GEOSTEERING DIFFICULTY INDEX

Abstract

Systems and methods for determining a geosteering difficulty index are disclosed. The methods may include obtaining, using a well logging tool, a typelog recorded in a first borehole penetrating a subterranean region of interest and, using a well log interpretation system, identifying at least one geological layer of interest from the typelog, determining a plurality of typelog indices based on typelog values within and adjacent to the at least one geological layer and determining a geosteering difficulty index (“GDI”) based on the plurality of typelog indices. The methods further include determining, using a borehole planning system, a borehole plan for a second borehole based, at least in part, on the GDI.

Description

BACKGROUND

Accurate well placement by targeting a stratigraphic interval during the lateral phase of drilling is an important requirement for the success of highly deviated and horizontal wells, particularly in unconventional reservoirs. A high-confidence interpretation of the subsurface is needed to direct the bottom hole assembly in the direction of the target formation dip. However, geosteering within unconventional reservoirs is often subject to a high degree of non-uniqueness—made greater when using only one measurement, such as a gamma ray (GR) log, to make drilling decisions.

Geosteering is necessary in a real time drilling operation due to uncertainty in the depths of structures in a geological model and the location of the drill bit. Geosteering requires a geological model of the target zone. From this model and existing log data, predicted log readings may be generated for different drill bit positions within the subsurface. During drilling, new log readings are observed at or near the drill bit which allow for an updated interpretation, including model and drill bit depths, by comparing the predicted and the observed logs. The drilling direction is then adjusted based on interpretation of the current subsurface location and desired target. Furthermore, during geosteering, estimates of the true depth and the lateral location of a drill bit may contain errors, thus leading to uncertainty in the location of the drill bit with respect to the geological model. Often, this uncertainty is of the same magnitude as the thickness of the geological structures being targeted.

SUMMARY

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.

In general, in one aspect, embodiments disclosed herein relate to methods for determining a geosteering difficulty index. The methods include obtaining, using a well logging tool, a typelog recorded in a first borehole penetrating a subterranean region of interest, and, using a well log interpretation system: identifying at least one geological layer of interest from the typelog, determining a plurality of typelog indices based on typelog values within and adjacent to the at least one geological layer, and determining a geosteering difficulty index (“GDI”) based on the plurality of typelog indices. The methods further include determining, using a borehole planning system, a borehole plan for a second borehole based, at least in part, on the GDI.

In general, in one aspect, embodiments disclosed herein relate to a system for determining a geosteering difficulty index. The system includes a well logging tool configured to obtain a typelog recorded in a first borehole penetrating a subterranean region of interest; a well log interpretation system configured to: identify at least one geological layer of interest from the typelog, determine a plurality of typelog indices based on typelog values within and adjacent to the at least one geological layer, and determine a GDI based on the plurality of typelog indices. The system further includes a borehole planning system configured to determine a borehole plan for a second borehole based, at least in part, on the GDI.

Other aspects and advantages of the claimed subject matter will be apparent from the following description and the appended claims.

BRIEF DESCRIPTION OF DRAWINGS

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.

FIG. 1 shows a drilling system in accordance with one or more embodiments.

FIG. 2 shows an edge index versus depth in accordance with one or more embodiments.

FIG. 3 shows signal symmetry and slope versus depth in accordance with one or more embodiments.

FIG. 4 shows a geosteering difficulty index versus depth in accordance with one or more embodiments.

FIG. 5 shows a flowchart of a method in accordance with one or more embodiments.

FIG. 6 shows a computer system in accordance with one or more embodiments.

DETAILED DESCRIPTION

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.

In the following description of FIGS. 1-6, any component described with regard to a figure, in various embodiments disclosed herein, may be equivalent to one or more like-named components described with regard to any other figure. For brevity, descriptions of these components will not be repeated with regard to each figure. Thus, each and every embodiment of the components of each figure is incorporated by reference and assumed to be optionally present within every other figure having one or more like-named components. Additionally, in accordance with various embodiments disclosed herein, any description of the components of a figure is to be interpreted as an optional embodiment which may be implemented in addition to, in conjunction with, or in place of the embodiments described with regard to a corresponding like-named component in any other figure.

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 “well log” includes reference to one or more of such well logs.

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 flowcharts 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 flowcharts.

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.

