Office Action 2: Notice of Allowance (2025-02-25)

CLAIMS:
Amendments to the Claims

This listing of claims replaces all prior versions and listings of claims in the application.

Listing of Claims:

Application No. : 18/463,957

1\. (Currently Amended) An insertion tool assembly for disposing a back-pressure valve (BPV) in a tubing hanger installed in a wellhead of a well, the insertion toolassembly configured to isolate pressure from the well when attached to a top-most crown of the wellhead and the BPV configured to, when disposed in the tubing hanger, prevent fluid flow from the well through the wellhead while permitting fluid to be pumped into the well, the insertion tool assembly comprising:
a lubricator comprising a rod slidably disposed therein, the rod configured such that the BPV can be releasably attached to a distal end of the rod;
a tubular adapter comprising:a main body with a top end and a bottom end and a central bore therethrough, the top end detachably attached to the lubricator and the bottom end configured to be detachably attached to the crown top of the wellhead, wherein an internal diameter of the central bore is greater than an external diameter of the BPV; and
a kill fluid port disposed through a side-wall of the main body, wherein the insertion tool assembly is configured such that, when the BPV is attached to the distal end of the rod and the bottom end of the tubular adapter is attached to the crown top:
the BPV can pass through the tubular adapter and into the wellhead through the crown top as the rod is extended from the lubricator; and a kill fluid injected into the kill fluid port and uphole ofthe BPV while the BPV is fully retracted into the tubular adapter can flow through the crown top into the well.

2\. (Original) The insertion tool assembly of claim 1, wherein the insertion tool assembly is configured such that, when a crown valve of the wellhead is open, the kill fluid flowing into the tubular adapter flows vertically through the crown top into the well through the crown valve.

3\. (Original) The insertion tool assembly of claim 1, wherein the insertion tool assembly is configured such that, when kill fluid flows through the crown top into the well, all wellhead valves through which the rod can pass when extended are open.

4\. (Original) The insertion tool assembly of claim 1, wherein the kill fluid flowing through the crown top into the well flows through the BPV.

5\. (Original) The insertion tool assembly of claim 1, wherein the BPV, when attached to the distal end and the rod fully retracted, does not extend past the bottom end.

6\. (Original) The insertion tool assembly of claim 1, wherein the insertion tool assembly is configured such that injection of a fluid into the kill fluid line port from the fluid line dislodges debris within the central bore.

7\. (Original) The insertion tool assembly of claim 1, wherein the assembly is configured such that the crown top of the wellhead can remain closed as the bottom end is attached to the bottom end and can be opened after attaching the bottom end to the crown top.
8\. (Currently Amended) A method comprising:
attaching, to a crown top of a wellhead of a well, an insertion tool assembly for disposing a back-pressure valve (BPV) in a tubing hanger installed in a wellhead, the insertion tool assembly comprising:a lubricator comprising a rod slidably disposed therein, wherein the BPV is releasably attached to a distal end of the rod; and
a tubular adapter comprising:
a main body with a top end and a bottom end and a central bore therethrough, the top end detachably attached to the lubricator and the bottom end configured to be detachably attached to the crown of the wellhead, wherein an internal diameter of the central bore is greater than an external diameter of the BPV; and a kill fluid port disposed through a side-wall of the main body;

extending the rod and thereby passing the BPV through the tubular adapter and into the wellhead through the crown top; and
in response to a well control event indication, injecting a kill fluid into the kill fluid port, thereby flowing kill fluid through the crown top into the well, wherein the insertion tool assembly is configured such that injection of a fluid into the kill fluid line port from the fluid line dislodges debris within the central bore and injection of the fluid occurs uphole of the BPV while the BPV is fully retracted into the tubular adapter.

9\. (Original) The method of claim 8, wherein the kill fluid flowing through the crown top into the well flows into the well through an open, top-most valve of the wellhead below the crown top.

10\. (Original) The method of claim 8, wherein, when the kill fluid flows through the crown top into the well, all wellhead valves through which the rod is configured to pass when the rod is extended are open.

