Drillstring Considerations for Gulf of Mexico's Deepest Well
- Terry E. Prater (EEX Corp.) | S. DeWayne Everage (T.H. Hill Assocs. Inc.) | John F. Greenip (Hydril Co.) | Burt A. Adams (Oil & Gas Rental Services Inc.)
- Document ID
- Society of Petroleum Engineers
- SPE Drilling & Completion
- Publication Date
- June 2002
- Document Type
- Journal Paper
- 122 - 131
- 2002. Society of Petroleum Engineers
- 1.6.1 Drilling Operation Management, 1.4 Drillstring Design, 1.6 Drilling Operations, 1.10 Drilling Equipment, 1.3.2 Subsea Wellheads, 1.4.3 Torque and drag analysis, 1.14 Casing and Cementing, 1.1 Well Planning, 4.1.5 Processing Equipment, 1.11.2 Drilling Fluid Selection and Formulation (Chemistry, Properties), 1.7.5 Well Control, 4.1.2 Separation and Treating, 1.5 Drill Bits, 1.7 Pressure Management, 1.10.1 Drill string components and drilling tools (tubulars, jars, subs, stabilisers, reamers, etc), 1.11 Drilling Fluids and Materials
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This paper chronicles the design analysis performed to drill the Gulf of Mexico's deepest well. With small-diameter casing cemented in the hole, slimhole drilling plans for the record depth well were generated. The short fuse project required an atypical slimhole drillstring design to select a string with ample tension/ torsion capacity, sufficient flow area for hole cleaning, and immediate availability. The final design was used in an "edge of the envelope" environment with remarkable success. This paper discusses the factors involved in drillstring selection and acceptance, actual field data, post-well results, and future applications.
EEX Corp. and partners set out to drill the Llano Garden Banks 386 prospect on 9 June 1997 with the semisubmersible rig Ocean Voyager. The original well plan called for a 24,750 ft measured depth (MD) [23,700 ft true vertical depth (TVD)] penetration to test the upper Pliocene and deeper Miocene objectives. Drilling progressed relatively as planned with an 8 1/2-in. hole to 20,118 ft MD with a water-based drilling-mud (WBM) system. The drillpipe became differentially stuck and could not be fished. Sidetrack operations resumed to 25,342 ft MD (24,511 ft TVD) with a synthetic oil-based drilling-mud (SBM) system, 5-in. drillpipe, and PDC drill bits.
Drilling-equipment limitations were becoming critical, with 130,000 lbf drag and 22,000 ft-lbf cyclical torque, but well-control procedures put a stop to further progress. The well was successfully killed, but no kick tolerance was left. Therefore, a 7-in., 35.00-lbm/ft liner was set to 25,145 ft MD and cemented in place. An inspection log also indicated the 9 5/8-in., 53.50-lbm/ft casing was worn beyond safe limits. As such, the 7-in., 35.00-lbm/ft liner was tied back with 7 3/4-in., 46.10-lbm/ft casing to the subsea wellhead.
At this point, drilling had progressed beyond the originally planned depth, but the Miocene objective was still significantly deeper. Because of unknown fracture gradients and drilling-mud weight requirements below the 7-in. shoe, a decision was made to release the Ocean Voyager, equipped with a 10,000-psi blowout preventer (BOP) system, and find a rig with a 15,000-psi capability. The semisubmersible rig Omega became the rig of opportunity in March 1998 for drilling the deepest well in the Gulf of Mexico.
A revised plan called for drilling to 28,000 ft MD with slimhole drillpipe below the subsea wellhead at 2,731 ft rotary kelly bushing (RKB). Actual drilling progressed with a string of slimhole drillpipe to 27,864 ft MD (26,979 ft TVD), where a 1.2-lbm/gal kick was encountered. After the well was killed, the drillstring became stuck while tripping out of the hole (TOH). The drillstring was severed, and sidetrack drilling progressed to 26,750 ft MD (25,772 ft TVD), where a 5-in., 21.40-lbm/ft production liner was successfully set after evaluating the well with drillstring-conveyed logging tools. The wellbore schematic is detailed in Fig. 1.
Selecting a drillstring that could withstand the load requirements, yet allow sufficient flow area for fluid circulation, was perhaps the most important ingredient for a successful operation. It was quickly evident that this slimhole application would stretch conventional design practices. The following discussion details the drillpipe selection process and the actual results. The process described in this paper was not sequential, as presented here, but more of a parallel process whereby hydraulics, fishing, running and handling, torque and drag, and drillpipe/bottomhole assembly (BHA) specifications were continuously evaluated and reevaluated until the combination that met the overall performance requirements was achieved.
Torque and Drag Analysis
General Description of Original Proposed Drillstring Design.
A proposed drillstring design1-3 (outlined in Table 1) attempted to use readily available drillpipe that maintained conventional fishability inside the 7-in., 35.00-lbm/ft liner (5.879-in. drift) and planned 5 7/8-in. drilled hole.
The proposed design was modeled with DS-1 Drill String Spreadsheet4 1.0 software* to evaluate the estimated torque and drag loads. The actual survey through the total depth of the 7-in., 35.00-lbm/ft liner and the planned operating conditions were input to simulate potential operating loads. The planned drilling-mud weight for the section was between 14.6 and 15.5 lbm/gal. However, the designs were run at 13.5 lbm/gal to prevent drillstring failure in the event of lost circulation.
To prevent downhole makeup, the connection's makeup torque was used as the drillstring's torsional capacity. The weaker drillpipe tube body or connection tensile capacity at makeup was used as the drillstring's allowable tensile capacity (even though downhole makeup of the Wedge Thread** up to maximum torque does not present a problem).
Analysis of Original Proposed Drillstring Design.
The original proposed drillstring design constraints and the resulting critical loads are presented in Tables 2 and 3. Conservative design constraints were used, including cased-hole (CH) and openhole (OH) coefficient of friction (COF), minimum anticipated drilling-mud weight, maximum weight-on-bit (WOB) requirement, drill-bit torque, and BHA torque and drag. The torque and tension load factors, as presented in Table 3, are percentages of the actual capacity without safety factors applied. The results of this analysis are graphically depicted in Figs. 2 through 4 and suggest that approximately 83,000 lbf greater than the drillstring's buoyed weight [TOH/rotating off bottom (ROB) value] would be required to pull it out of the hole at 28,000 ft MD. Likewise, at least 51,000 lbf greater than the drillstring's buoyed weight [backreaming (BR)/ROB value] would be required for BR. Modeling also suggested that with a planned maximum WOB of 10,000 lbf, only the first three collars would be subject to buckling. Mechanical compression was predicted to up to 340 ft above the drill bit while rotary drilling and up to 690 ft above the drill bit while slide drilling. Though the jars would be run in compression, it was not anticipated that normal-weight drillpipe would be subjected to buckling or mechanical compression.
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