It is desirable to drill highly deviated and horizontal boreholes to enhance production. Doing so requires geosteering during which logs predicted from a geological model and observed logs are compared. Predicting the difficulty of geosteering prior to drilling is also desirable. The difficulty prediction may be used to modify the drilling plan, for example by predicting and recording a different type of well log, or perhaps modifying the planned borehole trajectory within the reservoir. Whereas planning a geosteering operation and executing the geosteering to put the well on a desired trajectory within the reservoir is an established process, the disclosed methods and system constitute an improvement on this established process by predicting the degree of geosteering difficulty by using typewell logs. The methods may include the use of the typewell logs to determine several intermediate parameters that measure the uncertainty in a geosteering operation, along with a final parameter known as the Geosteering Difficulty Index (“GDI”). The GDI may be used to visualize hazards and guide geosteering within a given interval.

Before further presenting the proposed system and methods, the essential elements of a drilling system within a borehole are presented for context.

FIG. 1 shows a drilling system (100) in accordance with one or more embodiments. Although the drilling system (100) shown in FIG. 1 is used to drill a borehole on land, the drilling system (100) may also be a marine borehole drilling system. The example of the drilling system (100) shown in FIG. 1 is not meant to limit the present disclosure.

As shown in FIG. 1, a borehole (117) may be drilled along a borehole path (103) by a drill bit (105) attached by a drillstring (106) to a drill rig located on the surface (107) of the earth. The drill rig may include framework, such as a derrick (108), to hold drilling machinery. The top drive (110) sits at the top of the derrick (108) and provides torque, typically a clockwise torque, via the drive shaft (112) to the drillstring (106) in order to drill the borehole (117). The borehole (117) may traverse a plurality of overburden (114) layers and one or more cap-rock (116) layers to a hydrocarbon reservoir (104) within the subterranean region of interest (102). The borehole path (103) may be a curved borehole path, or a straight borehole path. All or part of the borehole path (103) may be vertical, and some borehole paths (103) may be deviated or have horizontal sections. Boreholes may deviate from vertical unintentionally due to dips in the layers through which they are drilled. Alternately, boreholes can be deliberately deviated by the use of a whipstock, bent-sub, rotary steerable tool, or other steering mechanism. Boreholes may be deviated to increase the length of the borehole (117) traversing a hydrocarbon reservoir (104), to intersect fractures, or to avoid subsurface structures that impede drilling. Directional drilling optimizes drilling parameters such as weight on bit (WOB) and rotary speed to steer the drill bit (105) in a particular direction. Although steering is typically associated with deviated boreholes, it may also be used to keep a borehole trajectory vertical when subsurface formations cause deviation in the direction of travel of the drill bit (105).

The most common way to deviate a borehole is to use a rotary steerable downhole tool place between the drill bit and the remainder of the bottom-hole assembly and drillstring. The rotary steerable downhole tool may use pads pressed against the borehole wall to push the drill bit in the desired direction. Alternatively, a bet-sub includes a mud motor and a bend, typically of 1 or 2 degrees near the drill bit (105) that alters the borehole trajectory. By pumping mud through the mud motor, the drill bit (105) drills in the direction it points (but the drillstring (106) does not rotate). Once a desired direction is achieved, that direction may be maintained by rotating the entire drillstring (106) so that the drill bit (105) maintains the desired direction. Directional drilling is common, e.g., in shale reservoirs because it allows drillers to place the borehole (117) in contact with the most productive reservoir rock.

Prior to the commencement of drilling, a borehole plan may be generated. The borehole plan guides where and how the borehole will be drilled into the subsurface. The borehole plan may include a starting surface location of the borehole (117), or a subsurface location within an existing borehole (117), from which the borehole (117) may be drilled. Further, the borehole plan may include a terminal location that may intersect with the target zone (118), e.g., a targeted hydrocarbon-bearing formation, and a planned borehole path (103) from the starting location to the terminal location. In other words, the borehole path (103) may intersect a previously located hydrocarbon reservoir (104).

Typically, the borehole plan is generated based on the best available information at the time of planning from a geophysical model, geomechanical models encapsulating subterranean stress conditions, the trajectory of any existing boreholes (117) (which one may desire to avoid), and the existence of other drilling hazards, such as shallow gas pockets, over-pressure zones, and active fault planes.

The borehole plan may include borehole geometry information such as borehole diameter and inclination angle. If casing (124) is used, the borehole plan may include casing type or casing depths. Furthermore, the borehole plan may consider other engineering constraints such as the maximum borehole curvature (“dog-log”) that the drillstring (106) may tolerate and the maximum torque and drag values that the drilling system (100) may tolerate.