11\. (Original) The method of claim 8, wherein the kill fluid flowing through the crown top into the well does not flow through the BPV to the crown top when the rod is in a retracted position.

12\. (Original) The method of claim 8, wherein the kill fluid flowing through the crown top into the well flows through the BPV.

13\. (Original) The method of claim 8, wherein the insertion assembly is configured such that, when the BPV is attached to the distal end and the rod fully retracted, the BPV does not extend past the bottom end.

14\. (Canceled)

15\. (Canceled)

16\. (Currently Amended) A method comprising:
attaching a top end of a tubular adapter to a lubricator, the lubricator comprising a rod slidably disposed therein, the rod configured such that a back-pressure valve (BPV) can be releasably attached to a distal end of the rod, the tubular adapter comprising:a main body with a top end and a bottom end and with a central bore therethrough; and
a kill fluid port disposed through a side-wall of the main body;
while maintaining a crown top valve of a crown top of a wellhead of a well closed and the rod fully retracted such that the BPV attached to its distal end is within the central bore and above the bottom end, attaching the bottom end of the tubular adapter to the crown top;
after attaching the bottom end to the crown top, opening the crown top valve;
after opening the crown top valve, extending the rod and thereby passing the BPV out the bottom end of the tubular adapter and into the wellhead through the crown top;
after the extending, retracting the BPV from the wellhead with the rod and into the central bore of the tubular adapter above the bottom end and thereafter closing the crown top valve while the bottom end remains attached to the crown top; and
injecting a fluid comprising a surfactant into the kill fluid port in response to an indication of debris on or proximate the BPV, wherein the insertion tool assembly is configured such that the injection of the fluid occurs uphole of the BPV while the BPV is fully retracted into the tubular adapter.

17\. (Original) The method of claim 16, further comprising, in response to a well control event indication while the bottom end of the tubular adapter is attached to the crown top and the crown valve is open, injecting a kill fluid into the kill fluid port, thereby flowing kill fluid through the crown top into the well.

18\. (Canceled)

19\. (Canceled)

Filed : September 8, 2023

20\. (Currently Amended) The method of claim 16, wherei, when the BPV is attached to the distal end and the rod fully retracted, the BPV does not extend past the bottom end.

OFFICE ACTION:
DETAILED ACTION
Notice of Pre-AIA  or AIA  Status
The present application, filed on or after March 16, 2013, is being examined under the first inventor to file provisions of the AIA . The amendments of 22 Oct 2024 have been entered.
Response to Arguments
Applicant’s arguments, see Remarks page 8 line 9, filed 22 Oct 2024, with respect to the drawings have been fully considered and are persuasive.  The objection of 30 Jul 2024 has been withdrawn.
Applicant’s arguments, see Remarks page 8 line 15, filed 22 Oct 2024, with respect to claim(s) 8-20 have been fully considered and are persuasive.  The rejection of 30 Jul 2024 has been withdrawn.
Applicant’s arguments, see Remarks page 8 line 18, filed 22 Oct 2024, with respect to claim(s) 1, 8 and 16 have been fully considered and are persuasive.  The rejections of 30 Jul 2024 have been withdrawn.
EXAMINER’S AMENDMENT
An examiner’s amendment to the record appears below. Should the changes and/or additions be unacceptable to applicant, an amendment may be filed as provided by 37 CFR 1.312. To ensure consideration of such an amendment, it MUST be submitted no later than the payment of the issue fee.
The application has been amended as follows:
In the claim:
Claim 13 line 1 “wherein the insertion assembly” has been changed –wherein the insertion tool assembly--.
Allowable Subject Matter
Claim(s) 1-13, 16, 17 and 20 are allowed.
The following is an examiner’s statement of reasons for allowance:
The prior art Ronne (WO 2019027448), Jaffrey (US 20170167220), Lantier Sr. (USP 5,320,181), Bowen Jr et al (US 20180003002), El Sayed (US 20220290524), Villa (US 20120024521), Santos (US 20110214882) and Mason et al. (US 20120220501). The prior art discloses wherein the fluid is injected below the BPV, not above the BPV while fully retracted into the tubular adapter.
Any comments considered necessary by applicant must be submitted no later than the payment of the issue fee and, to avoid processing delays, should preferably accompany the issue fee.  Such submissions should be clearly labeled “Comments on Statement of Reasons for Allowance.”
Conclusion

