received. The surface unit (134) may receive commands via the transceiver or may itself execute commands to the controller. A processor may be provided to analyze the data (locally or remotely) and make the decisions and/or actuate the controller. In this manner, the field (100) may be selectively adjusted based on the data collected. This technique may be used to optimize portions of the operation, such as controlling wellhead pressure, choke size or other operating parameters. These adjustments may be made automatically based on computer protocol, and/or manually by an operator. In some cases, well plans may be adjusted to select optimum operating conditions, or to avoid problems.
As shown, the sensor (S) may be positioned in the production tool (106) or associated equipment, such as the christmas tree, gathering network, surface facilities and/or the production facility, to measure fluid parameters, such as fluid composition, flow rates, pressures, temperatures, and/or other parameters of the production operation.
While
The field configuration in
The respective graphs of
Data plots (308.1-308.3) are static data plots that may be generated by the data acquisition tools (302.1-302.4), respectively. Static data plot (308.1) is a seismic two-way response time. Static plot (308.2) is core sample data measured from a core sample of the formation (304). Static data plot (308.3) is a logging trace. Production decline curve or graph (308.4) is a dynamic data plot of the fluid flow rate over time, similar to the graph (206) of
The subterranean formation (304) has a plurality of geological formations (306.1-306.4). As shown, the structure has several formations or layers, including a shale layer (306.1), a carbonate layer (306.2), a shale layer (306.3) and a sand layer (306.4). A fault line (307) extends through the layers (306.1-306.2). The static data acquisition tools are adapted to take measurements and detect the characteristics of the formations.
While a specific subterranean formation (304) with specific geological structures is depicted, it will be appreciated that the field may contain a variety of geological structures and/or formations, sometimes having extreme complexity. In some locations, typically below the water line, fluid may occupy pore spaces of the formations. Each of the measurement devices may be used to measure properties of the formations and/or its geological features. While each acquisition tool is shown as being in specific locations in the field, it will be appreciated that one or more types of measurement may be taken at one or more location across one or more fields or other locations for comparison and/or analysis.
The data collected from various sources, such as the data acquisition tools of
Data may be collected by various sensors, for example, during drilling operations. Specifically, drilling tools suspended by a rig may advance into the subterranean formations to form a wellbore (i.e., a borehole). The borehole may have a trajectory in the subterranean formations that is vertical, horizontal, or a combination thereof. Specifically, the trajectory defines the path of the drilling tools in the subterranean formation. A mud pit (not shown) is used to draw drilling mud into the drilling tools via flow line for circulating drilling mud through the drilling tools, up the wellbore and back to the surface. The drilling mud is usually filtered and returned to the mud pit. Occasionally, such mud invades the formation surrounding the borehole resulting in an invasion. Continuing with the discussion of drilling operations, a circulating system may be used for storing, controlling, or filtering the flowing drilling mud. The drilling tools are advanced into the subterranean formations to reach reservoir. Each well may target one or more reservoirs.
The drilling tools are preferably adapted for measuring downhole properties using logging while drilling tools. Specifically, the logging while drilling tools include sensors for gathering well logs while the borehole is being drilled. In one or more embodiments, during the drilling operations, the sensors may pass through the same depth multiple times. The data collected by the sensors may be similar or the same as the data collected by the sensors discussed below with reference to
Each wellsite (402) has equipment that forms a wellbore (436) (i.e., borehole) into the earth. The wellbores extend through subterranean formations (406) including reservoirs (404). These reservoirs (404) contain fluids, such as hydrocarbons. The wellsites draw fluid from the reservoirs and pass them to the processing facilities via surface networks (444). The surface networks (444) have tubing and control mechanisms for controlling the flow of fluids from the wellsite to the processing facility (454).
Wellbore production equipment (564) extends from a wellhead (566) of wellsite (402) and to the reservoir (404) to draw fluid to the surface. The wellsite (402) is operatively connected to the surface network (444) via a transport line (561). Fluid flows from the reservoir (404), through the wellbore (436), and onto the surface network (444). The fluid then flows from the surface network (444) to the process facilities (454).