A geosteering system (150) may be used to generate the borehole plan. The geosteering system (150) may comprise one or more computer processors in communication with computer memory containing the geophysical and geomechanical models, information relating to drilling hazards, and the constraints imposed by the limitations of the drillstring (106) and the drilling system (100). The geosteering system (150) may further include dedicated software to determine the planned borehole path (103) and associated drilling parameters, such as the planned borehole diameter, the location of planned changes of the borehole diameter, the planned depths at which casing (124) will be inserted to support the borehole (117) and to prevent formation fluids entering the borehole (117), and the drilling mud weights (densities) and types that may be used during drilling the borehole (117).

The geosteering system (150) further contains information related to a geological model of the subsurface, observed logs, and estimate of uncertainty around the current drilling location and drilling direction. The geosteering system (150) allows a drilling engineer or other operator to visualize and manipulate the geological model and predicted and observed well logs to determine the location of the drill bit in relation to the geological model. The geosteering system (150) further allows the drilling engineer or other operator to control the drill bit (105) based on the logging measurements in the borehole (117) and adjust the trajectory of the borehole (117) as it drilled within a hydrocarbon reservoir (104). The operation of the geosteering system (150), i.e., geosteering, may be used while the borehole is being drilled to ensure the borehole (117) is drilled into a particular section of a hydrocarbon reservoir (104). This may be done to minimize gas or water breakthrough and maximize economic production from the well.

Many factors contribute to the difficulty of geosteering in real time. High on the list among them is the relative positioning of a drill bit (105) within a desired geological target. A target window of a few feet above and below the geological target center may be acceptable during a geosteering operation. For example, a driller may desire to drill a well 10 feet below the upper boundary of a hydrocarbon reservoir (104) and have a target window of 5 feet. This allows for placing the well between 5 and 15 feet below the upper boundary of the hydrocarbon reservoir (104).

Geosteering may entail the utilization of typewell logs in order to ascertain the stratigraphic position in a well during horizontal drilling. “Typewells,” also known as “typelogs,” are offset well logs, typically including a gamma ray curve. A geosteering system may allow a driller to visualize the subsurface geological model and typelog data simultaneously. The geosteering system may be located at the well site. It may also be located remotely, in which case it is controlled with communications via a network.

A borehole (117) may be drilled using a drill rig that may be situated on a land drill site, an offshore platform, such as a jack-up rig, a semi-submersible, or a drill ship. The drill rig may be equipped with a hoisting system, such as a derrick (108), which can raise or lower the drillstring (106) and other tools required to drill the well. The drillstring (106) may include one or more drill pipes connected to form a conduit and a bottom hole assembly (BHA) (120) disposed at the distal end of the drillstring (106). The BHA (120) may include a drill bit (105) to cut into subsurface (122) rock. The BHA (120) may further include measurement tools, such as a measurement-while-drilling (MWD) tool and logging-while-drilling (LWD) tool. MWD tools may include sensors and hardware to measure downhole drilling parameters, such as the azimuth and inclination of the drill bit (105), the WOB, and the torque. The LWD measurements may include sensors, such as resistivity, gamma ray, and neutron density sensors, to characterize the rock formation surrounding the borehole (117). Both MWD and LWD measurements may be transmitted to the surface (107) using any suitable telemetry system, such as mud-pulse or wired-drill pipe, known in the art.

To start drilling, or “spudding in” the well, the hoisting system lowers the drillstring (106) suspended from the derrick (108) towards the planned surface location of the borehole (117). An engine, such as a diesel engine, may be used to supply power to the top drive (110) to rotate the drillstring (106). The weight of the drillstring (106) combined with the rotational motion enables the drill bit (105) to drill the borehole (117).

The near surface is typically made up of loose or soft sediment or rock, so large diameter casing (124), e.g., “base pipe” or “conductor casing,” is often put in place while drilling to stabilize and isolate the borehole (117). 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 (107) of the earth.

Drilling may continue without any casing (124) once deeper, or more compact rock is reached. While drilling, a drilling mud system (126) may pump drilling mud from a mud tank on the surface (107) 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 (106) withdrawn from the borehole (117). Sections of casing (124) may be connected and inserted and cemented into the borehole (117). Casing string may be cemented in place by pumping cement and mud, separated by a “cementing plug,” from the surface (107) 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 (124) and the borehole 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 borehole (117) and the pressure on the borehole walls from surrounding rock.