APPLICANT REBUTTAL: REMARKS
Claims 1-20 are pending in the Application. Claims 1-20 are rejected. Applicant
respectfully traverses all of the rejections and objections, including any assertions therein; and therefore, requests reconsideration.
Objection to Drawings
The drawings are objected to as failing to comply with 37 CFR 1.84(p)(5) because element 200 in Figure 2B is not mentioned in the description.
Applicant respectfully requests withdrawal of the objection to the drawings in light of the above amendments to the specification.
Claim Rejections - 35 U.S.C. § 112(b)
Claims 8-20 are rejected under 35 U.S.C. § 112(b) as being indefinite for failing to particularly point out and distinctly claim the subject matter which the inventor or a joint inventor, or for pre-AIA the applicant regards as the invention.
Applicant respectfully requests withdrawal of the rejections of the claims under 35 U.S.C. § 112(b) in light of the above amendments.
Allowable Subject Matter
Applicant acknowledges, with thanks, the indication that claims 15 and 19 contain allowable subject matter. In this amendment, claim 8 is hereby amended as shown above to include features of claims 14 and 15, and claim 16 is hereby amended as shown above to include the features of claims 18 and 19. Claims 14, 15, 18, and 19 are hereby canceled. Accordingly, Applicant respectfully request allowance of amended claim 8 and its dependent claims and of amended claim 16 and its dependent claims.
Claim Rejections - 35 U.S.C. Q 103
Claims 1-8 and 12-14 are rejected under 35 U.S.C. § 103(a) as being unpatentable over WO Publication No. WO 2019027448 to Ronne ("Ronne") in view of U.S. Publication No. 20170167220 to Jaffrey ("Jaffrey") and U.S. Patent No. 5,320,181 to Lantier, Sr et al. ("Lantier") and U.S. Publication No. 20180003002 to Bowen, Jr et al. ("Bowen").
Claims 16 and 20 are rejected under 35 U.S.C. § 103(a) as being unpatentable over U.S. Publication No. 20220290524 to El Sayed ("El Sayed") maybe in view of U.S. Publication No. 20120024521 to Villa ("Villa").
Claim 17 is rejected under 35 U.S.C. § 103(a) as being unpatentable over El Sayed and Villa as applied to claim 16 above, and further in view of U.S. Publication No. 20110214882 to Santos ("Santos").
Claim 18 is rejected under 35 U.S.C. § 103(a) as being unpatentable over El Sayed and Villa as applied to claim 16 above, and further in view of U.S. Publication No. 20120220501 to Mason et al. ("Mason").
As noted above, independent claims 8 and 16 have been amended so as to include the allowable subject matter and to place claims 8 and 16 and their respective dependent claims in condition for allowance.
With respect to claims 1-7, independent claim 1 is hereby amended and Applicant
respectfully requests reconsideration in light of this amendment. The amendment to claim 1 provides that the insertion tool assembly is configured such that the kill fluid is injected "while the BPV is fully retracted into the tubular adapter." As noted in the Office Action, the combination of the cited references merely discloses an assembly in which kill fluid is injected below a BPV, not above the BPV, while the BPV is fully retracted into a tubular.
Applicant, therefore, respectfully requests withdrawal of the rejection to claim 1 and allowance of its dependent claims 2-7.
Request for Interview
If the present Application is not allowed and/or if one or more of the rejections is maintained, Applicant hereby requests a telephone conference with the Examiner and further requests that the Examiner contact the undersigned attorney to schedule the telephone conference.
CONCLUSION


