Patent Publication Number: US-7908034-B2

Title: System, program products, and methods for controlling drilling fluid parameters

Description:
RELATED APPLICATION 
     This application claims priority to PCT Application PCT/US2006/025964, International Filing date Jun. 30, 2006 which claims priority to U.S. patent application No. 60/696,092, filed Jul. 1, 2005 and U.S. patent application No. 60/701,744, filed Jul. 23, 2005. 
    
    
     BACKGROUND OF THE INVENTION 
     1. Field of the Invention 
     This invention relates in general to well drilling and, in particular, to systems, program products, and methods associated with controlling drilling-fluid parameters in an oil or gas well. 
     2. Description of the Related Art 
     More and more oil exploration is moving toward ever challenging environments, which present increasing environmental and technical risks. Such environments are resulting in narrow or margins between the pressure of fluids inside the pores of rock at the bottom of a well hole, known as pore pressure, and the pressure which causes a rock formation containing or adjacent a formation containing desired hydrocarbons to fracture, known as the fracture or leak off pressure of the formation. Well drilling systems can include a drilling rig located substantially at the surface. A drill string positioned within the casings extends through the casings to the formation containing hydrocarbons. The drilling string and annular area between the drilling string and between the wellbore and inner-most casing, referred to as the annulus, form a drilling circulation system. 
     Primary and intermediate casings (strings) are cemented inside a drilling hole to prevent direct transmission of fluid pressure to intermediate formations. The casing strings are designed for operationally limiting gradients, on the high side for overburden, fracture, borehole stability, etc. and on the low side for pore pressure control and/or wellbore integrity, etc. The overburden gradient is initially quite low and increases in a highly non-linear fashion with depth. Fracture gradient follows a similar trend, with separation from the overburden gradient diminishing with depth. Pore pressure increases with depth, details of which depend upon conditions in each formation penetrated. Separation of the upper limit (overburden or fracture) and lower limiting pore pressure is used to determine the number and depth of casing strings to be run. 
     As well drilling operations reach into deeper and deeper depths, proper well control becomes ever more challenging and yet more critical. Variations in the density of the drilling fluid resulting in more pronounced changes in hydrostatic pressure at the bottom of the well bore. Further, and deeper depths, some formations may not tolerate significant variations in hydrostatic pressure. Such variations in hydrostatic pressure can result in either a formation fluid influx into the wellbore, known as a “kick,” or a loss of drilling fluid to the formation, known as “lost circulation.” 
     Drilling a well bore generally requires circulating a drilling fluid through the drilling fluid circulation system. At the surface, the drilling fluid is pumped through a flowmeter and down the drilling string to the bottom hole of the well and is returned via the annulus. The fluid exits the annulus through a return line, outlet flowmeter or flowmeters, degasser, shale shaker to remove drilling clippings, and into a fluid storage tank to again be pumped down the drilling string. A choke in the return line can be used to control pressure within the annulus. 
     As the drilling fluid is circulated through the circulation system under a positive pressure from a surface “mud” pump (or bottom hole pump), the drilling fluid encounters a loss in pressure due to friction, known as “circulating friction.” The circulating friction is generally the result of an interaction between the drilling fluid and the inner surface of the drilling fluid conductors through which the drilling fluid is circulating. The mud pump and bottom hole circulating pressure is generally kept substantially constant for a particular set of operating parameters. When the drilling fluid is not being circulated, the bottom hole pressure exerted on the formation is a non-circulating or “static” hydrostatic pressure equal to the hydrostatic weight of the drilling fluid column. When drilling and under steady-state conditions, the drilling fluid is circulated and the bottom hole hydrostatic pressure exerted on the formation is increased above the non-circulating or “static” hydrostatic pressure by the amount of friction pressure in the well bore annulus. The resulting bottom hole pressure applied to the formation when circulating drilling fluid is known as the equivalent circulating density or “ECD.” 
     The drilling fluid is utilized to provide hydrostatic well control. In overbalanced drilling the weight of the drilling fluid and the setting of the choke is selected so that the dynamic pressure at the lower ends of the drilling and casing strings are greater than the pore pressure, but less than the fracture or leak off pressure. In near balanced drilling the dynamic pressure is maintained approximately the same as the pore pressure. In under balanced drilling, the dynamic pressure is maintained less than the pore pressure. In each type of drilling, the dynamic pressure is maintained by a combination of the drilling fluid weight (density) and control of the choke via surface well control equipment. 
     In order to determine if a “kick” is being encountered or if there is lost circulation, mass flow and/or volume flow can be monitored both in and out of the system to detect an influx or loss of mass or volume of the drilling fluid or by means of downhole temperature sensors, downhole hydrocarbon sensors, pressure chain sensors, or pressure pulse sensors. A discrepancy between predicted and monitored flow out can be indicative of an influx into or loss of the drilling fluid. The difference in mass being supplied to the drilling string and returned from the well annulus provides an indication of whether or not fluid is entering or exiting downhole. If a discrepancy is detected, the bottom hole pressure is controlled by a process known as managed pressure drilling. 
     Most recent developments in drilling systems include those described in U.S. Pat. No. 6,352,129 by Best titled “Drilling System,” U.S. Pat. No. 6,374,925 by Elkins et al. titled “Well Drilling Method and System,” U.S. Pat. No. 6,484,816 by Koederitz titled “Method and System for Controlling Well Bore Pressure,” and WIPO Patent Document No. WO 02/50398 A1 by Leuchtenberg titled “Closed-Loop Fluid Handling System for Well Drilling.” 
     According to one methodology, weighing agents, e.g., barite, are added to the drilling fluid to increase the “weight” in response to influx or oil or other low density material is added to the drilling fluid in response to fluid loss to set a desired drilling fluid density to change the equivalent circulating density and bottom hole pressure. This methodology is extremely inefficient as hours may pass as the weighing agent is being added to the drilling fluid and circulated through the circulation system. Another methodology of adjusting bottom hole pressure in response to an influx or drilling fluid loss includes adjusting the fluid choke in the fluid output conductor when circulating the drilling fluid and/or when drilling to apply sufficient back pressure. Another methodology of adjusting bottom hole pressure includes injecting fluid into the annulus when not performing drilling. 
     In order to function, each methodology incorporates assumptions used in monitoring pressure, volume, and density entering and exiting the circulation system and in determining desired drilling fluid density adjustment parameters or choke configuration parameters. These assumptions include the drilling fluid being a single-phase liquid that is incompressible. The assumptions also include the mud pump pressure being substantially constant. The assumptions further include that the flowrate of the drilling fluid entering the drilling string from the surface, although adjustable, is substantially constant. In the latter two methodologies, these assumptions also include that the density, although adjustable, is substantially constant. 
     Methodologies employed in the state-of-the-art for managing bottom hole pressure, general known as managed pressure drilling, do not account for, i.e., ignore, the pressure changes inside the drilling string along with other significant factors in the whole system that contribute in substantial ways to operational effects in the annulus, at the choke, at the bottom of the hole. Previously employed methodologies do not account for the compressibility of associated rocks, fluid in the rocks, cement in the hole, the casing strings cemented in the hole, the drilling fluid, the drilling string assembly when drilling, which is an enormous volume of material. The volume to pressurize the circulation system is small but it is not zero. Additionally, recognized by the Applicant is that adjusting the choke in the output line adjusts annulus pressure, but not necessarily pressure within the drilling string. 