As further shown in
One or more surface units (534) may be located at the field 400, or linked remotely thereto. The surface unit (534) may be a single unit, or a complex network of units used to perform the necessary data management functions throughout the field (400). The surface unit may be a manual or automatic system. The surface unit may be operated and/or adjusted by a user. The surface unit is adapted to receive and store data. The surface unit may also be equipped to communicate with various field equipment. The surface unit may then send command signals to the field in response to data received or modeling performed.
As shown in
The analyzed data (e.g., based on modeling performed) may then be used to make decisions. A transceiver (not shown) may be provided to allow communications between the surface unit (534) and the field (400). The controller (522) may be used to actuate mechanisms at the field (400) via the transceiver and based on these decisions. In this manner, the field (400) may be selectively adjusted based on the data collected. These adjustments may be made automatically based on computer protocol and/or manually by an operator. For example, based on revised log data, commands may be sent by the surface unit to the downhole tool to change the speed or trajectory of the borehole. In some cases, well plans are adjusted to select optimum operating conditions or to avoid problems.
To facilitate the processing and analysis of data, simulators may be used to process the data for modeling various aspects of the operation. Specific simulators are often used in connection with specific operations, such as reservoir or wellbore simulation. Data fed into the simulator(s) may be historical data, real time data or combinations thereof. Simulation through one or more of the simulators may be repeated or adjusted based on the data received.
As shown, the operation is provided with wellsite and non-wellsite simulators. The wellsite simulators may include a reservoir simulator (340), a wellbore simulator (342), and a surface network simulator (344). The reservoir simulator (340) solves for hydrocarbon flow through the reservoir rock and into the wellbores. The wellbore simulator (342) and surface network simulator (344) solves for hydrocarbon flow through the wellbore and the surface network (444) of pipelines. As shown, some of the simulators may be separate or combined, depending on the available systems.
The non-wellsite simulators may include process simulator (346) and economics (348) simulators. The processing unit has a process simulator (346). The process simulator (346) models the processing plant (e.g., the process facilities (454) where the hydrocarbon(s) is/are separated into its constituent components (e.g., methane, ethane, propane, etc.) and prepared for sales. The field (400) is provided with an economics simulator (348). The economics simulator (348) models the costs of part or the entire field (400) throughout a portion or the entire duration of the operation. Various combinations of these and other field simulators may be provided.
Further, the use of dashed lines around a component indicates that even in a single embodiment of the invention a particular component is optional. The use of the dashed lines does not expressly or implicitly indicate that components that do not have dashed lines are not optional in the same or different embodiments of the invention.
In one or more embodiments, in the description, the term, ‘measured depth,’ refers to a length of the borehole to a particular point, as if determined by a measuring stick. In one or more embodiments, measured depth differs from the true vertical depth of the well in all but vertical wells. In one or more embodiments, determining measured depth may be performed by aggregating the lengths of individual joints of drillpipe, drill collars and other drillstring elements when the drill bit is at the particular measured depth.
In one or more embodiments, the system includes a data repository (602) and reservoir geomodeling software (632). Both of these components are discussed below.
In one or more embodiments, the data repository (602) is any type of storage unit and/or device (e.g., a file system, database, collection of tables, or any other storage mechanism) for storing data. Further, the data repository (602) may include multiple different storage units and/or devices. The multiple different storage units and/or devices may or may not be of the same type or located at the same physical site. In one or more embodiments, the data repository includes functionality to store a geological model (606) (discussed below).
