Patent Publication Number: US-2006020390-A1

Title: Method and system for determining change in geologic formations being drilled

Description:
TECHNICAL FIELD  
      The present invention relates generally to the field of drilling in subterranean formations, and more particularly to a method and system for determining change in geologic formations being drilled.  
     BACKGROUND  
      Subterranean deposits of coal, also referred to as coal seams, contain substantial quantities of entrained methane gas. Production and use of methane gas from coal deposits has occurred for many years. Substantial obstacles, however, have frustrated more extensive development and use of methane gas deposits and coal seams. The foremost problem in producing methane gas from coal seams is that while coal seams may extend over large areas of up to several thousand acres, the coal seams are often fairly thin in depth, varying from a few inches to several meters. Thus, while the coal seams are often relatively near the surface, vertical wells drilling into the coal deposits for obtaining methane gas can only drain a fairly small radius in the coal deposits. Further, coal deposits are sometimes not amenable to pressure fracturing and other methods often used for increasing methane gas production from rock formations. As a result, once the gas easily drains from a vertical well bore in a coal seam, further production is limited in volume. In response to these limitations, horizontal drilling patterns have been tried in order to extend the amount of coal seams exposed by a well bore for gas extraction.  
     SUMMARY  
      The present invention provides a method and system for determining change in geologic formations being drilled. In particular, certain embodiments of the invention provide a system and method using data integration and predictive analysis for maintaining drilling operations within a thin or narrow formation.  
      In accordance with one embodiment of the present invention, a method for determining change in geologic formations includes receiving a plurality of values of formation change indicators. For at least one formation change indicator, the value is adjusted based on operating conditions. Specifically, a formation change is determined based on the received plurality of values of formation change indicators.  
      The technical advantage of the present invention include providing a method and system for data integration and predictive analysis of a subterranean formation. In particular, a technical advantage may include adjusting values of indicators of formation change based on drilling operations. This adjustment may allow for more accurate monitoring of formation change in a subterranean formations. More accurate monitoring of formation changes allows for more efficient drilling of thin subterranean formations and greatly reduces costs and problems associated with other systems and methods. Another technical advantage of one or more embodiments may include providing a system and method for drilling in any thin geologic formation.  
      Other technical advantages will be readily apparent to one skilled in the art from the figures, descriptions and claims included herein. Moreover, while specific advantages have been enumerated above, various embodiments may include all some or none of the enumerated advantages.  
    
    
     DESCRIPTION OF DRAWINGS  
       FIG. 1  is a schematic diagram of a drilling system in accordance with one embodiment of the present invention;  
       FIG. 2  is a block diagram illustrating an exemplary steering system of  FIG. 1 ;  
       FIG. 3  is an exemplary flow diagram illustrating an example method for providing data integration and predictive analysis of a subterranean zone;  
      FIGS.  4 A-B are exemplary flow diagrams illustrating example methods for the assessment step illustrated in  FIG. 3 ; and  
       FIG. 5  illustrates one embodiment of a display of formation change indicators. 
    
    
      Like reference symbols in the various drawings indicate like elements.  
     DETAILED DESCRIPTION  
       FIG. 1  is a schematic diagram of a drilling system  10  for drilling within a subterranean formation using data integration and predictive analysis in accordance with an embodiment of the present invention. In particular embodiments, the subterranean formation is an unconventional reservoir such as a coal seam. However, it should be understood that other subterranean formations including conventional oil and gas reservoirs can be similarly drilled using system  10  of the present invention to remove and/or produce water, hydrocarbons and/or other fluids, including gases, from the zone, to treat minerals in the zone prior to mining operations, or to inject, introduce, or store a fluid or other substance in the zone. The formation may, for example, be a thin formation having a thickness of less than ten feet, may include inconsistent bedding planes, or be undulating or faulted.  
      Referring to  FIG. 1 , system  10  includes a drilling rig  14 , an articulated well  12 , and a well bore pattern  32 . Rig  14  drills articulated well  12  that extends from a surface  16  into a subterranean formation  18 . From the terminus of articulated well  12  or articulated portion of well  12 , rig  14  proceeds to drill well bore pattern  32 . Articulated well  12  may be any appropriate well including a portion that is deviated from vertical, such as slanting, sloping or radiused. In other embodiments, the well may be a vertical or other suitable well.  