     Therefore, there is still a need for a system, program product, and methods for enhanced dynamic control of drilling fluid pressures and parameters. Particularly, recognized by the Applicant is the need for a system that can monitor and control pressure, volume, density, temperature, fluid composition, molecular concentration of both single phase and multiphase drilling fluid both when entering and when exiting the drilling circulation system and at any location from the surface and along the length inside the drilling string and in the annulus, i.e., either side of the U-tube, at any time or operational drilling phase. Recognized also is the need for a system that can account for the pressure changes and other factors inside the drilling string, in the annulus, at the choke, at the bottom of the hole, and that can account for the volume of drilling fluid required to pressurize the circulation system. Recognized also is the need for a system that can measure compressibility of associated rocks, fluid in the rocks, cement in the hole, the casing strings cemented in the hole, the drilling fluid, the drilling string assembly to formulate a running description of the physical behavior of the drilling system and all components, and that can account for such compressibility to thereby enhance dynamic density control throughout the system. Recognized also is the need for a system that can account for friction losses for any location for any rheology and physical dimensions of the circulation system and that can determine and compensate for the existence of mud channels in the drilling string cement. Recognized further is the need for a system that can dynamically manipulate the mud weight window, and that can predict maximum dynamic bottom hole pressure at future depths to be drilled to thereby anticipate future drilling requirements to drill at the future depth including a requirement to order supplies, people, third party services, etc. Recognized further, also, is the need for a system that can add gas or other fluids to drilling fluid and account for gas or other fluids added in the drilling fluid. 
     SUMMARY OF THE INVENTION 
     In view of the foregoing, embodiments of the present invention provide systems, program products, and methods to enhance the controlling of drilling fluid pressures and other parameters such as in an oil or gas well. Embodiments of systems, program products, and methods for controlling drilling pressures of the present invention, for example, advantageously provide dynamic density control (DDC) and dynamic mud weight windows (DMWW). These embodiments having DDC provide highly adaptive, real-time, process control and can be scalable to any rig, large or small, on land or water. Embodiments of systems, program products, and methods also advantageously allow combined static and dynamic stresses and displacements to be determined continuously at strategic locations in and around the wellbore so that insitu and operationally induced pressure window limitations at specific weal-points are controlled. By coupling feedback loops and high-rate, high-quality, time-lapse data logging, for example, embodiments of the present invention allow an operator/service company team to “walk-the-line” or even “move-the-line”. 
     For example, mass and energy balances for an active system account for time-varying bulk volumes, stresses, pressures, fluids, and temperatures, coupled and associated with flows, displacement or movement. On or off switching circuitry can activate individual system element quantifiers in isolation or coupled with other elements to allow selected usage, maximum usage, or no usage of the enhanced system features. An embodiment of a method of controlling drilling fluid pressures includes monitoring the fluid pressure in real-time and increasing fluid head pressure within a drill pipe and annulus of a well to thereby control downhole pressures within pre-selected limits. 
     Additionally, many applications for embodiments of systems, program products, and methods of the present invention abound. For example, applications can include detecting pressure changes where critical pressure magnitudes and small pressure tolerances have large economic, technical, safety, and environmental consequences; in distinguishing between kicking flow and ballooning flow in kick/loss scenarios; in minimizing formation damage during drilling/completion operations; in identifying likely trouble spots in advance; and in training, predictive, what-ifs, and case studies. 
     More specifically, according to an embodiment of the present invention, provided is a system for controlling drilling fluid parameters. The system can include a drilling apparatus having one or more casing string cemented within a subterranean wellbore, a drilling string run within the one or more casing strings, an annulus formed between an external surface of the drilling string and inner surface of the innermost casing string, a drilling fluid inlet, a drilling fluid outlet, a drilling fluid circulating through the drilling fluid inlet, down through the drilling string, up through the annulus, and out the drilling fluid outlet, one or more monitors including one or more sensors positioned to monitor drilling fluid parameters of the drilling fluid entering the drilling string, one or more monitors including one or more sensors positioned to monitor drilling fluid parameters of the drilling fluid exiting the annulus, and an output port choke in communication with the annulus and the drilling fluid outlet. A combination of the wellbore and the one or more casing strings have a plurality of locations of interest located at laterally separate locations which must be managed through control of the drilling fluid. The system can also include a dynamic density control computer in communication with the choke and including a processor and memory associated with a processor to store operating instructions therein, and dynamic density control program product stored in the memory of the dynamic density control computer. The dynamic density control program product can include instructions that when executed by the processor of the dynamic density control computer cause the computer to perform the operations of determining separately for each of the plurality of laterally separated locations of interest drilling fluid control variable system limitation of a drilling fluid control variable, measuring a value of an operationally induced drilling fluid parameter at each of a plurality of separate locations when drilling, predicting separately for each of the plurality of laterally separated locations of interest a value of the drilling fluid control variable responsive to each measured drilling fluid parameter value, and controlling a drilling fluid parameter responsive to each predicted control variable value and each associated at least one drilling fluid control variable system limitation. 
     Embodiments of the present invention can also include methods of controlling drilling fluid parameters. A method, for example, can include determining separately for each of a plurality of laterally separate locations of interest in a drilling system having at least one casing string cemented in a wellbore and a drilling string positionable therethrough at least one drilling fluid control variable system limitation of a drilling fluid control variable, measuring a value of an operationally induced drilling fluid parameter at each of a plurality of separate locations when drilling, predicting separately for each of the plurality of laterally separated locations of interest a value of the drilling fluid control variable responsive to each measured drilling fluid parameter value, and controlling a drilling fluid parameter responsive to each predicted control variable value and each associated at least one drilling fluid control variable system limitation. 
     Embodiments of the present invention can also include a computer readable medium that is readable by a computer controlling drilling fluid parameters, e.g., pressures, etc., in a drilling system. A computer readable medium, for example, can include a set of instructions that, when executed by the computer, cause the computer to perform the operations of determining separately for each of a plurality of laterally separate locations of interest in a drilling system having at least one casing string positioned in a wellbore and a drilling string positionable therethrough at least one drilling fluid control variable system limitation of a drilling fluid control variable, measuring a value of an operationally induced drilling fluid parameter at each of a plurality of separate locations when drilling, predicting separately for each of the plurality of laterally separated locations of interest a value of the drilling fluid control variable responsive to each measured drilling fluid parameter value, and controlling a drilling fluid parameter responsive to each predicted control variable value and each associated at least one drilling fluid control variable system limitation. 
     Advantageously, embodiments of the present invention provide a system, program product, and methods that can monitor and control pressure, volume, density, temperature, fluid composition, molecular concentration of both single phase and multiphase drilling fluid both when entering and when exiting the drilling circulation system and at any location from the surface and along the length inside the drilling string and in the annulus, i.e., either side of the U-tube, at any time or operational drilling phase. The system, program product, and methods advantageously can account for the pressure changes and other factors inside the drilling string, in the annulus, at the choke, at the bottom of the hole, and can account for the volume of drilling fluid required to pressurize the circulation system. The system, program product, and methods can measure compressibility of associated rocks, fluid in the rocks, cement in the hole, the casing strings cemented in the hole, the drilling fluid, the drilling string assembly to formulate a running description of the physical behavior of the drilling system and all components, and can account for such compressibility to thereby enhance dynamic density control throughout the system. Further, the system, program product, and methods advantageously can account for friction losses for any location for any rheology and physical dimensions of the circulation system, and can determine and compensate for the existence of mud channels in the drilling string cement. Such system, program product, and methods can dynamically manipulate the mud weight window, and can predict maximum dynamic bottom hole pressure at future depths to be drilled to thereby anticipate future drilling requirements to drill at the future depth including a requirement to order supplies, people, third party services, etc. Embodiments of the present invention can utilize surface parameters, e.g., flow rates, pressures, densities, fluid compositions (in and out); system parameters, e.g., flow rates, pressures, densities, friction losses, temperature distributions of the drilling fluid, to predict operational parameters of the drilling fluid to thereby control drilling fluid parameters. Additionally, embodiments of the present invention can utilize gas volume and solubility profiles in system, and can determine fracture volumes with pressure-volume-time curves/solubility data for the drilling fluids determined by testing or in real-time during operations. Embodiments of the present invention can also incorporate compressibility and load/displacement rules or qualifications (all elements) and strategic space and time derivatives to enhance control. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
       So that the manner in which the features and advantages of the invention, as well as others which will become apparent, may be understood in more detail, a more particular description of the invention briefly summarized above may be had by reference to the embodiments thereof which are illustrated in the appended drawings, which form a part of this specification. It is to be noted, however, that the drawings illustrate only various embodiments of the invention and are therefore not to be considered limiting of the invention&#39;s scope as it may include other effective embodiments as well. 