CITED REFERENCE SUMMARIES: Ref US20170167220: Claims:
1. A rain blowout preventer (“BOP”) assembly, comprising:
a body comprising a vertical bore extending through the body, a rain cavity intersecting the bore, and a port located below the rain cavity;
a pair of opposing rams movable laterally into and out of the BOP vertical bore; and
a sensor assembly located in the port and configured to monitor the position of at least one opposing rain.
2. The assembly of claim 1, wherein each opposing rain comprises a detection feature located on a lower surface of the rain and configured to be detected by the sensor assembly.
3. The assembly of claim 2, wherein the detection feature comprises a visual indicator.
4. The assembly of claim 2, wherein the detection feature comprises a radio frequency identification (“RFID”) tag.
5. The assembly of claim 1, wherein the sensor assembly is configured to be calibrated depending on a velocity of sound of a fluid in the vertical bore.
6. The assembly of claim 1, wherein the sensor assembly is configured to monitor the position of each opposing rain during movement of each rain.
7. The assembly of claim 1, further comprising another port configured to provide for fluid communication with the vertical bore.
8. The assembly of claim 7, wherein the another port is a choke or kill port.
9. The assembly of claim 1, comprising multiple sensors located in the port configured to monitor the position of each opposing rain.
10. The assembly of claim 1, where the sensor assembly is powered by a power source local to the blowout preventer assembly.
11. The assembly of claim 1, wherein the opposing rams are each one of a shear rain, a pipe rain, variable-bore rain, blind shear rain, or a blind rain.
12. The assembly of claim 1, wherein the sensor is configured to be retrofitted to the port.
13. A blowout preventer (“BOP”) rain detection assembly for detecting the position of a rain in a BOP assembly, the detection assembly comprising:
a rain moveable within the BOP assembly and comprising a detection feature located on a lower surface of the rain;
a sensor assembly locatable in the BOP assembly and configured to detect the position of the rain by detecting the detection feature.
14. The assembly of claim 13, wherein the detection feature comprises a visual indicator.
15. The assembly of claim 13, wherein the detection feature comprises a radio frequency identification (“RFID”) tag.
16. The assembly of claim 13, wherein the sensor is configured to be calibrated depending on a velocity of sound of a fluid in the vertical bore.
17. The assembly of claim 13, wherein the sensor assembly is configured to monitor the position of the rain during movement of the rain.
18. The assembly of claim 13, wherein the detection feature is retrofittable to the rain.
19. The assembly of claim 13, further comprising a plurality of detection features.
20. A method for monitoring the position of a rams within a blowout preventer (“BOP”), comprising:
providing a detection feature on a lower surface of the rain;
providing a sensor assembly in a port located in the BOP below the rain;
moving the rain within the BOP; and
monitoring the position of the rain by detecting the detection feature with the sensor assembly.
Ref US20180003002: Claims:
1. A method of sealing a well bore production tubing string at a well tubing head using a test-port pressure actuated sealing apparatus installed in-line with the well bole production tubing string.
2. The method of sealing the well bore production tubing string of claim 1 wherein the method further comprises the following steps:
adapting an improved tubing hanger to the well tubing head,
the improved tubing hanger having
the test-port pressure actuated sealing apparatus installed in-line with the well bore production tubing string,

the well tubing head having a standard test-port in communication with the improved tubing hanger,

utilizing a void space created between the improved tubing hanger and the well tubing head,
the void space having fluid communication with the standard test-port and further fluid communication with the test-port pressure actuated sealing apparatus,