      Articulated well  12  extends from surface  16  to subterranean formation  18 . Articulated well  12  includes a first portion  20 , a second portion  22 , and a curved or radius portion  24  interconnecting the portions  20  and  22 . In  FIG. 1 , portion  20  is illustrated substantially vertical; however, it should be understood that portion  20  may be formed at any suitable angle relative to surface  16  to accommodate surface  16  geometric characteristics or attitudes and/or the geometric configuration or attitude of subterranean formation  18 . Portion  22  lies substantially in the plane of subterranean formation  18 . Substantially horizontal portion  22  may be formed at any suitable angle relative to surface  16  to accommodate the geometric characteristics of subterranean formation  18  and may undulate in subterranean formation  18 . Articulated well  12  may be logged and/or measured during drilling in order to monitor indicators of formation change, i.e., formation change indicators, to assist in maintaining drilling operations within subterranean formation  18 . As used herein, a formation change indicator is a parameter that in at least one circumstance strongly indicates a change in a formation being drilled, such as from one formation to another disparate formation. Formation change indicators may also or instead indicate anomalous formation changes such as faults, fractures or inconsistencies within a formation as, for example, thicker formations. Logging while drilling (LWD) may monitor the following formation change indicators: resistivity, density, sonic, gamma, oriented gamma, a combination of the foregoing, or other appropriate indicators. Measurement while drilling (MWD) may monitor the following formation change indicators: inclination, azimuth, annular pressure, vibration, tool face, a combination of the foregoing or any other appropriate indicators. Values determined by LWD and MWD may also assist in drilling well bore pattern  32  within subterranean formation  18 . Other formation change indicators may include operating conditions such as standpipe pressure, rotary torque and rate of penetration.  
      After the drilling orientation has been successfully aligned within and/or in subterranean formation  18 , drilling is continued to provide well bore pattern  32  in subterranean formation  18 . In  FIG. 1 , well bore pattern  32  is illustrated substantially horizontal corresponding to a substantially horizontally illustrated subterranean formation  18 ; however, it should be understood that that well bore pattern  32  may be formed at any suitable angle corresponding to the geometric characteristics of subterranean formation  18 . During this operation, MWD, LWD and rig measurements may be employed to control and direct the orientation of drill bit  29  in order to substantially maintain well bore pattern  32  within the confines of subterranean formation  18  and to provide substantially uniform coverage of a desired area within subterranean formation  18 . Well bore pattern  32  may lay within sloped, undulating, or other inclinations of subterranean formation  18 . During the process of drilling well bore pattern  32  and articulated well  12 , drilling rig  14  applies weight and torque to drill string  26  or otherwise manages drill string  26  to drill appropriate well bores.  
      Rig  14  includes drill string  26  supported by kelly  34 , which in turn is connected to swivel  36 . Swivel  36  allows kelly  34  and drill pipe to rotate. The drilling progress or rate of penetration (ROP) is measured from the rate that the height of kelly  34  decreases during drilling operations. Swivel  36  is suspended from hook  40  of travelling block  38 . Draw works  46  controls the upward and downward motion of travelling block  38  via drilling line  44 . Drilling line  44  runs from the drum of draw works  46 , up to crown block  42  and then over several loops back and forth between crown block  42  and travelling block  38 . Crown block  42  is affixed to mast  43 . The end of drilling line  44  is clamped or otherwise affixed to mast  43 . This termination point may also serve as a sensor point for determining weight on bit (WOB) via drill string  26 . Drill string  26  includes a motor  28  and drilling bit  29  and may collectively be referred to as a bottom hole assembly (BHA)  31 . BHA  31  may also include MWD instruments  30  to measure formation change indicators used to control the orientation and direction of drill string  26  for substantially maintaining drilling within subterranean zone  18 .  