         FIG. 1  is a schematic diagram of drilling equipment for use with embodiments of a system for controlling drilling fluid parameters according to an embodiment of the present invention; 
         FIGS. 2A-2C  are schematic diagrams of drilling equipment according to an embodiment of the present invention; 
         FIG. 3  is a schematic diagram illustrating mass and energy transfer and data communication according to an embodiment of the present invention; 
         FIG. 4  is a schematic diagram of drilling equipment and earth formations according to an embodiment of the present invention; 
         FIG. 5  is a schematic diagram of drilling equipment and earth formations according to an embodiment of the present invention; 
         FIG. 6A-6F  are schematic diagrams illustrating progression of a wellbore during testing according to an embodiment of the present invention; 
         FIG. 7  is a schematic block diagram of functional software/program products modules according to an embodiment of the present invention; 
         FIG. 8  is a schematic flow diagram illustrating a method of controlling drilling fluid parameters according to an embodiment of the present invention; 
         FIG. 9  is a schematic flow diagram illustrating a method of establishing baseline data for controlling drilling fluid parameters according to an embodiment of the present invention; 
         FIG. 10  is a schematic flow diagram illustrating a method of iteratively performing a cased hole pressure test according to an embodiment of the present invention; and 
         FIG. 11  is a schematic flow diagram illustrating a method of performing an integrity and fracture test according to an embodiment of the present invention. 
     
    
    
     DETAILED DESCRIPTION OF THE INVENTION 
     The present invention now will be described more fully hereinafter with reference to the accompanying drawings in which embodiments of the invention are shown. This invention, however, may be embodied in many different forms and should not be construed as limited to the embodiments set forth herein; rather, these embodiments are provided so that this disclosure will be thorough and complete, and will fully convey the scope of the invention to those skilled in the art. Like numbers refer to like elements throughout, and prime or double prime notation where used in association with numbers indicates like elements in alternative embodiments. 
     FIGS.  1  and  2 A- 2 C, the method of this invention illustrate embodiments of a system  22  and method of the present invention in connection with an offshore platform  11 . The invention, however, is also applicable to land well drilling operations. The equipment utilized for drilling offshore well  71  in accordance with this embodiment of a system  22  and method may include a drilling riser  13  that is supported by tensioners (not shown) mounted to platform  11 . The drilling riser  13  has a lower marine riser package  15  at its lower end. The lower marine riser package  15  has pressure control equipment such as an annular blowout preventer that will close around drill pipe or fully close, pipe rams that will close around pipe, and blind rams that will fully close the drilling riser  13 . A string of drill pipe  17  is shown extending through the drilling riser  13 . 
     A rotating control head (RCH)  25  mounts to the upper end of the drilling riser  13 . The RCH  25  has a rotatable annular seal member that seals around and rotates with the drill pipe  17 . The drill pipe  17 , for example, can be rotated by a top drive assembly  27  shown schematically in  FIGS. 1 and 2A , a rotary table (not shown), or other similar device known to those skilled in the art. The unit can have a continuous circulation device  28  that allows drilling fluid circulation to continue while breaking out and making up the threaded joints of the drill pipe  17 . The drilling pipe  17  has an inlet end that can include an analog or digital sensor or monitor  103  to measure various parameters such as, for example, pressure, flow rate, density, temperature, fluid composition, and gas chromatograph information, e.g., molecular composition of the drilling fluid, in a real-time basis as understood by those skilled in the art (see  FIGS. 2A and 3 ). Fluid, as understood by those skilled in the art, can mean liquid fluids, or gas fluids, or a combination of both. 
     As shown in  FIGS. 1 and 2C , for example, a subsea low pressure wellhead housing  37  is at the upper end of the well  71  at the sea floor  39 . The low pressure wellhead housing  37  is located at the upper end of the conductor pipe  41  that extends to a first depth in the well  71 . The conductor pipe  41  can be cemented in place as indicated by the numeral  43 . A high pressure wellhead housing  45  lands in the low pressure wellhead housing  37 . A string of casing  47  extends from the lower end of high pressure wellhead housing  45  to a second depth in the well. The casing  47  is cemented in place as indicated by the numeral  49 . Another string of casing  51  is shown installed in the well. The casing  51  is supported by a casing hanger  53  that lands within the high pressure wellhead housing  45 . The casing  51  is cemented in place as indicated by the numeral  55 . 
       FIGS. 1 and 2C  also show a drill bit  57  attached to the lower end of drill string  17  in the process of drilling on open hole below the lower end of casing  51 . A measuring while drilling (MWD) instrument or logging while drilling (LWD) instrument  59  (see also  FIGS. 3-5 ) can be mounted in the drill string  17  a short distance above the drill bit  57  for making various measurements and sending those measurements to the surface via fluid pulse techniques. As understood by those skilled in the art, the MWD or LWD instrument  59  can be capable of measuring the bottom hole pressure and sending signals to a pulse decoder  60  of a process control system  62  (see  FIGS. 2B and 3 ) at the surface while drilling fluid is being circulated down drill string  17 . A pressure gauge  69  monitors pressure within the drilling riser  13  near the RCH  25  and transmits that information to one or more computers  67 . As understood by those skilled in the art, other surface measurements can be made in conjunction with the other measurements, including various parameters relating to each layer or stratae of earth formation, the pore fluid quantifications within each layer or stratae of earth formation, each string of casing, each layer of cement, as well as the fluid or mud within the drilling pipe  17  and annulus  18 , which can also be included in the computer(s)  67 . These parameters can be measured by a logging tool, logging while drilling (LWD) instrument  59 , or other suitable instrument. 
     An additional string of casing (not shown) or a liner, for example, can be installed when the open hole section shown in  FIG. 1  has reached its desired depth. The additional string of casing may be supported by a casing hanger above the casing hanger  53  in the wellhead housing  45 . If a liner is employed, it can be suspended by a liner hanger mechanism near the lower end of casing string  51  as understood by those skilled in the art. The number of casing strings will differ from well to well based on depth and characteristics of the earth formations. 
     As shown in  FIGS. 1 ,  2 A, and  2 B, the equipment typically includes surface pressure control equipment  19  suspended by the platform  11 . The surface pressure control equipment  19  has the capability of closing around the drill pipe  17  and diverting drilling fluid up through diverter lines (not shown) if excessive pressure in the annulus  18  surrounding the drill pipe  17  is encountered. The surface pressure control equipment  19  can also be able to fully close the riser  13  in the absence of the drill pipe  17 . The fluid is generally understood to be any material that is capable of residing in the pipe, which can include such materials as mud, gases, entrained fluids residing within the mud, cuttings, and other various types of materials, either alone or in combination, which may flow through the drill pipe  17  and the annulus  18 . 