applying introduced pressure through the standard test-port,
building the introduced pressure within the void space,
overcoming well pressure pressing up from the well bore production tubing string with the introduced pressure applied through the standard test-port and transferred via fluid communication through the void space to the test-port pressure actuated sealing apparatus, and
actuating the test-port pressure actuated sealing apparatus to seal the well bore production tubing string.
3. The method of claim 2 wherein the test-port pressure actuated sealing apparatus of the improved tubing hanger further comprises:
a body,
a transfer component,
an actuating mechanism, and
a sealing valve,
wherein the body houses the transfer component, the actuating mechanism, and the sealing valve.
4. The method of claim 3 wherein the body is in fluid communication with the test-port.
5. The method of claim 3 wherein the introduced pressure within the void space displaces the transfer component.
6. The method of claim 5 wherein the transfer component initiates the actuating mechanism.
7. The method of claim 6 wherein the actuating mechanism moves the sealing valve.
8. The test-port pressure actuated sealing apparatus of claim 3 wherein the body is adapted to sealably join with the well tubing head.
9. The test-port pressure actuated sealing apparatus of claim 3 wherein:
the transfer component is comprised of a ring piston,
the sealing valve is comprised of a gate valve,
the actuating mechanism is further comprised of a gate assembly.
10. The test-port pressure actuated sealing apparatus of claim 9 wherein the gate assembly further comprises a spring.
11. The test-port pressure actuated sealing apparatus of claim 3 wherein the body further comprises at least two members further comprising a lower body and an upper body.
12. The at least two members of claim 11 further comprising a hanger neck.
13. The method of claim wherein the sealing valve further comprises a seal body with a radial cross section to engage the well bore production tubing string.
14. The test-port pressure actuated sealing apparatus of claim 3 further comprising a flow body.
15. The flow body of claim 17 being sized to fit and align with the well bore production tubing string.
16. The flow body of claim 18 formed to interface with the sealing valve.
17. The sealing valve of claim 3 further comprising a seal body assembly.
18. The seal body assembly of claim 20 further comprising a workpiece to bias the sealing valve to a closed position.
19. The method of claim 2 wherein the test-port actuated sealing apparatus is biased to a closed position.
20. The method of claim 2 wherein the test-port pressure actuated sealing apparatus seals the well bore production tubing string by extending a seal perpendicular to flow in the well bore production tubing string.
21. The method of claim 2 wherein the applying introduced pressure through the standard test-port is initiated by a hand operated hydraulic pump with an adapter to join with the standard test-port.
22. The method of claim 2 wherein the building of the introduced pressure within the void space is stopped when the introduced pressure exceeds pressure rising through the well bore production tubing string.
23. The method of claim 2 wherein the method further comprises the following steps of unsealing of the well bore production tubing string:
bleeding the introduced pressure back through the standard test-port,
applying neutralizing pressure into the well tubing head above the improved tubing hanger
permitting a coil spring within the improved tubing hanger to actuate the test-port pressure actuated sealing apparatus to open the well bore production tubing string.
Ref US20220290524: Claims:
1. Through BOP lubrication system, which is capable to be run-through a rig blow out preventer located below the rig floor, the through BOP lubrication system comprising:
a. a lubricator having a polished rod, wherein the polished rod at the bottom end thereof comprising a first high torque connection for connection with a dry rod; b. a riser for connecting the lubricator with the well tubing, wherein the riser is capable of running through a blow out preventer stack; c. a dry rod, which is arranged within the riser; and wherein d. the dry rod at the top end thereof comprises a second high torque connection, wherein the dry rod is connected to the polished rod of the lubricator via the first and second high torque connections.
2. The through BOP lubrication system according to claim 1, wherein the riser comprises a plurality of riser tube elements, that are connected to each other via high pressure rating riser joints.
3. The through BOP lubrication system according to claim 2, wherein the top most riser tube element comprises a pressure gauge.
4. The through BOP lubrication system according to claim 2, wherein the lower most riser tube element comprises inlet holes.
5. The through BOP lubrication system according to claim 1, wherein the riser further comprises a riser single bottom sub element, for connecting the riser with a single well tubing hanger plug profile.
6. The through BOP lubrication system according to claim 1, wherein the riser further comprises a riser dual bottom sub element, for connecting the riser with a dual well tubing hanger plug profile.