      Mud pump  52  pumps drilling fluid, or mud  54  from mud tank, or pit,  58  to drill string  26 . Mud pump  52  is connected to drill string  26  via mud hose  56 , which may be connected to a standpipe. Standpipe pressure may be measured by any appropriate instrument. After mud  54  enters drill string  26 , mud  54  travels to BHA  31  via drill string  26 , where it drives the motor of BHA  31  and exits bit  29 . After exiting bit  29 , mud  54  scours the formation and assists in lifting cuttings to surface  16  via the annulus of drill string  26 . The returning mud  54  is directed to mud tanks  58  through flow line  60 . Mud tanks  58  may include shale shakers or other appropriate devices to remove cuttings from the returned mud  54 . Sensors may be included in mud tank  58  to measure characteristics of mud  54  such as, for example, mud weight, mud resistivity, mud temperature, mud density, and other appropriate characteristics.  
      In operation, articulated well bore  12  and well bore pattern  32  are drilled by applying weight to and rotating drill bit  29 . A rotary table  62 , which is mounted on rig floor  64 , drives the rotation of drill string  26  and thus transmits torque to drill bit  29 . Rotary table  62  may provide a measuring point for rotations per minute (RPM) of and rotary torque applied to drill string  26 . Bit  29  may alternatively or additionally be rotated by downhole motor  28  and may be independent of drill string  26 . In this case, mud  54  pumped through drill string  26 , flows through motor  28  to turn bit  29 . Further, motor  28  may be configured with an angular subassembly which, when oriented in a given altitude, allows the wellbore trajectory to be altered. As discussed above, mud  54  carries the cuttings produced by drill bit  29  out of well bore pattern  32  through the annulus between the drill string  26  and well bore  12 . During operation, determinations of MWD and LWD parameters and operating conditions may be made and provide to steering system  100 .  
      Steering system  100  assesses, based on formation change indicators and operating conditions, changes in subterranean zone  18  during drilling operations and indicates these assessments to a user of system  100 . The value of one or more formation change indicators may be adjusted based on operating conditions. Such adjustments may be continuous, periodic or as necessary. For example, operating condition adjustments may not be necessary when formation change is the cause of a change in formation change indicators.  
      Operating conditions are parameters associated with the operation of rig  14 . Operating conditions may include one or more of the following: rate of penetration, standpipe pressure, annular pressure, vibration, motor differential pressure, weight on bit, measured depth, rotary torque, fluid flow rate, mud weight, and others. Steering system  100  may be used to maintain horizontal drilling within a formation, to give early indications of formation changes to pick core points and/or to identify equipment problems such as worn bit or washed out drill string tubular. For example, the system may be used in conventional reserve horizontal drilling where a formation sweet spot is being targeted. In this application, for example, well bore trajectory at a certain elevation in the formation (e.g. near the top) may be maintained using indicators that identify differences in formation consistency between the top and bottom of the formation. While steering system  100  is illustrated as a part of rig  14 , steering system  100  may be separate from rig  14  and/or on-site or off-site.  
       FIG. 2  illustrates one embodiment of steering system  100  of  FIG. 1 . In one embodiment, system  100  provides data integration and predictive analysis for aiding drilling operations and/or steering system  100 . At a high level, system  100  is coupled to and receives formation change indicators and/or operating conditions from surface data gathers  102  and downhole data gathers  104 . Based on the received data, system  100  assesses changes in subterranean zone  18  during drilling operations and indicates these assessments to the user of system  100 .  
      Surface data gathers  102  and downhole data gathers  104  comprise instrumentation that measure formation change indicators and/or operating conditions and provides their values to system  100 . Alternatively, the measurements of formation change indicators and/or operating conditions may be manually determined, in which case their values may be manually inputted into system  100 . It will be understood that reference to “value” may be used interchangeably with “an average of a selected number of values,” so the term “value” also refers to “an average of a selected number of values,” where appropriate. For example, the average may span a specified period of time (e.g., 15 sec, 30 sec, 45 sec, etc.) or include a specified number of data points (e.g., 3, 10, 20, etc.). As discussed above, formation change indicators and/or operating conditions may include MWD measurements, LWD measurements, rig measurements, and other suitable measurements. In one embodiment, down hole data gathers  104  comprises MWD instrumentation  30  that communicates values of formation change indicators via mud pulses, electromagnetic, acoustic or other wireless telemetry methods. Values may be alternatively communicated by wireline, fiber optic, tubular conveyance or other hardwire conduits.  
