FAST FORMATION DIP ANGLE ESTIMATION SYSTEMS AND METHODS BACKGROUND Modern petroleum drilling and production operations demand a great quantity of information relating to the parameters and conditions downhole. Such information typically includes the location and orientation of the borehole and drilling assembly, earth formation properties, and parameters of the downhole drilling environment. The collection of information relating to formation properties and downhole conditions is commonly referred to as "logging", and can be performed during the drilling process itself (hence the term "logging while drilling" or "LWD," frequently used interchangeably with the term "measurement while drilling" or "MWD"). Various measurement tools exist for use in LWD. One such tool is the resistivity tool, which includes one or more antennas for transmitting an electromagnetic signal into the formation and one or more antennas for receiving a formation response. When operated at low frequencies, the resistivity tool may be called an "induction" tool, and at high frequencies it may be called an electromagnetic wave propagation tool. Though the physical phenomena that dominate the measurement may vary with frequency, the operating principles for the tool are consistent. In some cases, the amplitude and/or the phase of the receive signals are compared to the amplitude and/or phase of the transmit signals to measure the formation resistivity. In other cases, the amplitude and/or phase of multiple receive signals are compared to each other to measure the formation resistivity. When plotted as a function of depth or tool position in the borehole, the logging tool measurements are termed "logs." Such logs may provide indications of hydrocarbon concentrations and other information useful to drillers and completion engineers. In particular, azimuthally-sensitive logs may provide information useful for steering the drilling assembly because they can inform the driller of the bit's direction relative to the orientation of the current bed and nearby bed boundaries, thereby enabling modifications to the drilling program that will provide much more value and higher success than would be the case using only seismic data. However, such information is of limited utility if it cannot be made available to the driller in an expeditious fashion. BRIEF DESCRIPTION OF THE DRAWINGS A better understanding of the various disclosed embodiments can be obtained when the following detailed description is considered in conjunction with the attached drawings, in which: FIG. 1 shows an illustrative logging while drilling (LWD) environment. FIG. 2 shows an illustrative LWD tool mounted along a drillstring. FIG. 3 shows a block diagram of two logging tool modules and a surface system. FIG. 4 shows an illustrative method for fast formation dip angle estimation. It should be understood that the drawings and corresponding detailed description do not limit the disclosure, but on the contrary, they provide the foundation for understanding all modifications, equivalents, and alternatives falling within the scope of the appended claims. DETAILED DESCRIPTION The paragraphs that follow describe illustrative apparatuses, systems and methods for fast formation dip angle estimation. An illustrative drilling environment suitable for using such apparatuses, systems and methods is first described, followed by a description of an illustrative drillstring with a logging while drilling (LWD) tool. The positional relationships between antennas housed within the LWD tool modules are also described and expressed mathematically, as are the effects of these relationships on received signals propagated through the surrounding formation. Several illustrative fast formation dip angle calculations are then described, as well as formulas that produce parameters indicative of the applicability of the fast formation dip angle calculations. The calculations and formulas are presented with the context of an illustrative system and a software-based method implemented by the system that perform the described calculations together with a decision tree that operates to decide which calculations are used to estimate the formation dip angle. The disclosed apparatuses, systems and methods are best understood in the context of the larger systems in which they operate. Accordingly, FIG. 1 shows an illustrative LWD environment. A drilling platform 2 supports a derrick 4 having a traveling block 6 for raising and lowering a drill string 8. A top drive 10 supports and rotates the drill string 8 as it is lowered through the wellhead 12. A drill bit 14 is driven by a downhole motor and/or rotation of the drill string 8. As bit 14 rotates, it creates a borehole 16 that passes through various formations. A pump 18 circulates drilling