A reservoir model (608) is a representation of the physical space of the reservoir, where the physical space is partitioned into cells using a regular (i.e., structured) or irregular (i.e., unstructured) 3D grids. Physical properties (i.e., attributes) such as porosity, permeability and water saturation are assigned to individual cells. A geological model (606) is a reservoir model providing static description of the reservoir. The geological model (606) is a representation of the geology of the oilfield that is constructed from a variety of data gathered from the oilfield. Such data may include, but is not limited to, prior geological knowledge, seismic surveys, surface electromagnetic surveys, well logging and well monitoring, production history, core analysis, etc. The representation of the model may vary widely and may include structural and geological maps, cross-sections, description of the rocks and rock formations, borehole diagrams, etc. In its digital embodiment, the geological model includes a representation of geometry of the subsurface (in a form of a grid of cells) that describes the earth layers and faults, various surfaces describing fluid contacts (such as oil-water contact (OWC) and gas-oil contacts (GOC)). The model may include as data trajectories of the boreholes, various well markers, etc, as well as variety of physical properties inside the grid cells or on the surfaces. The physical properties may include porosity, permeability, resistivity, etc.
In one or more embodiments, an invasion object (610) corresponds to a description of an invasion in a borehole. Specifically, the invasion object (610) stores information describing a particular movement of fluid into the subsurface formation. In one or more embodiments, the invasion object (610) may store information about a current invasion in the borehole and/or a simulation of a possible invasion that may occur. A current invasion is one that has or is in the process of occurring. If the invasion object (610) provides information about a current invasion, the data for the invasion object may be generated automatically using oilfield data gathered directly from sensors at the oilfield. The following is a discussion of the primitives of the invasion object (610) from the fundamental element of the invasion object to the more complex primitive.
In one or more embodiments, an invasion object (610) includes at least one invasion profile definition (624.1, 624.2). An invasion profile definition (624.1, 624.2) provides a description of the invasion at a particular moment in time and at a particular measured depth. Specifically, the invasion profile definition (624.1, 624.2) describes the edge of the shape of the invasion at a constant time value for a constant measured depth value. In other words, the invasion profile definition describes a line denoting an edge of the shape of the invasion. In one or more embodiments, the shape of the invasion may be, for example, a teardrop shape, an arbitrary shape, a circle shape, or another defined shape.
In one or more embodiments, the edge of the shape of the invasion is defined as one or more parameters (630) in the invasion profile definition (624.1, 624.2). The parameter(s) (630) may include a shape identifier and edge parameters in one or more embodiments. The shape identifier uniquely identifies the shape of the invasion. For example, the shape identifier may define whether the shape is a teardrop shape, an arbitrary shape, a circle shape, or another defined shape. The edge parameters describe the size and major points of the shape.
For example, for a teardrop shape, the edge parameters may include three lengths. The first length represents a distance from a focus to each of two opposite points that are equidistant to the focus. The second length and third length represent two different distances from the same focus to two additional points that are opposite each other and a ninety-degree angle from the first length. In one or more embodiments, the focus is the trajectory of the borehole at a particular measured depth. Alternatively, the focus may be offset from the trajectory. When the focus is offset from the trajectory, the parameter(s) (630) may include an offset value.
As another example, for a circle shape, an edge parameter may be a radius of the circle. As another example, for an arbitrary shape, the edge parameters may represent any number of control points along the edge of the shape that describing a closed region. In one or more embodiments, for an arbitrary shape, each control point is defined using a theta and radius value. The radius is the distance from the borehole trajectory at the particular measure depth to the control point. The theta value defines an angle to the control point. In one or more embodiments, the edge of the shape is interpolated between the control points. For example, a Linear, Hermite, or any other method may be used to interpolate the edge of the shape from the control points.
In one or more embodiments, the invasion profile definition (624.1, 624.2) may additionally or alternatively include a dip value (626) and an azimuth value (628). The dip value and the azimuth value together describe the position of the edge of the shape in the three-dimension space of the formation relative to the trajectory of the borehole at the particular measured depth. In one or more embodiments, the dip value (626) defines the dip of the shape of the invasion at the particular measured depth. Specifically, the dip is an angle of descent relative to a horizontal plane. In one or more embodiments, the dip value is a value between zero and ninety degrees. In one or more embodiments, the azimuth value specifies the azimuth of the edge of the shape. The azimuth is an angle defining the direction of the dip as projected onto the horizontal plane. Although the above describes using a dip and azimuth to define a position of the profile in the three-dimensional space of the formation, other techniques may be used without departing from the scope of the claims.