Due to the high pressures experienced by deep boreholes (117), a blowout preventer (BOP) may be installed at the wellhead to protect the rig and environment from unplanned oil or gas releases. As the borehole (117) becomes deeper, both successively smaller drill bits (105) and casing string may be used. Drilling deviated or horizontal boreholes (117) may require specialized drill bits or drill assemblies.

In conjunction with a geosteering system, a drilling system (100) may be disposed in communication with other systems in the well environment. The drilling system (100) may include computers used to 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 WOB, drill revolutions-per-minute (RPM), flow rate of the mud pumps (GPM), and rate of penetration (ROP) of the drilling operation. Each sensor may be positioned or configured to measure a desired physical stimulus. Drilling may be considered complete when a target zone (118) is reached, or the presence of hydrocarbons is established.

Several intermediate parameters may be derived from typewell logs. In some embodiments, an Edge Index (EI) may be determined. EI accounts for the size of the geosteering window and the planned well position within it. The geosteering window is a window of total spatial tolerance, i.e., the sum of the distance above and below a target. The smaller the window, or the closer the borehole (117) is from one of the edges, and the higher the edge difficulty index. An example of the EI is shown in FIG. 2. The EI value is plotted on the vertical axis while proximity to boundaries of the geosteering window is plotted on the horizontal axis.

EI is represented by the following equation:

$\begin{array}{cc}\mathrm{EI}\left(P,D\right)=\frac{D}{D_{\lim }·M^2}·P^2-\frac{2D}{D_{\lim }·M}P+\left[{\left(\frac{2}{D_{\lim }·M}\right)}^2+\frac{4\left(D-1\right)}{{\left(D_{\lim }·M\right)}^2}\right]·\frac{D_{\lim }·M^2}{4},\left\{0<P\le M\right\}& \left(\mathrm{Eq}.1\right)\end{array}$ $\frac{D}{D_{\lim }·M^2}·P^2-\frac{2D\left(D-M\right)}{D_{\lim }·M^2}P+\left[{\left(\frac{2D\left(D-M\right)}{D_{\lim }·M^2}\right)}^2+\frac{4T\left(10-D\right)}{{\left(D_{\lim }·M\right)}^2}\right]·\frac{D_{\lim }·M^2}{4D},\left\{\left(D-M\right)\le P<D\right\}h,\left\{M<P<D-M\right\}$

where EI is an explicit function of two other parameters, P and D. P is the borehole position inside the target window. D is the TVT between the upper and lower boundaries of the window. h is represented as follows:

$h\left(D,D_{\lim }\right)=\left\{\begin{array}{cc}0,& D\ge D_{\lim }\\ \frac{\left(D_{\lim }-D\right)}{D_{\lim }},& D<D_{\lim }\end{array}\right\}$

There are other predetermined parameters, implicit in the equation as bounds that determine which of the three lines of Eq. 1 to evaluate for EI. Among these predetermined parameters is M, which measures the side margins. The side margins are a predetermined distance from the boundaries of the window (e.g., the upper and lower 3 feet of the window). The utility of M is to account for the risk of exiting the window. In the Eq. 1 it triggers the exponential increase in the EI near the boundaries. Another predetermined parameter is D, the thickness of the window in the interval being drilled. Yet another predetermined parameter set by a user is D_lim, the window thickness limit. Since window thickness changes based on the assumed geological scenario, D_lim acts as a reference point (e.g., 20 feet) to which is compared the input D. h is the default “base value” for the EI function, and is used in the case of P exceeding D. As can be seen from Eq. 1, when P exceeds D, the value of EI is assigned the constant value of h. The functional form of EI is quadratic when the drilled borehole (117) is within a predetermined marginal thickness inside the window. In this case, the constants, M, D, and P lead to the quadratic form.

FIG. 2 shows an embodiment of the EI obtained from Eq. 1 for a particular well being drilled for a range of target locations. In this case, the graph shows how EI increases closer to both the target top (202) and the target bottom (204) of an interval being drilled in a horizontal well.

A second parameter that may be derived from typewell logs is the Signal Symmetry and Slope Index (SSI), which describes the positional confidence inside the target interval. The SSI is itself composed to two other indices, symmetry and slope. A higher value symmetry and/or a lower value of slope increases the uncertainty in the interpretation due to high levels of non-uniqueness. The SSI is designed to switch between symmetry and slope, giving priority to symmetry at saddle points of the signal, but defaults to using slope otherwise. A saddle point on the signal log curve is a point with maximum symmetry and thus represents a point with high misinterpretation risk.

