Marlin Failure Analysis and Redesign: Part 2 - Redesign
- R.C. Ellis (Mullen Energy Corp.) | D.G. Fritchie Jr. (BP America) | D.H. Gibson (BP America) | S.W. Gosch (BP America) | P.D. Pattillo (BP America)
- Document ID
- Society of Petroleum Engineers
- SPE Drilling & Completion
- Publication Date
- June 2004
- Document Type
- Journal Paper
- 112 - 119
- 2004. Society of Petroleum Engineers
- 5.6.11 Reservoir monitoring with permanent sensors, 4.3 Flow Assurance, 5.2.1 Phase Behavior and PVT Measurements, 4.3.1 Hydrates, 2.4.3 Sand/Solids Control, 4.3.4 Scale, 1.14.1 Casing Design, 1.1.2 Authority for expenditures (AFE), 5.3.2 Multiphase Flow, 5.1.5 Geologic Modeling, 4.1.5 Processing Equipment, 2 Well Completion, 2.2.2 Perforating, 2.7.1 Completion Fluids, 1.6 Drilling Operations, 4.5 Offshore Facilities and Subsea Systems, 4.6 Natural Gas, 1.14 Casing and Cementing, 1.10.1 Drill string components and drilling tools (tubulars, jars, subs, stabilisers, reamers, etc)
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This second of three related papers addresses applying the failure analysis from the first paper to the remaining Marlin wells. The fact that all five initial Marlin penetrations were predrilled up to the completion stage limited mitigation options. Within the limitations posed by predrilling, well design concepts were developed and screened using agreed-upon risk-acceptance criteria for health, safety, and environment (HSE); do-ability; and operability. On the basis of the risk profile and cost associated with each option, a vacuum-insulated tubing (VIT)/fiber-optic completion concept was selected. This paper focuses on the VIT redesign process.
Following the review of the initial investigation of the tubing/casing failure on the Marlin A-2 well,1 this paper addresses application of the failure analysis to the remaining Marlin wells. The fact that all five initial Marlin penetrations were predrilled up to the completion stage had the following consequences:
The remaining wells can be expected to be exposed to the same loads as the failed A-2 well.
The remaining wells have the same vulnerability as the failed well because only two material differences in well design exist between Well A-2 and the subsequent A-3 through A-6 wells.
The 10 3/4-in., 60.7-lbm/ft tieback casing in Well A-2 was grade P-110; on subsequent wells, it was grade N-80.
Well A-2's intermediate-casing (tapered 13 3/8-×10 3/4-in.) cement top was not designed to go into the preceding 16-in. liner, whereas on subsequent wells, the intermediate-casing (tapered 13 5/8-×10 3/4-in.) cement top was designed to go inside the preceding 16-in. liner, with collapsible foam strapped to the outside of the uppermost 17 joints of the 10 3/4-in. section. The shallower cement top was intended to ensure isolation of a potent, hydrocarbon-bearing zone. Although calculated cement tops were not verified by bond logs, full returns were experienced on three of the remaining four wells.
Apart from the redrill option, one does not have complete freedom to devise solutions for the remaining completions.
Within the limitations posed by predrilling, well design concepts were developed and screened with agreed risk-acceptance criteria for HSE, do-ability, and operability. Based on the risk profile and cost associated with each option, a VIT/fiber-optic completion concept was selected.
After the VIT well concept was selected, an extensive assurance plan was initiated that involved the physical testing and analysis of every component in the new well design. This paper summarizes the redesign process, including insights on:
The analysis of annular-fluid expansion (AFE), focusing on the sensitivity of the calculation to fluid and formation properties.
The importance of thermally modeling various types of completion fluids.
The performance of tieback casing connections in less-conventional combined-load regions, such as compression and external pressure.
Full-scale qualification testing of VIT to obtain overall heat-transfer coefficients for both the tube body and the coupling.
The final paper in this series2 discusses the implementation and assurance of the solutions resulting from this discussion.
The overriding conclusion from investigating the tubing deformation in Marlin Well A-21 is that whatever the underlying cause of the production tieback collapse onto the tubing - hydrates; AFE; or even less likely causes, such as wellhead seal-assembly initiation pressure and the geometry of the submudline packoff tubing hanger (POTH) - all potential mechanisms are related to temperature increase. Because the Marlin wells were batch drilled, a number of currently used mitigation techniques, such as rupture plugs on surface strings, foam cement spacers, and switching to a favorable annulus fluid, are no longer available. One is left with the alternative of lowering the load instead of increasing resistance to it. In the case of the Marlin development, this suggests reducing the temperature to which the outer, more vulnerable annuli are exposed.
Temperature reduction assumes a number of forms, including low-conductivity annular fluids, low convection of annular fluids, and insulating the tubing. Some form of each alternative is present in the final Marlin redesign. The following sections discuss the numerical and experimental paths that led to the new well configuration. Before this discussion, however, insights into the effect of annular-fluid properties on operating annulus pressure are included because annular-fluid calculations form the backbone of integrity evaluation for the shallow, outer well annuli.
This paper is largely devoted to amassing data with which to accomplish a redesign of the remaining Marlin wells. Assembling this information into a basis of well completion design will be addressed in the final paper in the series.2
Throughout this paper, the submudline tubing hanger-packer is called a POTH. The well annuli are designated in alphabetical order, proceeding outward from the production tubing/tieback (5 1/2-×10 3/4-in.) annulus, designated "A." Thus, the "B" annulus is outside the production tieback (e.g., tapered 10 3/4-×8 5/8× tapered 13 5/8-×10 3/4-in.), and the "C" annulus is outside the intermediate casing (e.g., tapered 13 5/8-×10 3/4×16-in. liner hung inside 20-in. casing).
In well design, AFE refers to the pressure change for a fluid in a closed annulus. The phenomenon is particularly relevant to offshore wells in which annuli may be trapped by terminating a casing string(s) at the mudline. The AFE phenomenon, however, can occur in any annulus that is not vented.
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