Continuing with
In one or more embodiments, an invasion front definition (616.1, 616.2) describes an invasion front. An invasion front is a closed volume along a range of measured depths. An invasion front may be defined as the closed volume between the trajectory of the borehole and an invasion shape. Alternatively, the invasion from may be defined as the closed volume between two invasion shapes. Thus, the invasion front definition (616.1, 616.2) may include one or two invasion shape definitions in one or more embodiments. If the invasion front definition (616.1, 616.2) includes a single invasion shape definition (620.1, 620.2), then the invasion front is the volume between the trajectory and the invasion shape along the range of measure depths defined by the invasion shape definition (620.1, 620.2). In one or more embodiments, if the invasion front definition includes two invasion shape definitions (620.1, 620.2), the two invasion shape definitions (620.1, 620.2) are defined for the same range of measured depths. Further, one invasion shape definition may be inside or closer to the borehole trajectory than another invasion shape. The inside invasion shape may be the same type or a different type than the outside invasion shape. For example, the inside invasion shape may be a teardrop shape while the outside invasion shape is an arbitrary shape.
In addition to invasion shape definition(s) (620.1, 620.2), an invasion front definition includes physical property values (622). The property values (622) describe the properties of the fluid in the invasion front. In one or more embodiments, the property values are constant throughout in the invasion front. In one or more embodiments, the property values may include related water saturation, salt concentration in the invasion front and other values defining the fluid of the invasion front including horizontal resistivity or conductivity, vertical resistivity or conductivity, density, etc.
In one or more embodiments, multiple invasion front definitions (618.1, 618.2) may be defined for the same range of measured depths. For example, one invasion front definition (618.1, 618.2) may describe an invasion front that is inside another invasion front. The inside invasion front may have different property values than the outside invasion front.
In one or more embodiments, the one or more invasion front definitions (618.1, 618.2) that are all defined for the same range of measured depths are grouped into an invasion zone definition (616.1, 616.2). An invasion zone definition (616.1, 616.2) represents the invasion along the particular range of measured depths.
In one or more embodiments, one or more invasion zones definitions (616.1, 616.2) may be combined into an invasion event definition (612.1, 612.2). An invasion event definition (612.1, 612.2) describes the invasion at a particular moment in time. Specifically, whereas an invasion is a movement of fluid into the formation surrounding the wellbore over time, an invasion event definition (612.1, 612.2) provides a snapshot of the invasion at the particular moment.
In one or more embodiments, the invasion event definition includes a timestamp (614) defining the particular moment. The timestamp (614) defines the time of the invasion event. The timestamp (614) may specify an actual time value or a relative time value. For example, the timestamp may be defined in terms of Greenwich Mean Time, Unix time, a number whereby each invasion event in the invasion object as a sequential number, or any other type of timestamp. Further, the timestamp may specify when the invasion event occurred or when the invasion event was recorded (e.g., by sensors, by the surface unit, etc.).
In one or more embodiments, multiple invasion events may be combined into an invasion object (610). The invasion object (610) describes the invasion over a period of time.
While
Continuing with
The reservoir modeling package (636) corresponds to hardware and/or software for modeling the properties of the oilfield. Specifically, the reservoir modeling module may include functionally to generate and update the reservoir model (608). For example, the reservoir modeling package may include one or more of the various simulators (e.g., economics simulator, process simulator, wellbore simulator, surface network simulator, reservoir simulator) discussed above and in
In one or more embodiments, the invasion modeling module (634) corresponds to hardware and/or software for modeling an invasion event. Specifically, the invasion modeling module (634) may be a plug-in to the reservoir modeling package (636), a part of the reservoir modeling package (636), or separate from the reservoir modeling package.