The values of the symmetry index, Γ, comes from the Pearson equation, which calculates a correlation coefficient at each point inside the target interval using a number of points above and below each point:

$\begin{array}{cc}\begin{array}{cc}\Gamma =\frac{n\left(\sum A·B\right)-\left(\sum A\right)·\left(\sum B\right)}{\sqrt{\left[n\sum A^2-{\left(\sum A\right)}^2\right]·[n\sum B-{\left(\sum A\right)}^2}},& {\Gamma }_N=\frac{\Gamma +1}{2}\end{array}& \left(\mathrm{Eq}.2\right)\end{array}$

where A represents the points in the typelog above the target point, B represents the points in the typelog below the target point, n represents the total number of points being compared, and Γ_N represents normalized coefficients. “Normalizing” the coefficients ensures that the range of values goes from 0 to 1, rather than −1 to 1, as would normally be the case for correlation coefficients. This converts the symmetry index so that it is defined over the same range as the other indices.

For the slope index, SI, a measure may be determined across the same range of target values as for the symmetry index. At each target point, two slopes may be taken from a predetermined distance above and below the point and averaged together to give an average slope representative of the surrounding trend. This value may then be inverted (multiplied by −1) to reflect its inverse-proportional relationship with difficulty of geosteering and then normalized. A cut-off filter may also be introduced to assign a slope index value of 0 (i.e., very low in difficulty) when gradient is greater than a preset slope of maximum confidence selected by the user. The slope index, SI, may therefore be determined by the following equation:

$\begin{array}{cc}\mathrm{SI}=\frac{\frac{Y_B-Y_S}{X_B-X_S}+\frac{Y_S-Y_A}{X_S-X_A}}{2}·\left(-1\right)& \left(\mathrm{Eq}.3\right)\end{array}$

Here X_A (320) is the x-coordinate of the upper point (i.e., the point above), Y_A(310) is the y-coordinate of the upper point, X_B (324) is the x-coordinate of the lower point (i.e., the point below), Y_B (314) is the y-coordinate of the lower point, X_S (322) is the x-coordinate of the subject point, and Y_S (312) is the y-coordinate of the subject point. The subject point is the point around with the average slope is measured.

A normalized slope SI_N may be obtained from the averaged slope of Eq. 3 via the following equation:

$\begin{array}{cc}{\mathrm{SI}}_N=\left\{\begin{array}{cc}0,& \mathrm{SI}\ge 10\\ \frac{{\mathrm{SI}}_{\max }-\mathrm{SI}}{{\mathrm{SI}}_{\max }},& \mathrm{SI}<10\end{array}\right\}& \left(\mathrm{Eq}.4\right)\end{array}$

Here it can be seen that for an averaged slope value greater than 10, the normalized slope, SI_N, may be set to zero. It must be noted that SI_N is the average of two slopes. For the embodiments presented here, when the average is greater than 10 units of measure per sampling point, the signal's contrast is clearly visible. On the other hand, if the average is below 10 units of measure per sampling interval, the signal's contrast becomes more difficult for the observer to notice. However, the number 10 is not a hard requirement; the number depends on the signal's units and sampling frequency, and may be different for different applications.

For the points X_A, Y_A, X_B, Y_B, X_S, and Y_S presented in FIG. 3, the determined value of SI_N (326) is also pointed out.

Slope may be defined in other ways than that of Equations 3 and 4. For example, a curve may be fit to the signal data around a target point and the slope of that curve may be determined at the target point. Equations 3 and 4 do not limit the possible methods for determining slope.

An example of the symmetry and slope indices is shown in FIG. 3. The value of the indices is on the vertical axis while the horizontal axis presents the range of possible target depth values from the top to the bottom of a formation being drilled. The first curve (300) represents the symmetry index. The second curve (302) represents the slope index. The third curve (304) represents the signal value coming from typelogs. Γ_N (shown by the first curve (300)) oscillates over the range of possible target points being examined. A point with a high value of Γ_N indicates the signal varies symmetrically on either side of that point in the signal. The signal for the embodiment presented here is a smoothed gamma ray log. However, this is not a limitation. The same methods may be applied to any kind of log. SI_N (shown by the second curve (302)) also oscillates between zero and one, with segments exactly equal to zero. The value of SSI is determined by taking the higher value between Γ_N and SI_N.