      System  100  includes a Graphical User Interface (GUI)  106 , an MWD interface  108 , a memory  110 , and a processor  112 . The present disclosure includes a repository of conversion files  119  that may be stored in memory  110  and may be processed by processor  112 . While system  100  is illustrated as a computer, system  100  may comprise any appropriate processing device such as, for example, a mainframe, a personal computer, a client, a server, a workstation, a network computer, a personal digital assistant, a mobile phone, or any other suitable processing device. System  100  may be operable to receive input from and display output through GUI  106 .  
      GUI  106  comprises a graphical user interface operable to allow the user of system  100  to interact with processor  112 . The terms “system  100 ” and “user of system  100 ” may be used interchangeably, where appropriate, without departing from the scope of this disclosure. Generally, GUI  106  provides the user of system  100  with an efficient and user-friendly presentation of data provided by system  100 . GUI  106  may comprise a plurality of displays having interactive fields, pull-down lists, and buttons operated by the user. Alternatively, system  100  may comprise any appropriate indicator operable to convey formation changes to a user of system  100  such as, for example, a display, color-coded lights, alerting noise, or any other suitable indicator.  
      System  100  may include MWD interface  108  for receiving MWD signals from MWD instruments  30  and converting the signal for use with system  100 . Generally, interface  108  comprises logic encoded in software and/or hardware in any suitable combination to allow system  100  to receive values of formation change indicators measured by MWD instruments  30 . While MWD interface  108  is illustrate as a part of system  100 , MWD interface  108  may be disparate from system  100  and coupled to system  100 .  
      Memory  110  may include any memory or database module and may take the form of volatile or non-volatile memory including, without limitation, magnetic media, optical media, Random Access Memory (RAM), Read Only Memory (ROM), removable media, or any other suitable local or remote memory component. In this embodiment, memory  110  includes a filtering range file  114 , a tolerance range file  116 , and repository of conversion files  118 , but may also include any other appropriate files. Filtering range file  114  comprises instructions, algorithms or any other directive used by system  100  to identify one or more ranges of reliable values associated with each formation change indicator and operating condition. The term “each,” as used herein, means every one of at least a subset of the identified items. In the case a value is outside a filtering range, the value is discard and may comprise noise. Filtering range file  114  may be created by system  100 , a third-party vendor, any suitable user of system  100 , loaded from a default file, or received via network.  
      Tolerance range file  116  instructions, algorithms or any other directive used by system  100  to identify one or more ranges of each formation change indicators and operating condition that indicates tolerable variation in values of the associated parameter. For example, a tolerance range may indicate expected variation in values of a formation change indicator while drilling operations are within subterranean formation  18 . In this case, values within the tolerance range may not indicate significant or any formation changes. As another example, a tolerance range may indicate expected variation in measurements due to noise inherent in the measuring instrumentation. In this case, values within the tolerance range may not indicate significant or any formation changes. In one embodiment, tolerance ranges of a formation change indicator and/or operating condition is a subset of the associated filtering range. In this embodiment, values that lie outside the tolerance range and within the associated filtering range may indicate significant changes in the formation being drilled. Filtering range file  114  may be created by system  100 , a third-party vendor, any suitable user of system  100 , loaded from a default file, or received via network.  
      Conversion file  118  comprises instructions, algorithms, data mapping, or any other directive used by system  100  to convert a value of a formation change indicator and/or operating conditions to a corresponding value on a scale operable to indicate formation changes. As used herein, convert means to swap, translate, transition, or otherwise modify one or more values. Conversion file  118  may be dynamically created by system  100 , a third-party vendor, any suitable user of system  100 , loaded from a default file, or received via network. The term “dynamically” as used herein, generally means that the appropriate processing is determined at run-time based upon the appropriate information. Moreover, a conversion file  118  may be accessed one or more times over a period of a day, a week, or any other time specified by the user of system  100  so long as it provides scaling function  119  upon request.  