The invasion modeling module (634) includes functionality to obtain data from the oilfield and/or from a historical oilfield and generate an invasion event. The invasion modeling module (634) includes functionality to generate the invasion event automatically (e.g., directly from data gathered from the oilfield and the reservoir model (608)) and/or with input from a user. In one or more embodiments, the invasion modeling module (634) includes a fluid flow simulator (642). The fluid flow simulator (642) includes functionality to simulate the flow of fluid. Specifically, the fluid flow simulator (642) includes functionality to simulate how the mud flows or invades the formation surrounding the borehole.
Continuing with
Additionally, in one or more embodiments, the user interface (638) includes functionality to display the invasion event within the geological context of the oilfield. Specifically, the user interface (638) includes functionality to present the invasion with the properties of the wellbore and the reservoir. The properties displayed may include, for example, resistivity, and other properties of the wellbore and surrounding formation. By combining the presentation of the invasion with the presentation of the reservoir model, a user may be able to have a more accurate depiction of the reservoir.
Although
By way of an example, consider the scenario in which the perturbation is a shape change of the borehole. In other words, the cylindrical model is to represent a portion of the borehole that may not be a cylindrical shape, but rather have one or more cross sections with irregular sides. In such a scenario, the perturbation object may be a borehole object with the properties and parameters describing the shape change of the borehole.
While
In 701, oilfield data is obtained from a wellsite in one or more embodiments. In particular, in one or more embodiments, data is gathered from various sensors and equipment distributed throughout the oilfield. Such data, sensors, and equipment may be gathered and include the data discussed above with reference to
In one or more embodiments, the oilfield data includes data obtained from the logging while drilling tool. The logging while drilling tool may gather measurements at different measured depths in the wellbore at a single moment in time. Further, the logging while drilling tool may gather measurements for the same measured depth at different times. For example, the logging while drilling tool may make multiple passes through the same point along the trajectory of the borehole. Such multiple passes may be, for example, the first time when the drilling bit reaches the depth, each time the drill string is pulled completely or partially out of the borehole, and during the tripping process. In one or more embodiments, measurements may also be taken over time while the logging while drilling is stationary. In such a scenario, the measurements may be with respect to time only. In one or more embodiments, the data is recorded and indexed by time and/or by depth. Using the recorded time indexed data, the invasion can be reconstructed.
In 703, in the reservoir modeling package, a reservoir model is generated in one or more embodiments. In one or more embodiments, generating the reservoir model is performed using techniques known in the art.
In 705, an invasion object is generated in one or more embodiments. The invasion object may be generated using the data from the logging while drilling or wireline or testing tool. Each moment in time may be stored as a different invasion event in the invasion object. For each invasion event, for example, an algorithm may be executed to infer the parameters of the formation including the geometry of each invaded zone, the resistivity of the invaded formation, and any offset from the center of the borehole. The algorithm may account for positions of formation boundaries, faults, and properties of formation layers near the particular range of measured depths for the invaded zone. Further, in one or more embodiments, the invasion object is generated with a different scale than the reservoir model. Specifically, the invasion object may be generated at a much smaller scale than the reservoir model, thereby providing more detail for the invasion object.
One method of generating an invasion object uses inversion. Inversion is a technique of generating a model based on acquired data. Specifically, a model is generated that fits the acquired data. The inversion-based workflow and algorithms are optimized based on measurement sensitivities. The workflow and algorithms are used to interpret the data and build reservoir models with characterization of the formation geometry and properties, invasion size, shape and properties. Inversion may use a Gauss-Newton algorithm to minimize a cost function. The cost function represents the error function and weighted sum of misfit between the measurements and the modeled tool responses, with appropriate regularization functions used to construct parametric interpretation model. In case of invaded formation, the model parameters may include the reservoir geometry (e.g., position of boundaries and faults), properties (e.g., water saturation, permeability or porosity or derived properties such as resistivity), and invasion geometry (e.g., tear-drop invasion, elliptical shape defined by semi-axes) and invasion properties such as resistivity. In addition, depending on measurements used, the borehole may be included in the model.
