Mr. Erik Milito - The House Committee on Natural Resources ...

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54 API STANDARD 65-2 Cooke’s study [24,25] discovered fundamental mechanisms and explanations supporting some theories on loss of hydrostatic pressure and invalidating others. <strong>The</strong>se discoveries were verified by others such as a similar separate downhole sensor study (SPE 19552) by Morgan [40] while running and cementing casing in the North Sea. Morgan also reported how these downhole measurements indicated the failure to set an ECP. An analysis of downhole annular pressure measurements can explain other difficult to find or complex root causes for other cause effects such as high ECD pressures when cementing liners. Brehme et al [41] et al found that downhole pressure sensor measurements are a reliable method to help diagnose and evaluate liner running and liner cementing operations. Cementing simulation computer model results were favorably compared to the actual downhole pressures. Brehme et al [41] proposed this process to help predict and evaluate results in future cementing operations by downhole gauge diagnosis of conditions not included in software models such as annular restrictions by cuttings, hole cleaning performance, and liner hanger equipment functions. For example, this data can help operators find answers for some annular flows linked to lost circulation events such as those caused by complete or partial flow restrictions in liner overlaps or liner hanger bypass or cross-sectional areas plugged by cuttings not removed during hole cleaning operations. A.14 Some Key Results from Cooke's Study [24,25] Some of the key results from Cooke’s study [24,25] are as follows. 1) Downhole sensor measurements proved that the loss of hydrostatic pressure in columns of unset cement may be reduced to values below those found in cement mixwater (fresh, sea or saltwater) density gradients [see A.3, no.4.a)]. See Figure A.2 (Figure 9 in SPE 11206) showing that the cement hydrostatic head from the sensor at 1900 ft. in well G decreased from 13.4 lb/gal to 2.5 lb/gal equivalent density in ca. 420 minutes. This measurement is 6.0 lb/gal equivalent density below the average seawater gradient of 8.5 ppge. Cooke concluded that SGS development caused the cement hydrostatic head to regress to 2.5 ppge based on hole conditions such as formations with little or no permeability across and above the sensor at 1900 ft. This invalidates the idea claimed in SPE 8255 [42] that the loss of hydrostatic head in the cement column never falls below the cement’s mixwater density gradient. It also invalidates the associated practice [38] of adding salt in cement slurries to increase the gradient and reduce the loss of hydrostatic head. 2) Surface pressure applied to the annulus may not reach the desired depth depending on drilling fluid and cement properties such as gel strength development (A.3, no.4.b. and 5.7.8). See Figure A.3 (Figure 4 in SPE 11206) that illustrates the lack of pressure response in 3 sensors at 4430 ft, 5454 ft, and 7412 ft in well B when surface pressure is applied. Also notice the large amount of pressure applied after 2100 minutes was high enough to break the cement SGS and allow hydrostatic pressure to be measured at 2 of the 3 sensors. Figure A.3 (Figure 2 in SPE 11206) also shows no pressure response from all sensors in well A by the applications of surface pressure designed to test the validity of said practice described in SPE 8255 [42] . <strong>The</strong> surface pressure was applied 24 minutes after the cement job ended. This uncertainty in transmitting hydrostatic pressure through unset cement slurry at various times during a cement’s curing phase makes it unreliable to carry out the practice of applying and maintaining an annular surface pressure to compensate for hydrostatic head pressure losses as claimed in SPE 8255[42]. <strong>The</strong>refore, applying surface pressure by pumping into the top of the annulus should be considered only for well control purposes such as controlling a kick in the annulus. However, in some recent cases applying small amounts of surface pressure in the form of controlled pressure pulses has worked in some wells to help prevent annular flows when the entire process, including the cement system, is properly engineered, understood by all involved, and validated by relevant means such as the lab testing described in 5.7.8. 3) Prior to Cooke’s study [24,25] our industry did not have relevant field data to fully understand and confirm the theoretical mechanisms accounting for the rapid losses of designed overbalances after cementing jobs. Cooke’s measurement of this rapid decrease in cement column hydrostatic pressures to underbalanced conditions across potential flow zones helped explain the cause of many LWC incidents. It also helped explain how other annular flows such as cross-flows and underground blowouts were initiated. <strong>The</strong> understanding of how SCP may initiate via different types of annular pathways was also improved. Figure A.4 (Figure 2 in SPE11206) presents annular pressure and temperature measurements in well A that illustrate how the hydrostatic head
ISOLATING POTENTIAL FLOW ZONES DURING WELL CONSTRUCTION 55 4 Sensor Depths - ft Pumping Completed Pressure - thousand psi 3 2 1 4432 4326 4034 2900 1900 EMW = 2.5 lb/gal 130 Temperature - °F 120 110 100 90 80 4034 4432 & 4326 1900 1 2 3 4 Time - Hundreds of minutes Geothermal Reproduced with permission. Copyright, SPE. Cooke Jr., C.E., Kluck, M.P., Medrano, R. 1983. Field Measurements of Annular Pressure and Temperature During Primary Cementing. J. Pet Tech 35 (8): 1429-1438; SPE-11206-PA. Figure A.2—Annular Pressure and Temperature—Well G 2900 5 decreased vs time. Note that the hydrostatic head loss in all sensors started immediately after pumping of the cement slurry ended and the temperature at each sensor indicated that the cement was not set until inflection points in each temperature curve was recorded. <strong>The</strong>se inflection points represent the principal exotherm of the cement that occurs when the cement achieves initial set. In 1983 all the information from Cooke’s study was an industry revelation that helped accelerate the implementation of cement practices and materials that were already developed to help control annular flows. It also helped R&D funding by various companies for even better solutions. 4) Many other interesting facts and data analysis results are presented in SPE 11206 and the follow-up paper SPE 11416. <strong>The</strong> latter one focused on temperature effects, lost circulation during cementing diagnostics, and the hydrostatic pressure decline in columns of “mud” or drilling fluids. Figure A.5 (Figure 7 in SPE 11416) indicates the drilling fluid hydrostatic pressure loss recorded by sensors above the TOC during many days after the cementing jobs in wells B and D.
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oost domestic production by four mi
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Environmental Protection for Onshor
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Environmental Protection for Onshor
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Bibliography [1] Interstate Oil and
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2009 Publications Order Form Effect
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1220 L Street, NW Washington, DC 20
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Contents January 2012 EXECUTIVE SUM
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January 2012 EMPLOYMENT, GOVERNMENT
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January 2012 These
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January 2012 Figure 1: Natural Gas
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1.1 New Federal Drilling Leases Iss
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1.2 Permits to Drill: Down 39% Janu
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January 2012 2 ADVERSE FEDERAL LAND
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January 2012 3 Economic Projections
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January 2012 5 APPENDIX: Data and M
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TABLE 11 - Baseline and Alternative
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5.3 Employment January 2012 Employm
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Natural Gas Production, billion cub
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Number of Wells Started (Spud) on F
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Net (Alternative Minus Baseline) Ja
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Federal royalties of production of
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Imports from Rest of the World 38%
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proactive in communicating to, and
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Product No. GHF301
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Mr. Erik Milito - The House Committee on Natural Resources ...

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