      Scaling function  119  is one or more entries or instructions in conversion file  118  that maps a value of a formation change indicator and/or operating condition to a corresponding value on a selected scale. As used herein, “select” means to initiate communication with, retrieval of, or otherwise identify. The selection of the scale may be based on any appropriate characteristic such as, for example, ease of use, association with a formation change indicator, or any other suitable characteristic. Scaling function  119  may comprise a mathematical expression based on any appropriate programming language such as, for example, C, C++, Java, Pearl, or any other suitable programming language. For example, scaling function  119  may comprise an algebraic, trigonometric, logarithmic, exponential, a combination of the foregoing, or any suitable mathematical expression. Moreover, different values of a formation change indicator and/or operating conditions may be associated with disparate mathematical expressions. For example, scaling function  119  may comprise an algebraic expression for a first range of values and an exponential expression for a second range of values. Alternatively, scaling function  119  may comprise any appropriate data type, including float, integer, currency, date, decimal, string, or any other numeric or non-numeric format operable to identify a mathematical expression for mapping a value of a formation change indicator and/or operating condition to a selected scale. It will be understood that every value received by system  100  may not be associated with a corresponding scaling function  119  and thus a scaling function  119  may only be provided for a subset of the received values. Additionally, formation change indicators and/or operating conditions may be associated with disparate scaling functions  119  and thus each received value may be associated with a disparate scaling function  119 . In one embodiment, a value of an operating condition may be associated with multiple scaling functions  119  and thus multiple scaled values may be determined from a single value of an operating condition. In this embodiment, the disparate scaled values are used to adjust disparate formation change indicators.  
      Processor  112  executes instructions and manipulates data to perform operations of system  100 . Although  FIG. 1  illustrates a single processor  112  in system  100 , multiple processors  112  may be used according to particular needs and reference to processor  112  is meant to include multiple processors  112  where applicable. Processor  112  may include one or more of the following features and functions: point-to-point comparison, trailing average comparison of individual streams of values of formation change indicators, forward extrapolations based upon an individual stream of values of formation change indicators, point-to-point differential, trailing average indicators, forward extrapolations based on point-to-point or trailing average calculations, a combination of the above, or others. In the illustrated embodiment, processor  112  executes conversion engine  120 , assessment engine  122 , and alerting engine  124 . Conversion engine  120  filters received values, converts values based on associated scaling functions  119 , adjusts the converted values based on changes in operating conditions, and forwards the adjusted values to assessment engine  122 . After receiving values of formation change indicators and/or operating conditions, conversion engine  120  retrieves associated filtering ranges from filtering range file  114 . Conversion engine  120  discards all values that fall outside their associated filtering range. After filtering the values, conversion engine  120  retrieves scaling functions  119  from conversion file  118  associated with each received value. Based upon the retrieved scaling functions  119 , conversion engine  120  converts each value to a corresponding value on the selected scale. For those values discarded, conversion engine  120  may use a preceding value or preceding average of values to convert to the selected scale. After converting the values, conversion engine  120  determines the extent that each converted value results from operating conditions. Based on this determination, conversion engine  120  adjusts the converted value to substantially remove the effect of the operating condition. In one embodiment, conversion engine  120  subtracts a value associated with a change in operating condition from a converted value of a formation change indicator. For example, conversion engine  120  may determine an increase or decrease in a converted values of an operating condition, at which point conversion engine  120  may subtract this increase or decrease from an associated formation change indicator. Alternatively, conversion engine  120  may determine the value of the change in the operating condition prior to converting to the selected scale. In this case, the change is converted to the scale which is then subtracted from the associated formation change indicator. As discussed above, a change in an operating condition may be used to adjust multiple formation change indicators, so multiple scaling functions  119  may be associated with the operating condition. In this case, each scaling function  119  may convert the same value (or change in value) to disparate values on the scale for adjusting disparate formation change indicators.  
