Designing and Qualifying Drill Strings for Extended Reach Drilling
- T.H. Hill (T.H. Hill Assocs.) | G.J. Guild (T.H. Hill Assocs.) | M.A. Summers (T.H. Hill Assocs.)
- Document ID
- Society of Petroleum Engineers
- SPE Drilling & Completion
- Publication Date
- June 1996
- Document Type
- Journal Paper
- 111 - 117
- 1996. Society of Petroleum Engineers
- 1.6 Drilling Operations, 1.7.7 Cuttings Transport, 1.6.1 Drilling Operation Management, 4.1.2 Separation and Treating, 4.1.5 Processing Equipment, 1.4 Drillstring Design, 1.11.2 Drilling Fluid Selection and Formulation (Chemistry, Properties), 1.10.1 Drill string components and drilling tools (tubulars, jars, subs, stabilisers, reamers, etc), 1.11 Drilling Fluids and Materials, 4.2.3 Materials and Corrosion, 1.12.1 Measurement While Drilling, 1.10 Drilling Equipment
- 7 in the last 30 days
- 946 since 2007
- Show more detail
- View rights & permissions
|SPE Member Price:||USD 12.00|
|SPE Non-Member Price:||USD 35.00|
Extended reach (ER) drill string design involves selecting from a variety of available drill string components, those best suited to drill an ER well. In a typical ER well, torsion loads will be higher and tension loads will be lower than for a vertical well of the same measured depth. These differences in applied loads and the need to apply bit weight with normal weight drill pipe pose design and operating questions that are answered in this paper. ER drill strings are often very complex. Also, most available components are in used condition, and thus have been exposed to unknown histories of wear and fatigue. A system for qualifying the drill string is required to ensure that the components we use conform to our design requirements. This paper covers some of the issues the authors have faced in designing and qualifying drill strings for extended reach wells, and how these issues were successfully resolved.
ER Drill String Design Model
Figure 1 shows a general model for drill string design in an extended reach well. We first estimate the loads that the drill string will experience (step 1), then select components that can safely carry these loads (step 2). Since the two steps are interdependent, this is an iterative process, and the arrow is drawn both ways. In addition, the final selection of drill string configuration is also heavily influenced by many issues other than applied loads. These "side issues" shown on Figure 1 are also interdependent, often conflicting one with another, and rarely cut-and-dried. For example, hole cleaning needs and pump pressure limitations may favor 6-5/8 inch drill pipe over 5-inch, but ECD, rig setback space and availability issues may be forcing us toward the smaller pipe. The final design is invariably a compromise between all these issues, and thus will rarely be "optimum", if indeed such a thing exists. Rather, we aim for a "successful" design, one that gets us safely to TD within budget and without either experiencing a drill string failure or wearing out our casing.
Typical Drill String Loads and Load Limits
Imagine that we plan to drill a series of 20,000 ft MD wells with 5-inch drill pipe. We'll drill the first one vertically to TD. The others will be kicked off at 1000 feet and build angle at 2 degrees/100 feet until they reach some desired tangent angle between 0 and 90 degrees, then continue straight until they reach 20,000 ft MD. Figure 2 shows the expected surface hanging load and torsion to rotate the drill string off bottom in these hypothetical wells as tangent angle increases to 90 degrees. Although rotating off bottom is only one of many possible operations, it's readily apparent from Figure 2 that torsion will often be a major concern in ER drilling.
|File Size||435 KB||Number of Pages||7|