7. The through BOP lubrication system according to claim 1, wherein the dry rod comprises a plurality of dry rod tube elements, that are connected to each other via high torque rating dry rod joints.
8. The through BOP lubrication system according to claim 7, wherein the lower most dry rod tube element, comprises at the bottom end thereof a socket head, for connection with a running or retrieving tool.
9. The through BOP lubrication system according to claim 1, wherein the lubricator comprises a housing, an upper packing and a lower packing, wherein the upper and lower packings seal the polished rod against the housing.
10. The through BOP lubrication system according to claim 9, wherein the lubricator further comprises a hydraulically actuated middle packing that further seals the polished rod against the housing, wherein the middle packing is arranged in-between the lower and the upper packing of the lubricator.
11. The through BOP lubrication system according to claim 1, further comprising a C-plate.
12. The through BOP lubrication system according to claim 1, further comprising a dry rod lifting cap for lifting the dry rod.
13. The through BOP lubrication system according to claim 1, further comprising a riser lifting cap for lifting the riser.
14. Method of testing a through BOP lubrication system, comprising the following steps in the following sequence:
a. run a riser to above tubing hanger orient a bottom sub and land same on tubing hanger; b. close bottom pipe rams; c. run a dry rod; d. connect a polished rod of a lubricator to the top of the dry rod; e. connect the riser with the lubricator; and close top pipe rams; f. apply pressure through a kill line between the BOP pipe rams and the lubricator lower packing; and g. check pressure at the BOP gauges and at a riser pressure gauge arranged below the lubricator.
15. The method of testing a through BOP lubrication system, according to claim 14, further comprising the following step:
h. after step a, connect a H1 or H2 and running tool to the bottom of dry rod.
Ref US20120024521: Claims:
1. A wellhead lubricator apparatus comprising:
a barrel portion detachably engageable with a yoke assembly mountable upon a wellhead, the barrel portion comprising:
a barrel housing;
a rod movable coaxially within the barrel housing and having a segment of the rod variably extendable from an end of the barrel housing and into the yoke assembly;
a piston secured to the rod and movable within the barrel housing; and
 hydraulic means for controllably driving the piston to-and-fro within the barrel housing, thereby moving the rod axially in relation to the barrel housing and yoke assembly.
2. A lubricator apparatus for use at an oil or gas wellhead, comprising:
a yoke assembly removably mountable to a wellhead, and a barrel portion, detachably engageable with the yoke assembly, comprising:
a barrel housing having a first end and a second end;
a rod movable coaxially within the barrel housing and having a segment of the rod variably extendable from the barrel housing second end;
a piston secured to the rod and movable within the barrel housing, there being defined in the barrel housing a head space between the piston and the barrel housing first end and a barrel space between the piston and the barrel housing second end;
 an upper port defined in the barrel housing for permitting a hydraulic fluid to enter or exit the head space; a lower port defined in the barrel housing for permitting hydraulic fluid to enter or exit the barrel space; and a valve for regulating hydraulic pressure in the head space or the barrel space, thereby controllably driving the piston to-and-fro within the barrel housing and moving the rod axially in the barrel housing.
3. An apparatus according to claim 2 wherein the barrel portion has a screwed engagement with the yoke portion by means of a steel swage.
4. An apparatus according to claim 3, wherein the second end of the barrel housing is secured within a female side of the swage by a pressure gland for containing hydraulic pressure within an interior of the barrel housing.
5. An apparatus according to claim 4 wherein the swage has a screwed engagement with a union atop the yoke assembly, and the tool rod movably extends axially through the gland and the swage, and into the yoke assembly.
6. An apparatus according to claim 2 wherein the valve comprises a valve in fluid communication with the upper port and with the fluid port, and further wherein the lower port and the upper port are in fluid communication with hoses for delivering hydraulic pressure separately to each of the ports.
7. An apparatus according to claim 6 wherein the valve comprises a needle valve for controlling hydraulic fluid flow between the upper fluid port and the lower fluid port, whereby the needle valve closed prevents hydraulic fluid from moving directly between the ports while the needle valve open allows hydraulic pressure equalization to occur between the ports.
Ref US20110214882: Claims:
1. A system (10) for controlling a well being drilled into a subterranean formation (14), said system comprising,