     The drilling equipment at the outlet end of annulus  18  can include an analog or digital sensor or monitor  101  as understood by those skilled in the art can include one or more sensors or a sensor array. The sensor or monitor  101  can measure a variety of parameters such as, for example, pressure, flow rate, density, temperature, fluid composition, and gas chromatograph information in a real-time basis. The outlet end also can include a mixing chamber  105  from which to mix and an injection pump  107  to inject other fluids to the existing fluid or mud at the annulus  18 . The outlet end can also include an output choke  21  at the outlet of the riser  13  for drilling fluid returns from the drill pipe annulus  18 . The output choke  21  is a conventional device that restricts the flow of drilling fluid, affecting pressure within the drilling riser  13  in the drill pipe annulus  18  and inside the drill pipe  17 . The output choke  21  has a drive mechanism that can vary the orifice within the choke  21  to selectively increase and decrease the pressure in the drill pipe  17  and the drill pipe annulus  18 . As illustrated in the embodiment of a system, program product, and a method exemplified in  FIG. 3 , the solid lines connote fluid transfer or transmittal, and the dashed lines connote data transfer or transmittal. Additionally, in  FIG. 3 , a single arrow indicates a one directional flow or transmittal, and a double arrow indicates dual directional flow or transmittal. The dual arrow indicators can be, for example, in the form of back pressure as pertaining to fluids, or in the form of a feedback loop as pertaining to data. 
     The drilling fluid passes through the choke  21  and through the sensors  101  to processing equipment for cleaning and conditioning the fluid, such as a mud/gas separator  113  including, e.g., a gas chromatograph  115 , a set of shale shakers  117 , and perhaps other devices. Shakers  117  screen and remove cuttings from the drilling fluid for analysis, such as shown by box  119 . A fluid treatment device  121  can treat the fluid with a variety of treatments. 
     The drilling fluid flows into a fluid pit  125 , which has a level sensor, a flow rate monitor, a pressure gauge, and a density monitor such as indicated in box  127  and as understood by those skilled in the art. The fluid injection pump  109  draws fluid from the fluid pit  125  through, for example, a mixing chamber  111 , and delivers the fluid through a number of digital or analog sensors or monitors  103  to test or analyze various parameters in a real-time basis, and then flows the fluid into the interior of the drill pipe  17  via, e.g., the top drive  27 . 
     The equipment of this embodiment of the invention also includes a test pump  61  or fluid pumps  129  mounted on platform  11  (see, e.g.,  FIGS. 2A ,  2 B and  3 ). The test pump  61  ( FIG. 2B ) is an accurate low volume pump, preferably of positive displacement. The test pump  61 , for example, need be capable of pumping only a few gallons per minute. A flow meter  63  accurately measures the amount of drilling fluid pumped by the test pump  61 . Also, a pressure gauge  65  (see also pressure speed  131 ) accurately records the pressure of the drilling fluid being pumped by the test pump  61 . The outlet of the test pump  61  leads to the interior of the drilling pipe  17 , for example, at an elevation above the surface pressure control equipment  19 . The test pump  61  has an intake connected with a fluid pit  33 . 
     The computer  67  is located, e.g., at rig  11 , for controlling the choke  21 , the fluid pumps  129  via pressure and speed controller  131 , fluid composition via the mixing chambers  105 ,  111 , and injection pumps  107 ,  109 . The computer  67  includes a processor  73  and memory  75  coupled to the processor  73 . The memory  75  can include volatile and nonvolatile memory known to those skilled in the art including, for example, RAM, ROM, and magnetic or optical disks, just to name a few. The computer  67  includes in memory  75  or has access to one or more databases  66 . The database  66  or databases  66  can include one or more individual modules. The computer  67  also includes inputs as known by those skilled in the art for receiving data from the various parameters and a process control system  62  utilized in real-time. Dynamic density control program product  72  is stored in the memory  73  of the computer  67  to perform the various functions described below. The dynamic density control program product  72  can form part of the process control system  62  or can function as a stand-alone unit capable of communicating with the process control system  62 . The process control system  62  as known and understood by those skilled in the art can be implemented in hardware, software/program product, or a combination thereof. 
     As shown in  FIG. 7 , the computer databases  66  can include parameters relating to each layer or stratae of earth formation, the pore fluid quantifications within each layer or stratae of earth formation, each string of casing, each layer of cement, as well as the fluid or mud within the drilling pipe  17  and the annulus  18 , which can also be included in the computer  67 . The databases  66  of the computer  67  (or a separate database) also can include information concerning the compressibility of the various earth formations, including subsurface stratae and the pore fluids residing within the stratae through which the well will extend and the compressibility of the drilling fluid. The computer databases  66  can include additional parameters such as, for example, pressure, flow rate, density, temperature, fluid composition, and gas chromatograph information in a real-time basis, both at the inlet side of the drill pipe  17  and the outlet end of the annulus  18 . The computer databases  66  also can include a myriad of other parameters, as understood by those skilled in the art, such as, for example, information from the pressure gauge  69  or the mud pulse decoder  60 . 
     As also shown in  FIG. 7 , embodiments of systems, program products, or methods of the present invention can also include other software modules or programs that function as simulators  77  that interact or communicate directly with one or more computers  67  in a real-time basis. A hydraulics simulator  79 , for example, can calculate the frictional pressure drop throughout the system  22 . A hydraulics optimization simulator  81  can optimize hydraulic energy at the drill bit. A pressure control simulator  83  can control kicks that may occur within the system. A wellbore stability simulator  85  can determine fracture pressures and collapse pressures of the earth formation. A drilling simulator  87  can determine rate of penetration parameters. A formation productivity simulator  89  can assess the production impairment due to drilling fluid invasion. A geomechanics model  91  can provide information relating to the way earth formations react with the system under varying conditions of pressure, temperature, density, and flow rate. A wellbore breathing, ballooning, and rebounding simulator  93  can account for the expansion and contraction of the wellbore and surrounding volumes under dynamic conditions. 
     The various components and sensors controlled or monitored by computer  67  can be separately switched on or off according to various combinations, as desired. Further, the various functions of the dynamic density control program product  72 , systems, and the various simulators  77  can be run in parallel for back up, redundancy, to obtain more data points, and/or for comparison for checking with each other, to validate data, to allow one to do some and another others, and/or for calibration based on known guidelines. The surface monitors or sensors  101 ,  103  and bottom hole sensor  59  can each be one or more sensors, preferably a plurality at each sensing location, e.g., input, output, and in well, that can function separately or in unison. Further, the control functions can be shut down in order to function as a conventional system or can be emergency situations so that the original system used by a rig can then be used or reverted back to (or be manually operated) as a back up or precautionary measure. 
     As shown in  FIGS. 1-11 , and embodiment of the system, program product, and methods can provide operators the ability to determine separately for each of the plurality of laterally separated locations of interest at least one drilling fluid control variable system limitation of a drilling fluid control variable, measure a value of an operationally induced drilling fluid parameter at each of a plurality of separate locations when drilling, predict separately for each of the plurality of laterally separated locations of interest a value of the drilling fluid control variable in response to each measured drilling fluid parameter value, and control at least one drilling fluid parameter in response to each predicted control variable value and each associated at least one drilling fluid control variable system limitation. The locations of interest can include a specific weak point in at least one of the plurality of casing strings, a specific weak point in, e.g., at least one cement layer surrounding one of the plurality of casing strings, a portion of an earth formation located, for example, at the bottom of the wellbore, and/or a regions or areas which can change dynamically, can be strategic, and can vary in size and dimension. Ascertaining the general location and effect of such locations of interest are described in more detail, later. 