Besides the Gauss-Newton algorithm, alternative deterministic or probabilistic approaches are possible. Workflow may re-separate shallow information from deep information to ensure models are built that is consistent with all the data. The shallow measurements or information are more sensitive to formation near the wellbore are used to characterize the invasion. The deep measurements or information are used to characterize the “virgin” (i.e., uninvaded) formation and reservoir geometry, such as a distance to boundaries. A inversion workflow may include the following steps: (1) from deep sensing measurements, invert the distance to nearby boundaries and formation properties thereby building a one dimensional model; (2) using shallow measurements, invert the inversion profile and properties for given layered background model from step (1); and (3) compose a two dimensional and/or a three dimensional model from two previous steps and process the data with inversion to build the model. The model that is built in (3) may be built to include formation parameters (e.g., distance to boundaries, layer thicknesses and properties) and invasion parameters (e.g., invasion size, shape, and properties) and, if there is sensitivity in data, borehole model parameters (e.g., size of the borehole, eccentering and borehole mud properties). Additional workflows may be used that integrate multiple measurements with data acquired at different times. Such data that is acquired at different times includes data that follows the invasion. In these cases, the workflow and parameterizations may be common formation models and different invasion models. Details of algorithm used may depend on measurements used and the measurement's sensitivities.
Alternatively or additionally, a physics based simulation may be used to create the invasion object. In physics based simulation, an invasion object is created based, in part on data acquired from the formation using physics and other simulation knowledge. The physics based simulation may be used to forward model the invasion object. Specifically, generating the invasion object may include performing the following. Acquired data may be analyzed to create an initial invasion object. Log data is gathered from drilling the borehole. The log data may be gathered during or after drilling the borehole. Synthetic log data is generated from the initial invasion object using a physics based simulation. The log data is compared with the synthetic log data to identify any discrepancies. Based on any discrepancies a shape or a physical property or both of the initial perturbation object is modified to create a revised invasion object. The above steps may repeat one or more times until a discrepancy does not exist, is not discovered, or is within an allowed margin of error.
In one or more embodiments, rather than generating the invasion object as discussed above using the logging while drilling tool, a user may create an invasion object. For example, using the user interface of the reservoir geomodeling package, the user may specify the different definitions (discussed above and in
In 707, a geological model having the invasion object and the reservoir model is displayed in one or more embodiments. For example, a visualization of the invasion may be generated and displayed along the trajectory of the wellbore. The visualization may be displayed with the reservoir model. Thus, in a single display, the user may view the invasion with one or more of a visualization of rock types, faults, permeability of the formation, resistivity, and other properties of the formation and borehole. The visualization may include a time lapse showing a change of the invasion over time (e.g., showing how over time the fluid of the invasion permeates into the formation surrounding the borehole). Although
In 709, a determination is made whether to modify the invasion object in one or more embodiments. In one or more embodiments, the user may decide to change the invasion object. For example, the user may determine that the simulated invasion does not accurately depict the actual invasion.
In such a scenario, in 711, the invasion object is modified. For example, the user may use the user interface to change the invasion object. For example, the user may change the parameters of the invasion profile, remove or add invasion zone, or perform other functions.
In one or more embodiments, 709 and 711 may be performed automatically. For example, after a first pass of the logging while drilling tool the drilling tool, an initial invasion object may be created that reflects an estimated invasion. Creating the initial invasion object may be based on data gathered during the first pass and/or data from similar boreholes. Additionally or alternatively, user input may be used to create the first invasion object. Using the fluid flow simulator, different invasion events for the invasion object may be created. Specifically, the different invasion events reflect an estimate of how the invasion of the fluid may flow into the formation over time.
During a subsequent pass of the logging while drilling tool, additional information may be collected. The additional information reflects how the invasion is actually occurring at a different moment in time. The actual invasion may be compared with the estimated invasion to determine if a discrepancy between the actual and the estimate exists. Specifically, estimate log data values for a well log may be generated based on the invasion events and compared with the actual log data values obtained from the logging while drilling tool. If the estimated invasion accurately capture the actual invasion, then no discrepancy may be deemed to have occurred. However, if a discrepancy exists, then the invasion object is modified based on the discrepancy to reflect the new logging while drilling data. Thus, the invasion object may be iteratively updated until the invasion object accurately reflects the invasion.