a tubular drill string (20) having a lower end (22) extending into a borehole 2 and an upper end (24), said tubular drill string having a drill bit (26) at its lower end, a drill string turning device (38) arranged and designed to turn said drill bit in said borehole in which a borehole annulus (18) is defined between an outer diameter of said tubular drill string and an inner diameter of said borehole, a blow-out preventer (32) arranged and designed to close said borehole from atmosphere only at a time when said drill bit is stationary, a fluid pump (40) in fluid communication with a surface fluid reservoir (42), a choke line (56) coupled between said borehole annulus and said surface fluid reservoir and arranged and designed to permit fluid communication therebetween when said blow-out preventer closes said borehole from atmosphere, a fluid injection line (48) extending between said fluid pump and said upper end of said drill string, said fluid injection line capable of providing fluid communication therebetween, said fluid injection line, said drill string, said borehole annulus and said choke line defining a fluid pathway when said blow-out preventer closes said borehole from atmosphere, an outlet flow rate measurement device (50) disposed in said choke line, said outlet flow rate measurement device arranged and designed to measure flow rate through said choke line and to generate a signal Fout(t) representative of actual choke line flow rate as a function of time (t), an outlet pressure measurement device (64) disposed in said choke line, said outlet pressure measurement device arranged and designed to measure choke line pressure and to generate a signal Pout(t) representative of actual choke line pressure as a function of time (t), a central control unit (80) arranged and designed, while said borehole is closed from atmosphere by said blow-out preventer,
to receive said signals Fout(t) and Pout(t),
to determine a formation fracture pressure as a function of said signals Fout(t) and Pout(t),
to determine a formation pore pressure as a function of said signals Fout(t) and Pout(t),
to generate a signal Pann(t) representative of pressure at a desired well bore depth as a function of time (t),
to generate a signal FC(t) representative of choke line flow rate required as a function of time (t) to maintain said signal Pann(t) below said formation fracture pressure and above said formation pore pressure, and
to transmit said signal FC(t), and
 a flow control device (70) disposed in said choke line, said flow control device arranged and designed to control fluid flow therethrough in response to said signal FC(t) transmitted and received from said central control unit, thereby controlling choke line flow ate to maintain said signal Pann(t) below said formation fracture pressure and above said formation pore pressure.
2. The system of claim 1 further comprising,
an inlet flow rate measurement device (52) disposed in said fluid injection line, said inlet flow rate measurement device arranged and designed to measure fluid flow rate through said fluid injection line and to generate a signal Fin(t) representative of actual fluid injection line flow rate as a function of time (t).
3. The system of claim 2 wherein,
said central control unit is further arranged and designed to receive said signal Fin(t) and to determine said formation pore pressure as a function of said signals Fout(t) and Pout(t) when said flow control device controls fluid flowrate through said choke line such that said signal Fin(t) first becomes consistently less than said signal Fout(t).
4. The system of claim 2 wherein,
said central control unit is further arranged and designed to receive said signal Fin(t) and to determine said formation fracture pressure as a function of said signals Fout(t) and Pout(t) when said flow control device controls fluid flow rate through said choke line such that said signal Fin(t) first becomes consistently greater than said signal Fout(t).
5. The system of claim 1 further comprising,
an inlet pressure measurement device (62) disposed in said fluid injection line, said inlet pressure measurement device arranged and designed to measure fluid injection line pressure and to generate a signal Pin(t) representative of actual fluid injection line pressure as a function of time (t), and wherein,
said central control unit is further arranged and designed to receive said signal Pin(t).
6. The system of claim 1 wherein,
said central control unit is further arranged and designed to calculate an increase in fluid weight to be pumped through said fluid pathway based upon said formation pore pressure.
7. The system of claim 1 further comprising,
a kill line (54) coupled between said fluid pump and said borehole annulus and capable of providing fluid communication therebetween, and wherein,
said kill line, said borehole annulus, and said choke line define said fluid pathway when said blow-out preventer closes said borehole from atmosphere.
8. The system of claim 7 further comprising,
an inlet flow rate measurement device (60) disposed in said kill line, said inlet flow rate measurement device arranged and designed to measure fluid flow rate through said kill line and to generate a signal Fin2(t) representative of actual kill line flow rate as a function of time (t).
9. The system of c
[Truncated to input limit]