The final parameter determined by the methods presented here is the GDI. It is obtained by averaging the EI and SSI, with the exception of setting the GDI equal to EI in the case that the EI is greater than the SSI:

$\begin{array}{cc}\mathrm{GDI}=\left\{\begin{array}{cc}\mathrm{EI},& \mathrm{SSI}\le \mathrm{EI}\\ \mathrm{Avg}\left(\mathrm{SSI},\mathrm{EI}\right),& \mathrm{SSI}<\mathrm{EI}\end{array}\right\}& \left(\mathrm{Eq}.5\right)\end{array}$

The GDI is the final parameter to be determined and is used in decision-making. Geologists may use the GDI to visualize the level of confidence in reaching different parts within the target interval during geosteering. The GDI may be applied to a wide range of logs and customized to suit a user's needs. For example, the EI's base value, h, the window thickness limit, D_lim, and the side-margin trigger distance, M, may all be preset differently for each particular application. For instance, the window thickness depends upon the objective of the well. Also, large windows contribute to lower risk of exiting the geosteering window, while smaller windows have a higher risk of exiting the geosteering window.

The GDI is shown in FIG. 4 by the GDI curve (400). It is contrasted with the signal from the typelog that was use to derive the different parameters, which is shown by the signal curve (402) (which is the same curve as (304)). The GDI curve may be used to minimize the uncertainty in borehole placement by choosing a minimum value of the curve as the drilling target.

FIG. 5 present the workflow for methods detailed above. First, in Step 500, a typelog is recorded in a first borehole that penetrates a subterranean region of interest using a well logging tool. The typelog may be a gamma ray log but it is not limited to such a log. It may be any log obtainable in a drilled well. In Step 502, at least one geological layer of interest is identified from the typelog. This geological layer of interest may contain a hydrocarbon reservoir. In Step 504, a plurality of typelog indices is determined from the typelog within or adjacent to the geological layer. The indices may include an Edge Index, a Symmetry Index, and a Slope Index, but it may also contain other indices that allow for improved understanding of uncertainty in a geosteering operation.

In Step 506, a geosteering difficulty index is determined based on the plurality of typelog indices. This is not a limitation, however; other summary indices may be determined from the plurality of typelog indices that give a measure of geosteering difficulty. In Step 508, a borehole plan for a second borehole is determined based, at least in part, on the geosteering difficulty index. For example, during active drilling, if the GDI is high, the drilling operator may choose to deviate the direction of drilling or perhaps backtrack to a higher location in the well and then drill a sidetrack from there.

Implementation of the methods above requires a computer system (602) to execute the calculations, as well as to control the geosteering process. FIG. 6 depicts a block diagram of a computer system (602) used to provide computational functionalities associated with described algorithms, methods, functions, processes, flows, and procedures as described in this disclosure, according to one or more embodiments. The illustrated computer (602) 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 (602) may include 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 (602), including digital data, visual, or audio information (or a combination of information), or a GUI.

The computer (602) 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 (602) is communicably coupled with a network (630). In some implementations, one or more components of the computer (602) 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 (602) 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 (602) 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 (602) can receive requests over network (630) from a client application (for example, executing on another computer (602)) and responding to the received requests by processing the said requests in an appropriate software application. In addition, requests may also be sent to the computer (602) 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.

Each of the components of the computer (602) can communicate using a system bus (603). In some implementations, any or all of the components of the computer (602), both hardware or software (or a combination of hardware and software), may interface with each other or the interface (604) (or a combination of both) over the system bus (603) using an application programming interface (API) (612) or a service layer (613) (or a combination of the API (612) and service layer (613)). The API (612) may include specifications for routines, data structures, and object classes. The API (612) 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 (613) provides software services to the computer (602) or other components (whether or not illustrated) that are communicably coupled to the computer (602). The functionality of the computer (602) may be accessible for all service consumers using this service layer. Software services, such as those provided by the service layer (613), 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 (602), alternative implementations may illustrate the API (612) or the service layer (613) as stand-alone components in relation to other components of the computer (602) or other components (whether or not illustrated) that are communicably coupled to the computer (602). Moreover, any or all parts of the API (612) or the service layer (613) 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.