     More specifically, as perhaps best shown in  FIG. 8 , according to embodiment of the present invention, through performing various tests and/or simulations, the computer  67  can establish local wellhead baseline data separately for each weak point or other locations of interest (block  141 ). The computer  67  either directly from the baseline data or through execution of one or more simulations can determine for each location of interest one or more drilling fluid control variable system limitations of a drilling fluid control variable (block  143 ). By knowing the limitations of each weak point or other location of interest, the operator can establish a desired bottom hole pressure and a combination of drilling fluid parameters, e.g., pressure, flow rate, density, temperature, and composition, that will maintain the drilling fluid within the limitations of each weak point or other location of interest and maintain the desired bottom hole pressure (block  145 ). During drilling operations, the operator will circulate drilling fluid through the drilling fluid circulation components, e.g., pump  129 , drilling string  17  inlet and inlet associated components, drilling string  17 , bottom hole wellbore adjacent the drill bit, annulus  18 , riser  13  outlet, and outlet associated components (block  147 ). During circulation and during drilling, the computer  67  can monitor/measure drilling fluid mass and energy parameters in real-time for drilling fluid entering and exiting the drilling circulation system/components (block  149 ). Through use of the baseline data, simulations, and current drilling fluid parameters, the computer can predict a value of the drilling fluid control variable for each location of interest (block  151 ), and can control a drilling fluid parameter in response to each predicted control variable value and each associated drilling fluid control variable system limitation (block  153 ). 
     As shown in  FIG. 9 , the baseline data can be established through performance of a cased hole pressure test prior to running the drilling string  17  through wellbore conduit (block  161 ), performing a cased hole pressure test after running the drilling string  17  through wellbore conduit (block  163 ), and performing a drilling system integrity and fracture pressure test (block  165 ). These tests are described below. Alternatively, the baseline data can be prestored in databases  66  or determined real-time during actual drilling operations. 
     As perhaps best shown in  FIGS. 6A ,  6 C,  6 E, and  10 , in the embodiment of a system and method of this invention, after conductor pipe  41  or casing  47 ,  51  has been installed and cemented in place, the operator runs a cased hole pressure test. The first cased hole pressure test can occur before drilling out below the lower end of conductor pipe  41 . The operator performs the first part of cased hole pressure test before running the drill string  17  into the riser  13 . The riser  13  is filled with liquid, such as drilling fluid. The operator closes the riser  13  with the surface pressure control equipment  19  and the choke  21  or valves (not shown) between the choke  21  and the riser  13  (block  171 ). The operator then begins applying pressure to the drilling fluid by pumping more drilling fluid into the riser  13  with the test pump  61  (block  173 ). During the test, the operator measures the increase in pressure over time with the pressure gauge  65  (block  175 ). The test pump  61  pumps drilling fluid into the riser  13  while measuring the amount being pumped with the flow meter  63  as well as the pressure with the pressure gauge  65 . For example, the operator can apply pressure to a selected maximum that is a safe level below the yield strength of the riser  13  and the conductor pipe  41 . This pressure causes compression of the drilling fluid, radial expansion of the riser  13 , the conductor pipe  41  and the cement layer  43 . The expansion of the cement layer  43  compresses the surrounding earth formation. Data are generated during this test that are transmitted to the computer  67 . 
     As understood by those skilled in the art, the computer  67  generates a pressure versus volume curve (“PV”). The pressure is the fluid pressure sensed by the pressure gauge  65 , and the volume is the amount of drilling fluid pumped by the test pump  61  during the test. The PV curve is not linear and indicates that, eventually, increased pressure will result in very little increased volume of drilling fluid entering the riser  13 . The computer  67  also generates a pressure over volume versus time (“PVT”) curve (block  177 ). The time is the amount of time occurring during the test. The operator then releases the pressure and turns off the test pump  61  (block  179 ). The flow meter  63  can measure the return flow of drilling fluid flowing back into the fluid pit  33  (block  181 ). The amount returning should be substantially the same as the amount that was pumped in by the test pump  61 . Any difference resulting from the measurement, for whatever reason, will be duly recorded and analyzed (block  183 ). 
     The data generated by this test simulates “breathing” and “ballooning” that occurs during drilling operations. Ballooning occurs as a result of expansion of riser  13 , expansion of conductor pipe  41 , expansion of any strings of casing  47 ,  51 , expansion of the cement, and/or expansion of the rock or earth formation, due to drilling fluid pressures being exerted. The drilling fluid pressure includes the static pressure resulting from the weight of the drilling fluid as well as the flowing or dynamic pressure caused by the operation of fluid pumps  109  and the frictional effects within the conduits, during drilling operations. Breathing occurs as a result of contraction of the riser  13 , contraction of the conductor pipe  41 , contraction of any strings of the casing  47 ,  51 , contraction of the cement, and/or contraction of the rock or earth formation, due to a decrease in fluid pressure. Breathing occurs as a result of the pressure dropping, such as cessation of or reducing the flow rate fluid pumps  129 . Stopping the fluid pumps  129  removes the dynamic pressure component, resulting in a lower pressure being exerted on the conductor  41  and the surrounding earth formation. Lower pressure results in a contraction of the conductor  41  and a return of some of the volume of drilling fluid that occupied the space during the ballooning expansion. 
     After the test has been made as described above, the operator lowers the drill string  17  into the riser  13 . Normally the lower end of the drill string  17  is open, causing it to fill with drilling fluid as it is lowered into the well. The operator performs the same cased hole pressure test with test pump  61  while drill string  17  is located within riser  13  (block  185 ). That test will allow the computer  67  to account for the compressibility of drill pipe  17  as a result of drilling fluid pressure exerted on the interior and exterior of drill pipe  17  (block  187 ). 
     As perhaps best shown in  FIGS. 6B and 11 , the operator then drills down a few feet below the lower end of the conductor pipe  41  (block  191 ) and circulates drilling fluid with the fluid pumps  109  (block  193 ). The operator makes another test a short distance below the conductor pipe  41  in the open hole to determine the integrity of the sealing of cement  43  between the earth formation and the conductor pipe  41 . In this test, the operator will seek to learn the maximum pressure that can exist at the lower end of the conductor pipe  41  without fracturing the earth formation or the bonding of the cement  43 . In one method of performing this test, the operator will begin operating the fluid pumps  129  and circulating the drilling fluid through the choke  21  back to the fluid pit  125  (block  193 ). Downhole pressure MWD instrument  59  senses the dynamic pressure adjacent the lower end of the conductor pipe  41  and transmits data to the fluid pulse decoder  60  and the computer  67  (block  195 ). The operator gradually closes the choke  21  or increases the output pressure of pump  129  (block  197 ), which increases the pressure within the interior of the drill pipe  17  and the drill pipe annulus  18 . Initially, there will be a drop in the fluid pit level due to ballooning. The volume due to ballooning will be known from the earlier cased hole pressure test conducted with the test pump  61 . Any fluid level drop in the fluid pit  33  after the ballooning volume increase will be due to encroachment into the formation or at the bond lines of the cement layer(s)  43 . Eventually, the fracture pressure of the formation is reached, and some drilling fluid will begin encroaching into the earth formation adjacent the lower end of the conductor pipe  41  or through the cement layer  43 . This loss in drilling fluid will be detected by the level sensor  34  and the flow meter  63  (block  199 ). The point at which this detection occurs is deemed the maximum dynamic pressure that can exist at this point in the well (block  201 ). 