In one or more embodiments, inversion and/or physics based simulation may be used to modify the invasion object. Specifically, based on well log data or images, the invasion object geometry and physical properties may be updated using techniques, such as the inversion and/or simulation discussed above.
In 713, revised reservoir properties are calculated in one or more embodiments. In one or more embodiments, the invasion object and/or attributes of the invasion object obtained therefrom may be passed to the reservoir modeling package. The reservoir modeling package may be using the information about the invasion to provide more accurate reservoir data. For example, resistivity data may be adjusted to account for the existence of the invasion and correct well log data for the invasion effect using specialized processing based on modeling and/or inversion. For example, array resistivity measurement deliver multiple logs with different depth of investigation to provide sensitivity to invasion and information necessary to correct the invasion effect, or use the deepest log reading as the “true” resistivity of the “virgin” formation and fluids that are saturating it.
In 715, drilling operations at the wellsite are changed based on the revised reservoir properties in one or more embodiments. Specifically, once the properties of the formation and reservoir are corrected to account for the existence of the invasion, the corrected properties may result in change in how the drilling and/or production operations occur based on a new understanding of the formation. In such a scenario, control signals may be sent to the drilling or production tools to modify the equipment at the oilfield. For example, a signal may be sent to the bit to change the angle or speed of the rotation of the bit.
In one or more embodiments, 707-713 may correspond to integrating the invasion object with the reservoir model and forming the geological model. Further, although
Embodiments may be implemented on virtually any type of computer regardless of the platform being used. For example, as shown in
Software instructions in the form of computer readable program code to perform embodiments may be stored, in whole or in part, temporarily or permanently, on a computer readable medium such as a compact disc (CD), a diskette, a tape, physical memory, or any other computer readable storage medium. Specifically, the software instructions may correspond to computer readable program code that, when executed by a processor(s), is configured to perform embodiments. In one or more embodiments, the computer readable medium is a non-transitory computer readable medium.
Further, one or more elements of the aforementioned computer system (1600) may be located at a remote location and connected to the other elements over a network. Further, embodiments may be implemented on a distributed system having a plurality of nodes, where each portion may be located on a different node within the distributed system. In one or more embodiments, the node corresponds to a computer system. Alternatively, the node may correspond to a processor with associated physical memory. The node may alternatively correspond to a processor or micro-core of a processor with shared memory and/or resources.
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 integrating invasion modeling with reservoir modeling. Accordingly, all such modifications are intended to be included within the scope of this disclosure as defined in the following claims. In the claims, means-plus-function clauses are intended to cover the structures described herein as performing the recited function and not only structural equivalents, but also equivalent structures. Thus, although a nail and a screw may not be structural equivalents in that a nail employs a cylindrical surface to secure wooden parts together, whereas a screw employs a helical surface, in the environment of fastening wooden parts, a nail and a screw may be equivalent structures. It is the express intention of the applicant not to invoke 35 U.S.C. § 112, paragraph 6 for any limitations of any of the claims herein, except for those in which the claim expressly uses the words ‘means for’ together with an associated function.
This application claims priority, pursuant to 35 U.S.C. § 119(e), to the filing date of U.S. Patent Application Ser. No. 61/554,197, entitled “SYSTEM AND METHOD FOR MODELING DRILLING MUD INVASION INTEGRATED WITH GEOLOGICAL MODELS AND WELL LOG MODELING AND INVERSION” filed on Nov. 1, 2011, which is hereby incorporated by reference in its entirety.
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| Number | Date | Country | |
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| 20130110486 A1 | May 2013 | US |
| Number | Date | Country | |
|---|---|---|---|
| 61554197 | Nov 2011 | US |