fluid 20 through a feed pipe 22, through the interior of the drill string 8 to drill bit 14. The fluid exits through orifices in the drill bit 14 and flows upward through the annulus around the drill string 8 to transport drill cuttings to the surface, where the fluid is filtered and recirculated. The drill bit 14 is just one piece of a bottom-hole assembly 24 that includes a mud motor and one or more "drill collars" (thick-walled steel pipe) that provide weight and rigidity to aid the drilling process. Some of these drill collars include built-in logging instruments to gather measurements of various drilling parameters such as location, orientation, weight-on-bit, borehole diameter, etc. The tool orientation may be specified in terms of a tool face angle (rotational orientation), an inclination angle (the slope), and compass direction, each of which can be derived from measurements by magnetometers, inclinometers, and/or accelerometers, though other sensor types such as gyroscopes may alternatively be used. In one specific embodiment, the tool includes a 3-axis fluxgate magnetometer and a 3-axis accelerometer. As is known in the art, the combination of those two sensor systems enables the measurement of the tool face angle, inclination angle, and compass direction. Such orientation measurements can be combined with gyroscopic or inertial measurements to accurately track tool position. Also included in bottom-hole assembly 24 is a telemetry sub that maintains a communications link with the surface. Mud pulse telemetry is one common telemetry technique for transferring tool measurements to surface receivers and receiving commands from the surface, but other telemetry techniques can also be used. For some techniques (e.g., through-wall acoustic signaling) the drill string 8 includes one or more repeaters 30 to detect, amplify, and re-transmit the signal. At the surface, transducers 28 convert signals between mechanical and electrical form, enabling a network interface module 36 to receive the uplink signal from the telemetry sub and (at least in some embodiments) transmit a downlink signal to the telemetry sub. A data processing system 50 receives a digital telemetry signal, demodulates the signal, and displays the tool data or well logs to a user. Software (represented in FIG. 1 as non-transitory information storage media 52) governs the operation of system 50. A user interacts with system 50 and its software 52 via one or more input devices 54 and 55 and one or more output devices 56. In some system embodiments, a driller employs the system to make geosteering decisions and communicate appropriate commands to the bottom-hole assembly 24. The bottom-hole assembly 24 may still further include a steering mechanism which the driller can employ to change the borehole's trajectory in response to their analysis of the logging measurements. Illustrative steering mechanisms include controllable fins, drilling plows, or bent subs. A rotary steerable system (RSS) may be coupled to such steering mechanisms to enable geosteering even as the drillstring continues rotating. One formation parameter of interest to drillers making geosteering decisions is the true dip of a formation. As is well known in the art, the dip is the steepest angle of descent of a tilted bed or other formation feature relative to a horizontal plane. True dip is the dip measured perpendicular to the formation's strike line (i.e., a line marking the intersection of the bed or feature with a horizontal plane). (It can also be expressed as the angle between the vertical axis and a vector normal to the formation bedding plane.) A related parameter is the relative dip, which is the angle measured between the borehole axis and the vector normal to the formation bedding plane. For example, the driller may measure the relative dip of the formation and employ that information to maintain the borehole trajectory within the formation bed as much as possible (relative dip angle near 90°) or to exit the bed as expeditiously as possible (relative dip angle near 0° or 180°). As shown in more detail below, true and/or relative dip can be estimated based on multi-component/tri-axial resistivity measurements. In at least some illustrative embodiments, such measurements are obtained using LWD tools that incorporate tri-axial transmit and receive coils and/or azimuthally sensitive transmit and receive antennas that transmit and receive signals that can be decomposed into and modeled as orthogonal components. In general, coupling between the transmit and receive antennas of such LWD tools can be expressed as a tensor of the form: wherein each component T Rj represents a theoretical signal at a receive antenna with a -axis orientation (x, y or z) in response to a signal from a transmit antenna with an -axis orientation (also x,y z). In at least some illustrative embodiments, the above-described x, y and z orientations are defined by coordinate system axes that are aligned with the axis of the drillstring and with other formation features (e.g., the strike and dip of the formation). FIG. 2 shows a drillstring with an illustrative LWD tool together with coordinate systems corresponding to each of the transmit and receive antennas. The LWD tool includes two modules 202 and 206 separated by a rotary steering system 204 and coupled to a drill bit 208. LWD module 202 includes a receive antenna 212 and LWD module 206 includes a transmit antenna 216, although either module may either a transmit or a receive antenna, as well as any number of additional transmit and/or receive antennas. The z-axis of the right-handed coordinate system of FIG. 2 is aligned with the drillstring axis with x and y axes as shown. It should be noted that although it is possible for receive antenna 212 and transmit antenna 216 to become misaligned with respect to each other because of twisting of the drillstring or positional and orientation changes deliberately introduced by a rotary steering system 204, such misalignments can be corrected using known matrix rotations that mathematically re-align the two antenna coordinate systems and adjust the tensor components appropriately. Thus, the systems and methods described herein may also be used with multi-module LWD tools even in the presence of such misalignment. As the drillstring and LWD tool modules rotate, a rotational or azimuthal angle f describes the orientation of the antennas within a plane defined by the x and y axes, as illustrated by the azimuthal angle graph of FIG. 2. To facilitate acquisition and processing of the measured receive antenna data, in at least some illustrative embodiments the borehole is divided into azimuthal bins (i.e., rotational angle ranges). In the azimuthal angle graph of FIG. 2, the circumference has been divided into eight bins numbered 242 through 256, though larger or smaller numbers of bins may be employed. As the rotating tool gathers azimuthally sensitive measurements, the measurements can be associated with one of these bins and with a depth value. Typically LWD tools rotate much faster than they progress along the borehole, so that each bin at a given depth can be associated with a large number of measurements. Within each bin at a given depth, these measurements can be combined (e.g., averaged) to improve their reliability. For dipping heterogeneous formations (e.g., a dipping formation near a bed boundary) wherein the z-axis represents the LWD tool axis along a drillstring, it is known that if the j-axis of the tool coordinate system is parallel to the formation's strike line, cross-coupling between x-y and y-z transmitter/receiver pairs is negligible. This situation is represented by the tensor of equation (2), T = 0 TyRy 0 (2) 0 TZ Z which provides a basis for determining the dip angle as described in more detail below. It should be noted that because the TyRy component for a tool at an azimuthal angle of 0° is equal to the TXR X component for a tool at 90° at a given borehole depth z, equation (2) may be alternatively expressed as equation (3): The coupling tensor may thus be expressed in terms of measurements by the tool antennas providing only x and z measurements, reducing the number of antennas needed to identify the tensor components. Nonetheless, for simplicity the equations below refer to the center tensor component as TyRy , with all components values corresponding to an azimuthal angle f equal to zero. The coupling tensor can be evaluated for all azimuthal orientations of the tool to find the orientation at which the tensor form most closely approximates equation (2). (Hereafter, this tensor is termed the "strike-aligned" tensor.) Alternatively, the dip azimuth can be calculated from an arbitrarily-oriented tensor as: and the tensor rotated by that angle to achieve a form that approximates equation (2). In at least some illustrative embodiments, once a strike-aligned tensor has been identified, a rotation operation over a range of artificial dip angles a is performed about the j-axis to produce rotated tensor TR, as expressed in equation (5): s oc 0 —sin oc TxRx 0 TX RZ cos oc 0 —sin oc 0 1 0 TyyRRy 0 0 1 0 (5) sin oc 0 cos oc TZ . 0 Z Z sin oc 0 cos oc Because rotated tensor is computed for a sweep of artificial dip angles a between 0° and 180° for all logged depths z , the rotated tensor components are each a function of both a and z , except for TyRy which is only a function of z since the rotation is performed about the j-axis. Rotated tensor may thus alternatively be expressed as shown in equation (6): Tx Rx x , z 0 Tx Rz x , z 0 TyRy z ) 0 (6) L¾(oc,z) 0 Tz Rz