     Based on this maximum pressure level at the lower end of the conductor pipe  41 , the computer  67  will compute the maximum dynamic bottom hole pressure at future depths to be drilled. For example, if the maximum dynamic pressure at the lower end of the conductor pipe  41  is 1000 psi, the computer  67 , knowing the variables, such as, for example, weight and rock compressibility, can compute what dynamic bottom hole pressure if measured at a depth 1000 feet deeper would result in the dynamic pressure of 1000 psi at the lower end of the conductor pipe  41 . That bottom hole pressure level might be, for example, 1500 psi. The dynamic bottom hole pressure can be continuously transmitted to the decoder  60  and the computer  67  during drilling by down hole MWD instrument  59 , enabling the operator and the computer  67  to make sure that the maximum dynamic bottom hole pressure at each point drilled does not exceed an amount that would result in an excessive bottom hole pressure at the lower end of the conductor pipe  41 . 
     The operator can make the same series of PV and PVT measurements as described above immediately after setting the second string of the casing  47  and the third string of the casing  51 . The operator will make the same tests in the open hole immediately below the lower end of each string of the casings  47 ,  51  to determine the maximum bottom hole pressure allowable at the lower end of each casing string as each casing string is added. 
     The operator then continues drilling, using a desired fluid weight, pump pressure, and choke adjustment to maintain the desired bottom hole pressure and intermediate component pressures. While drilling, RCH  25  can be sealing around the drill pipe  17 , the pump  129  can be applying a controlled positive pressure, and the choke  21  can be applying a controlled back pressure. Further, other parameters such as, for example, temperature, or gas composition of the drilling fluid when using multiphase drilling fluid, can be adjusted to control dynamic pressure. The surface pressure in the riser  13  can be measured by the pressure gauge  69  and sent to the computer  67 . Normally, the operator will know from calculations and prior information the pore pressure of the various earth formations to be drilled. In overbalanced drilling the weight of the drilling fluid and the setting of the choke  21  is selected so that the dynamic pressure at the lower end of the conductor pipe  41  (or the casing strings  47 ,  51 ) is greater than the pore pressure, but less than the fracture or leak off pressure. In near balanced drilling the dynamic pressure is approximately the same, and in under balanced drilling, the dynamic pressure is less than the pore pressure. All three types of drilling may be performed with embodiments of systems and methods of the present invention. 
     Embodiments of the system, program product, and methods of the present invention provides a real-time solution to maintain the bottom hole pressure between the pore pressure and the maximum fracture pressure or lost circulation pressure by continually comparing the bottom hole pressure to the pore pressure and the maximum fracture or lost circulation pressures. Pressure of the drilling fluid can be controlled by adjusting the weight of the drilling fluid. The weight of the drilling fluid may be adjusted by regular conventional procedures. For example, the weight may be increased by adding more solids and fluid chemicals and lightened by introducing liquids or gases such as nitrogen into the drilling fluid at the platform. The bottom hole pressure may be increased by gradually adding more weight to the drilling fluid, adjusting the orifice of the choke  21  to increase the backpressure, or increasing pump pressure of the pump  129 , or a combination thereof. The bottom hole pressure may be decreased by adding lower density material, e.g., nitrogen, to the drilling fluid, adjusting the orifice of the choke  21  to decrease back pressure, decreasing pump pressure of the pump  129 , or a combination thereof. Further, according to an embodiment of the system, backpressure can be increased during both drilling operations and when not drilling by adding/injecting drilling fluid into the annulus  18  and correspondingly decreased by removing drilling fluid from the annulus  18 . Still further, bottom hole pressure may be modified by adjusting the drilling fluid temperature as known and understood by those skilled in the art. 
     Drilling fluid measurements can be made. For example, the drilling fluid can be circulated through the system in a systematic manner utilizing the method of the present invention illustrated in  FIG. 3 . As the fluid returns through the outlet side of the annulus  18 , the fluid is flowed through a series of analog or digital monitors  101  that can measure pressure, flow rate, density, temperature, fluid composition, gas chromatograph information, and other useful information. The analog or digital monitor  101  is in data communication with the computer  67  and the database  66 . The fluid then flows through a mixing chamber  105  where other fluids or other substances may be added thereto, and then through an injection pump  107 , and then through an analog or digital choke  21 , each of which are in data communication with the computer  67  and the database  66 . 
     Then the fluid can flow through a mud/gas separator  113 , which produces a gas chromatograph in data communication with the computer  67  and the database. Then the fluid can flow through the shale shaker  117 , which produces a cuttings analysis  119  in data communication with the computer  67  and the database  66 . 
     Then the fluid can flow through the fluid treatment chamber  121  where other solids, fluids, chemicals, or other substances can be added thereto, and which is in data communication with the computer  67  and the databases  66 . Then the fluid can flow through the fluid pit  125 , which evaluates and monitors pit level or fluid level, flow rate, pressure, density, or other parameters  127  which are in data communication with the computer  67  and the database  66 . 
     Then the fluid can flow though the fluid pump chamber of fluid pump  65 ,  129 , which regulates the pressure speed control  131  by being in data communication with the computer  67  and databases  66 . Then the fluid can flow through another mixing chamber  111  where fluids or other substances may be added thereto, and then through another injection pump  109 , each of which are in data communication with the computer  67  and database  66 . As the fluid circulates through the system, the fluid is flowed through another series of analog or digital monitors  103  that can measure pressure, flow rate, density, temperature, fluid composition, gas chromatograph information, and other useful information. The analog or digital monitor  103  is in data communication with the computer  67  and the database  66 . Finally, then the fluid can flow into the inlet side of the drill pipe  17  for circulation through the drill pipe  17  and into the annulus  18 . 
     While drilling, if the pit level sensor  127  indicates a drop in the volume of fluid, this information will be supplied to the computer  67  to determine whether or not lost circulation exists. A drop in drilling fluid volume may be indicative of well bore expansion due to ballooning, which happens when the fluid pumps  109  are initially turned on or the back pressure in annulus  18  increased. Alternately, a loss in fluid pit level while drilling could indicate that lost circulation is occurring wherein drilling fluid flows into one of the earth formations in an excessive amount. The computer  67  makes an analysis of the loss in fluid volume based upon the PV and PVT curves and the data stored concerning the compressibility of the earth formations, including subsurface stratae and the pore fluids residing within the stratae and the compressibility of the drilling fluid. The computer  67  can inform the operator of the reason for the change in fluid volume, enabling the operator to take remedial action if necessary. 
     The fluid or mud head pressure within the annulus  18 , just outside the drill bit  57 , is Known as the equivalent circulating density (ECD) or the circulating bottom hole pressure. The fluid or mud head pressure or circulating bottom hole pressure is substantially equal to the sum of the static pressure, and the pressure due to annular friction losses in the annulus  18 . The circulating bottom hole pressure, in an embodiment, can be maintained at a pressure greater than the pore pressure resulting from the particular layer or strata of earth formation, and maintained at a pressure less than the maximum fracture pressure gradient of the casing and cement structures. Correspondingly, embodiments of a system and a method of the present invention provides a real-time solution to maintain the bottom hole pressure between the pore pressure and the maximum fracture pressure (or lost circulation pressure) by continually comparing the bottom hole pressure to the pore pressure and the maximum fracture or lost circulation pressures. 