The computer (602) includes an interface (604). Although illustrated as a single interface (604) in FIG. 6, two or more interfaces (604) may be used according to particular needs, desires, or particular implementations of the computer (602). The interface (604) is used by the computer (602) for communicating with other systems in a distributed environment that are connected to the network (630). Generally, the interface (604) includes logic encoded in software or hardware (or a combination of software and hardware) and operable to communicate with the network (630). More specifically, the interface (604) may include software supporting one or more communication protocols associated with communications such that the network (630) or interface's hardware is operable to communicate physical signals within and outside of the illustrated computer (602).

The computer (602) includes at least one computer processor (605). Although illustrated as a single computer processor (605) in FIG. 6, two or more processors may be used according to particular needs, desires, or particular implementations of the computer (602). Generally, the computer processor (605) executes instructions and manipulates data to perform the operations of the computer (602) and any algorithms, methods, functions, processes, flows, and procedures as described in the instant disclosure.

The computer (602) also includes a memory (606) that holds data for the computer (602) or other components (or a combination of both) that can be connected to the network (630). For example, memory (606) can be a database storing data consistent with this disclosure. Although illustrated as a single memory (606) in FIG. 6, two or more memories may be used according to particular needs, desires, or particular implementations of the computer (602) and the described functionality. While memory (606) is illustrated as an integral component of the computer (602), in alternative implementations, memory (606) can be external to the computer (602).

The application (607) is an algorithmic software engine providing functionality according to particular needs, desires, or particular implementations of the computer (602), particularly with respect to functionality described in this disclosure. For example, application (607) can serve as one or more components, modules, applications, etc. Further, although illustrated as a single application (607), the application (607) may be implemented as multiple applications (607) on the computer (602). In addition, although illustrated as integral to the computer (602), in alternative implementations, the application (607) can be external to the computer (602).

There may be any number of computers (602) associated with, or external to, a computer system containing computer (602), wherein each computer (602) communicates over network (630). 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 (602), or that one user may use multiple computers (602).

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.

Claims

1. A method, comprising: obtaining, using a well logging tool, a typelog recorded in a first borehole penetrating a subterranean region of interest;using a well log interpretation system: identifying at least one geological layer of interest from the typelog,determining a plurality of typelog indices based on typelog values within and adjacent to the at least one geological layer, anddetermining a geosteering difficulty index (“GDI”) based on the plurality of typelog indices; anddetermining, using a borehole planning system, a borehole plan for a second borehole based, at least in part, on the GDI.

2. The method of claim 1, wherein the plurality of typelog indices comprise an edge index, a symmetry index, and a slope index.

3. The method of claim 2, wherein each of the plurality of typelog indices is based, at least in part, on variations of the typelog with depth.

4. The method of claim 1, wherein the at least one geological layer comprises a hydrocarbon reservoir.

5. The method of claim 1, further comprising drilling, using a drilling system, the second borehole guided by the borehole plan.

6. The method of claim 5, wherein drilling comprises using a geosteering system, based, at least in part, on a second typelog recorded in the second borehole during drilling.

7. The method of claim 1, wherein the typelog is a gamma ray log.

8. The method of claim 2, wherein the edge index comprises a quadratic dependence on depth.

9. The method of claim 2, wherein the symmetry index comprises a normalized Pearson correlation coefficient.

10. A system, comprising: a well logging tool configured to obtain a typelog recorded in a first borehole penetrating a subterranean region of interest;a well log interpretation system configured to: identify at least one geological layer of interest from the typelog,determine a plurality of typelog indices based on typelog values within and adjacent to the at least one geological layer, anddetermine a geosteering difficulty index (“GDI”) based on the plurality of typelog indices; anda borehole planning system configured to: determine a borehole plan for a second borehole based, at least in part, on the GDI.

11. The system of claim 10, wherein the plurality of typelog indices comprise an edge index, a symmetry index, and a slope index.

12. The system of claim 11, wherein each of the plurality of typelog indices is based, at least in part, on variations of the typelog with depth.

13. The system of claim 10, wherein the at least one geological layer comprises a hydrocarbon reservoir.

14. The system of claim 10, further comprising drilling, using a drilling system, the second borehole guided by the borehole plan.

15. The system of claim 14, wherein drilling comprises using a geosteering system, based, at least in part, on a second typelog recorded in the second borehole during drilling.

16. The system of claim 11, wherein the typelog is a gamma ray log.

17. The system of claim 12, wherein the edge index comprises a quadratic dependence on depth.

18. The system of claim 12, wherein the symmetry index comprises a normalized Pearson correlation coefficient.