      Conversion engine  120  may adjust several formation change indicators based on one or more operating conditions. For example, annular pressure may be adjust by one or more of the following: mud weight, fluid flow rate, standpipe pressure, vertical depth, or others. Vibration may be adjusted by standpipe pressure, weight on bit, or others. ROP may be adjusted by weight on bit or other appropriate operating conditions. Further, prior to using standpipe pressure to adjust other parameters, standpipe pressure may be adjusted by one or more of the following: fluid flow rate, WOB, and others. These examples are not intended as an exhaustive list but other embodiments may include other combinations of formation change indicators and operating conditions. In short, conversion engine  122  includes any suitable hardware, software, firmware, or a combination thereof operable to convert a value of a formation change indicator to a scale and adjust the value based on operating conditions. It will be understood that while connection engine  120  is illustrated as a single multitask module, the features and functions performed by this engine may be performed by multiple engines.  
      After adjusting the values, conversion engine  120  forwards the adjusted values of the formation change indicators to assessment engine  122 . Assessment engine  122  determines whether the adjusted values in combination indicate significant change in subterranean zone  18  and if so, notify a user of system  100 . In one embodiment, assessment engine  122  retrieves the tolerance ranges from tolerance range file  116 , at which point assessment engine determines the difference between each value and a corresponding tolerance range. In this embodiment, assessment engine  122  sums the difference to determine an overall formation change indicator as illustrated in  FIG. 5 . Alternatively, conversion engine  120  may combine preselected groups of adjust values and determine if these combined values fall outside their corresponding tolerance range. In this alternative embodiment, assessment engine  120  retrieves tolerance ranges from tolerance range file  116 . Assessment engine  122  sums the tolerance ranges of each preselected group and sums the adjust values within the preselected group. For example, the tolerance ranges of annular pressure and oriented gamma may be summed as a preselected group. After combining the ranges, assessment engine  122  determines if the combined values falls outside the tolerance range of the combined group. If so, assessment engine  122  notifies user of system  100  by, for example, displaying the value and range on a display. In yet another embodiment, assessment engine  122  may notify the user of system  100  if a certain number of adjusted values fall outside their tolerance ranges.  
      Alerting engine  124  communicates threshold violations to user of system  100 . In one embodiment, alerting engine  124  retrieves threshold values from threshold file  118 . Alerting engine  124  compares received values to the retrieved threshold values and in response to determining violations, alerting engine  124  communicates an alert to user of system  100 . Additionally, alerting engine  124  may perform the following features and/or functions: flag a selected percentage of values being rejected from each measured variable, flag selected percentage changes in point to point, trailing average and/or differential values, notify for selected percentage changes in measured parameters not chosen for operator display, a combination of the forgoing, and/or others. It will be understood that while alerting engine  124  is illustrated as a single multitask module, the features and functions performed by this engine may be performed by multiple modules. Additionally, alerting engine  124  may comprise a child or sub-module (not illustrated) of another software module without departing from the scope of the disclosure. Alerting engine  124  may be based on any appropriate computer language such as, for example, C, C++, Java, Pearl, Visual Basic, and others.  
      In one aspect of operation, system  100  receives values of formation change indicators and operating conditions. After receiving the values, conversion engine  120  retrieves filtering ranges from filtering range file  114  and discards all values that fall outside their associated filtering range. For values discard, conversion engine  120  may retrieve previous values to use as the received value. After filtering the values, conversion engine  120  converts the values into the selected scale based on associated scaling functions  119 . Once converted, conversion engine  120  adjusts the values by subtracting a change in the value of associated operating conditions. The adjusted values of formation change indicators are forwarded to assessment engine  122 . Assessment engine  122  combines a plurality of the adjusted values to determine the occurrence of significant formation change and in response to determining significant formation change, notifies a user of system  100  of this determination. In one embodiment, assessment engine  122  determines, for those values outside their corresponding tolerance range, a difference between each adjust value and their corresponding tolerance range. Assessment engine  122  sums these differences and notifies the user of system  100  of this value by, for example, displaying the value on through GUI  106 . In another embodiment, assessment engine  122  sums the values and tolerance ranges of preselected groups of formation change indicators and compares the summed values to the summed tolerance ranges to determine if any of the preselected groups fall outside their summed tolerance range. For those summed values that do, assessment engine  122  notifies the user of system  100  of the preselected group and their associated summed value.  