     Embodiments of the system and methods can also control fluid kicking. Fluid kicking, as understood by those skilled in the art, occurs when the pore pressure from one of the stratas of earth formation is greater than the fluid or mud head pressure. In the event of a fluid kick, the bottom hole pressure sensed by the MWD instrument  59  normally will initially increase. Also, a kick would normally result in some increase in the level of drilling fluid in the fluid pit  33  as sensed by sensor  34 . The increase in bottom hole pressure and increase in the fluid pit  33  level could also be due to a breathing in of the earth formation and various strings of casing and cement. The computer  67  refers to the PV and PVT curves to determine whether or not the increase in bottom hole pressure or increase in the pit  33  level is due to breathing or due to a fluid kick. If due to a breathing in, the computer  67  may adjust the choke  21  for a short while to reduce the bottom hole pressure. If the computer  67  determines that a fluid kick is occurring, drilling may continue while the fluid kick is circulated out. As the gas expands, choke pressure is changed such that bottom hole pressure remains constant as determined by the MWD measurement, and fracture pressure at the casing seat uphole is not breached. 
     Operators ordinarily will not be certain whether a source of back pressure is due to kicking or merely due to breathing after previous ballooning. In any event, to overcome or kill the kicking, the system or method can circulate more mud through the drill pipe  17  to increase the mud weight to respond to the apparent kicking. This acts to force the kicking fluid out from the annulus  18  while increasing the weight and density of the fluid or mud circulating through the drill pipe  17  and the annulus  18 , and restore the circulating bottom hole pressure as being greater than the pore pressure from the earth formation. If the circulating bottom hole pressure becomes greater than the maximum fracture pressure gradient, it can cause a fracture of the casing and cement structures and a subsequent loss of circulation. Therefore, embodiments of the system or method can increase the weight and density of the fluid or mud cautiously and/or can simultaneously add choke pressure to prevent kicking and can decrease the weight and density of the fluid or by cautiously and/or simultaneously reduce choke pressure so as to prevent the bottom hole pressure from exceeding the maximum fracture pressure. Embodiment of the present invention can also increase input pump pressure and/or inject fluid into the annulus  18 , or a combination thereof. 
     The PV curve and the PVT curve along with the data concerning the formations enable the operator to more accurately control the bottom hole pressure and thus the dynamic pressure at the lower ends of the casing strings  47 ,  51 . This information takes into account the compressibility of the drilling fluid both in the drill pipe  17  and in the annulus  18 . The computer  67  also takes into account expansion and contraction of the riser  13 , casing  41 , casing strings  47 ,  51 , and the drill pipe  17  as well as the earth formations, including subsurface stratae and the pore fluids residing within the stratae surrounding the bore hole. This information also allows the computer  67  to determine whether or not a kick, lost circulation, ballooning or breathing is occurring. This embodiment of a system avoids the need to stop drilling to add additional weight to the drilling fluid. With more accurate control, in some cases one or more casing strings may be eliminated. 
     Embodiments of system and method the present invention can advantageously provide real-time measuring to ensure conservation of matter and conservation of energy in both the well bore and the surrounding subsurface stratae. For example, the material/mass balance into the drill pipe  17  during normal operations should be substantially the same as the material/mass balance out of the annulus  18  as measured by the parameters of the fluid flowing into the drill pipe  17 , and the energy balance into the drill pipe  17  should be substantially the same as the energy balance out of the annulus  18  as measured by the parameters of the fluid returning from the annulus  18 , taking into account the mass and energy balances in all subsurface components. Any deviations from the material/mass balances or energy balances will be recorded. In addition to providing for conservation of matter and conservation of energy during ordinary drilling operations, the invention can also advantageously provide a real-time method for increasing the fluid or mud head pressure within the drill pipe  17  and annulus  18  in the event of a fluid kick from the subsurface stratae, or even in the event of a sequence of ballooning and breathing that skilled artisans may perceive as a fluid kick from the subsurface stratae. 
     Embodiments of a dynamic density control system of the present invention is a highly adaptive, real-time, process-control extension of managed pressure drilling with unlimited scalability to any rig, whether large or small, whether on land or on water. Embodiments of the system or method simultaneously quantifies and utilizes combined static and dynamic stresses and displacements at strategic locations within and around both sides of an apparatus, such as a wellbore U-Tube and its several constituent elements, as the well is being drilled. Dynamic pressures at strategic locations in the system are advantageously determined and controlled such that insitu and operationally induced pressure window limitations at specific weak-points are not breached. 
     Applications for embodiments of systems, program products, and method of the present invention include, for example situations where critical pressure magnitudes and small pressure tolerances, particularly in deepwater operations, have increasingly large economic, technical, safety, and environmental consequences. Productivity impairment during drilling/completion operations is also of great consequence on land or water, and the embodiments may be advantageously utilized on any rig to minimize formation damage during well construction. 
     Operational wellbore and near-wellbore processes involve several time-varying bulk volumes, stresses, pressures, fluids, and temperatures, coupled and associated with flows, displacement, and movements, some in series and some in parallel fashion. Embodiments of systems, program products, and methods of the present invention can advantageously utilize the coupling of feedback loop control with high-rate, high-quality, time-lapse data logging when circulation is initiated, continued, stopped, or changed, including drill string operations. 
     Embodiments of systems, program products, and methods of controlling drilling pressures, according to embodiments of the present invention, for example, advantageously provide DDC and DMW. These embodiments having DDC provide highly adaptive, real-time, process control and can be scalable to any rig, large or small, on land or water. Embodiments of systems, program products, and methods also advantageously allow combined static and dynamic stresses and displacements to be determined continuously at strategic locations in and around the wellbore so that insitu and operationally induced pressure window limitations at specific weak-points are controlled. By coupling feedback loops and high-rate, high-quality, time-lapse data logging, for example, embodiments of the present invention allow an operator/service company team to “walk-the-line” or even “move-the-line”. 
     For example, as illustrated in  FIG. 5 , mass and energy balances for an active system account for time-varying bulk volumes, stresses, pressures, fluids, and temperatures, coupled and associated with flows, displacement or movement. On or off switching circuitry can activate individual system element quantifiers in isolation or coupled with other elements. Particularly, all processing functions of computer  67  can be shut off to allow the system  22  to revert to a conventional system. 
     Additionally, many applications for embodiments of systems, program products, and methods of the present invention abound. For example, applications can include where critical pressure magnitudes and small pressure tolerances have large economic, technical, safety, and environmental consequences; in distinguishing between kicking flow and ballooning flow in kick/loss scenarios; in minimizing formation damage during drilling/completion operations; in identifying likely trouble spots in advance; and in training, predictive, what-ifs, and case studies. 
     It is important to note that while embodiments of the present invention have been described in the context of a fully functional system, those skilled in the art will appreciate that much of the mechanism of the present invention and/or aspects thereof are capable of being distributed in the form of a computer readable medium of instructions in a variety of forms for execution on a processor, processors, or the like, and that the present invention applies equally regardless of the particular type of signal bearing media used to actually carry out the distribution. Examples of computer readable media include but are not limited to: nonvolatile, hard-coded type media such as read only memories (ROMs), CD-ROMs, and DVD-ROMs, or erasable, electrically programmable read only memories (EEPROMs), recordable type media such as floppy disks, hard disk drives, CD-R/RWs, DVD-RAMs, DVD-R/RWs, DVD+R/RWs, flash drives, and other newer types of memories, and transmission type media such as digital and analog communication links. Such media can include both operating instructions and instructions related to the dynamic density control program product  72  and much of the method steps described above. Such media can also include instructions related to the software/program product portion of the process control system and/or the data contained in databases  66 , and/or some or all of the simulators  77 . 