       FIG. 3  is an exemplary flow diagram illustrating a method  300  for determining change in geologic formations being drilled. Method  300  is described with respect to system  100  of  FIG. 2 , but method  300  can also be used by any other system. Moreover, system  100  may use any other suitable techniques for performing these tasks. Thus, many of the steps in this flow chart may take place simultaneously and/or in different orders as shown. Moreover, system  100  may use methods with additional steps, fewer steps, and/or different steps, so long as the methods remain appropriate.  
      Method  300  begins at step  302  where a plurality of values of formation change indicators and operating conditions are received by conversion engine  120 . Next, at step  304 , conversion engine  120  filters the received values by discarding all values that fall outside their associated filtering range. In one embodiment, the discarded values are replaced with a previous value. If the value violates an associated threshold at decisional step  306 , then, at step  308 , conversion engine  120  communicates an alert to the user of system  100 . If no violation is detected, then execution proceeds to step  310 . At step  310 , conversion engine  120  converts the values to the selected scale based on an associated scaling function  119 . Conversion engine  120  adjust the scaled values based on changes in operating conditions. In one embodiment, conversion engine  120  subtracts changes in value of operating conditions from associated formation change indicators. Next, at step  314 , assessment engine  122  assesses whether a change in geologic formation is indicated by combining values of formation change indicators. Two embodiments of this assessment step are illustrated in  FIGS. 4A and 4B . Based on the assessment, if changes in drilling operations are required at decisional step  316 , then, at step  318 , assessment engine  122  notifies a user of system  100 . If no changes are required at step  316 , then execution ends.  
      FIGS.  4 A-B are exemplary flow diagrams illustrating two embodiments of step  314  of  FIG. 3 . Methods  400  and  450  are described with respect to system  100  of  FIG. 2 , but methods  400  and  450  could also be used by any other system. Moreover, system  100  may use any other suitable techniques for performing these tasks. Thus, many of the steps in these flow charts may take place simultaneously and/or in different orders as shown. Moreover, system  100  may use methods with additional steps, fewer steps, and/or different steps, so long as the methods remain appropriate.  
      Referring to  FIG. 4A , method  400  begins at step  402  where conversion engine  120  determines the difference between each adjusted value falling outside their associated tolerance range and their associated tolerance range. Next, at step  402 , assessment engine  122  sums the differences. Assessment engine notifies user of system  100  of nonzero sums at step  404 .  
      Turning to  FIG. 4B , method  450  begins at step  452  where assessment engine  122  sums the adjusted values and sums the tolerance ranges in preselected groups. At decisional step  454 , if the summed adjusted values violate the summed tolerance ranges of the preselected groups, then, at step  456 , assessment engine  456  notifies user of system  100  of those preselected groups. If none of the preselected groups violate their summed tolerance range, then execution ends.  
       FIG. 5  illustrates one embodiment of a display  500  of formation change indicators  1  to  10  (FCI 1  to FCI 10 ) and overall FCI. Display  500  includes graphical bars  502  and  504 . Graphical bars  502  include demarcations indicating tolerance ranges  506  of the FCI. Graphical bar  506  illustrates the summed difference between FCI and associated tolerance ranges. It will be understood that the assessment of formation change indicators may otherwise be provided. Alternatively, user of system  100  may be otherwise alerted as discussed above.  
      A number of embodiments of the invention have been described. Nevertheless, it will be understood that various modifications may be made without departing from the spirit and scope of the invention. For example, a peripheral benefit embedded in the technology may include user alerts that show violations that could indicate impending equipment failure (e.g. standpipe pressure decline indicating washed out tubular that can lead to parted drill string) and warn of safety issues (e.g. annular pressure decline indicating gas inflow that could result in a blowout). It is intended that the present invention encompass such changes and modifications as falling within the scope of the appended claims.