     For example, embodiments of the present invention can include a computer readable medium that is readable by a computer  67  positioned to control drilling fluid parameters, e.g. pressures, in a drilling system  22 . The computer readable medium can include a set of instructions that, when executed by the computer, cause the computer to perform the operation of determining separately for each of a plurality of laterally separate locations of interest in a drilling system  22  having at least one casing string  47 ,  51  or conductor  41  positioned in a wellbore and a drilling string  17  positionable therethrough at least one drilling fluid control variable system limitation of a drilling fluid control variable. The instructions can also include those to perform the operation of measuring a value of an operationally induced drilling fluid parameter at each of a plurality of separate locations when drilling, predicting separately for each of the plurality of laterally separated locations of interest a value of the drilling fluid control variable responsive to each measured drilling fluid parameter value, and controlling a drilling fluid parameter responsive to each predicted control variable value and each associated at least one drilling fluid control variable system limitation. 
     In the exemplary case where the controlled drilling fluid parameter is dynamic pressure, according to an embodiment of the computer readable medium, the operation of controlling can include modifying fluid pressure of the drilling fluid delivered to a drilling fluid inlet for the drilling system  22  real-time during drilling operations. Further, the operation of controlling can include modifying pressure of the drilling fluid at both the drilling fluid inlet and the drilling fluid outlet during drilling operations. Alternatively, the operation of controlling includes modifying temperature of the drilling fluid delivered to the drilling fluid inlet. When the drilling fluid is a multiphase fluid, the operation of controlling includes modifying inert gas content of the drilling fluid. According to another alternative, the operation of controlling can further includes modifying the density of the drilling fluid by supplying a gas to the primarily liquid drilling fluid to reduce dynamic pressure at at least one of the plurality of locations of interest. Pressure, temperature, density, composition are all parameters that can be controlled individually or in combination, utilizing the drilling system components described previously. 
     According to an embodiment of the computer readable medium, the operation of determining at least one drilling fluid control variable system limitation for each of the plurality of locations of interest can include performing at least one cased hole pressure test prior to running the drilling string  17  through the casing string  47 ,  51  to determine an amount of drilling fluid volume input into the drilling system  22  attributable to ballooning during drilling operations, performing at least one cased hole pressure test after running the drilling string to determine an amount of drilling fluid volume input into the drilling system  22  attributable to compression of the drilling string  17  during drilling operations, and performing a drilling system integrity and fracture pressure test to determine integrity of cement  49 ,  55  sealing the casing string  47 ,  51 , or cement  43  sealing the conductor  41  to the wellbore to thereby determine a maximum pressure that can exist at the lower end of the casing string or conductor without fracturing and associated earth formation or bonding of the cement. These data can be used to describe the physical characteristics of the drilling system to thereby predict the dynamic parameters of the drilling fluid during drilling operations. 
     As previously shown and described with respect to  FIGS. 6A ,  6 C,  6 E, and  10 , the operation(s) of performing a cased hole pressure test includes signaling a pump controller of a pressure pump, e.g., test pump  63 , to pump additional fluid into the drilling system to thereby compress the drilling fluid, radially expand the casing string and associated cement layer, and compress an earth formation surrounding the wellbore. The test can also include the operations of measuring over time an increase in fluid pressure and volume of fluid pumped into the drilling system  22 , generating at least one of the following: a pressure verses volume curve and a pressure verses volume versus time curve, signaling a pump controller of the pressure pump  63  to cease pumping to allow return of fluid not lost to the surrounding formation, measuring an amount of fluid returned; and determining a difference between the amount of additional fluid pumped into the drilling system  22  and the amount of fluid returned, the difference indicating at least one of the following: an amount of potential expansion of components of the drilling system  22  due to a high pressure condition, an amount of potential contraction corresponding with removal of the high-pressure condition. When performed with the drilling string  17  run inside the riser  13 , the test can provide an amount of compressibility of the drilling string  17  due to a high-pressure condition. The computer  67  can use pressure gauges  65 ,  69 , and the sensor components shown, for example, in  FIG. 3 . Beyond data usable for performing various simulations, the data provided can also include data necessary to determine an effect of mud channels in the casing string cement responsive to results of the cased hole pressure test. 
     A difference between the amount of additional fluid pumped into the drilling system and the amount of fluid returned defines a ballooning volume. As previously shown and described with respect to  FIGS. 6B ,  6 D,  6 F, and  11 , the operation of performing a drilling system integrity and fracture pressure test can include determining a steady-state dynamic pressure adjacent the bottom hole of the wellbore, increasing pressure in the drilling system  22 , detecting a loss in fluid volume greater than the ballooning volume, and determining fracture pressure responsive to detecting a loss in fluid volume to thereby determine a maximum dynamic pressure for the respective location of interest. Beyond data usable for performing various simulations, the data provided by both of the above tests can also include data necessary to determining a maximum dynamic bottom hole pressure at future depths to be drilled responsive to at least a portion of the local wellhead baseline data results to thereby enhance drilling requirements management. 
     The operation of predicting a value of the drilling fluid control variable for each of a plurality of weak points or other locations of interest can include the operations of establishing a desired bottom hole pressure responsive to a pressure level limitation for each location of interest, monitoring a drilling fluid mass and energy parameters in real-time for drilling fluid entering and exiting the drilling system  22 , and executing a plurality of simulations using a corresponding plurality of drilling system simulators (see, e.g.,  FIG. 7 ) in response to the local well baseline data to determine for each of the locations of interest. The limitations can include a maximum pressure level, e.g., fracture or component maximum pressure, and a minimum pressure level, e.g., pore pressure, to support drilling operations. 
     The operation of controlling a drilling fluid parameter correspondingly can include includes the operation of modifying one or more of the drilling fluid parameters alone or in combination within the drilling string  17  and/or annulus  18  of the drilling system  22 , to control the bottom hole pressure within constraints of each pressure level limitation for the locations of interest. 
     According to an embodiment of the present invention, also provided is a computer readable medium that is readable by a computer  67  controlling drilling fluid pressures in a drilling system  22 , which can include instructions that, when executed by the computer, cause the computer to perform the operations of forming a pressure volume and pressure volume time curve describing a location of interest within a drilling system  22 , detecting a change in fluid volume responsive to the pressure volume and pressure volume time curve and earth formation compressibility data including that for subsurface strata and pore fluids residing within the strata, and compressibility of the drilling fluid, and differentiating between drilling system component ballooning and lost circulation and between drilling system component breathing and a fluid kick when performing drilling operations. According to an embodiment of the computer readable medium, as described in more detail previously, the operation of forming a pressure volume and pressure volume time curves can include signaling a pump controller of a pressure pump  63  to pump additional fluid into the drilling system to thereby compress the drilling fluid, radially expand the casing string  47 ,  51 , and conduit  41  and associated cement layers  49 ,  55 ,  43  and compress an earth formation surrounding the wellbore, and  10  measure over time an increase in fluid pressure and volume of fluid pumped into the drilling system. 
     This application relates to International Application No. PCT/US2006/025964 filed Jun. 30, 2006, U.S. Patent Application No. 60/701,744, filed on Jul. 22, 2005 and U.S. Patent Application No. 60/696,092, filed on Jul. 1, 2005, each incorporated herein by reference in its entirety. 
     In the drawings and specification, there have been disclosed a typical preferred embodiment of the invention, and although specific terms are employed, the terms are used in a descriptive sense only and not for purposes of limitation. The invention has been described in considerable detail with specific reference to these illustrated embodiments. It will be apparent, however, that various modifications and changes can be made within the spirit and scope of the invention as described in the foregoing specification and as defined in the attached claims.