Consideration for Future Stimulation Options Is Vital in Deciding Horizontal Well Drilling and Completion Schemes for Production Optimization
- Jim B. Surjaatmadja (Halliburton Energy Services Group) | Billy W. McDaniel (Halliburton) | Leonard Case (Halliburton) | Loyd E. East (Halliburton Energy Services Group) | James F. Pyecroft (Halliburton)
- Document ID
- Society of Petroleum Engineers
- SPE Production & Operations
- Publication Date
- May 2008
- Document Type
- Journal Paper
- 158 - 169
- 2008. Society of Petroleum Engineers
- 4.6 Natural Gas, 5.8.2 Shale Gas, 5.1.2 Faults and Fracture Characterisation, 1.2.3 Rock properties, 2.5.2 Fracturing Materials (Fluids, Proppant), 4.1.2 Separation and Treating, 1.6 Drilling Operations, 1.8 Formation Damage, 2.4.3 Sand/Solids Control, 3.2.3 Hydraulic Fracturing Design, Implementation and Optimisation, 5.1.1 Exploration, Development, Structural Geology, 2.2.2 Perforating, 3 Production and Well Operations, 1.6.6 Directional Drilling, 2.5.4 Multistage Fracturing, 2 Well Completion, 5.5 Reservoir Simulation, 1.14 Casing and Cementing
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Many horizontal wells have been completed without plans for stimulation. Often, horizontal wells were not planned for stimulation, because the belief at the time of completion was that horizontal wellbores eliminate the need for hydraulic fracturing stimulation. This presumption has turned out to be false. Often, by the time it is discovered that a horizontal well needs to be stimulated, it cannot be stimulated effectively because of mechanical or reservoir limitations. This regrettable outcome may have been avoided if extensive preplanning had included consideration for future stimulation. Such preplanning may be limited—not only to the already extensive plans for prospective stimulation activities and selection of the most promising stimulation methods—but for all activities required during the life of the well.
History of Horizontal Wells
Before 1990, US horizontal wells totaled less than 300. By 2004, horizontal wells in the US still numbered less than 4,000, with fewer than 14,000 worldwide (Protecting Our Water 2004; Horizontal and Multilateral 1999). It is likely that most of the horizontal wells drilled before 1990 have depleted to an unsatisfactory production level, now making stimulation a necessity (East et al. 2004), and the US drilling pace for horizontal wells in low-permeability reservoirs has increased since 2005.
Horizontal wells were first drilled in the 1930s, primarily to expose more hydrocarbon-producing rock. Often though, cost and/or risk prevented these types of completions (Ranney 1939). To competitively achieve the same purpose, around 1949, service companies began to offer hydraulic fracturing-stimulation services that proved to be very effective in reaching the unexposed hydrocarbon. This success resulted in a temporary decline of horizontal well technologies, but in the early 1970s, more economical solutions in horizontal well drilling became available. Often during that time, the primary objective was to eliminate the need for costly stimulation and completions.
Eventually, operators began to realize that many of their horizontal wells were not producing as expected. Their options were to abandon the wells, be content with the low production, or stimulate. Usually, hydraulic fracturing stimulation was the desired option, but because the wells had not been completed with future stimulation treatments in mind, fracture stimulations often did not produce satisfactory results. Even when the wells were cased and cemented, many stimulation treatments were marred by screenouts and economically infeasible production increases.
How Horizontal Wells Differ
Stimulation options in horizontal wells are heavily influenced by the type of completion selected during the design phase. This consideration is less critical with vertical wells, whereby in most cases, any stimulation method can be implemented without unusual precompletion stimulation planning.
A primary difference with horizontal drilling is hydraulic fracture plane position relative to the wellbore. Fig. 1 shows a vertical well (a) that intersects the formation, creating Fractures 1, 2, and 3. Theoretically, no matter what the hydraulic fracture direction, any resulting fracture (i.e., 1, 2, or 3) connects to the wellbore in a similar fashion. That is, a large portion of the fracture connects the wellbore either axially or longitudinally. Of course, this theory assumes that fractures are always vertical; which, as will be discussed later, may not be the case. After the wellbore is laid down (as in view b), and relative to the wellbore, hydraulic fractures can be positioned in any relative direction imaginable.
To further complicate matters, horizontal wells as defined in the industry, in most cases, are not precisely horizontal. Slants, dips, and "up-and-downs?? are often designed into (or an unintentional result from) the drilling program (a complicated up-and-down horizontal well is shown in Fig. 2). Obviously, most horizontal or deviated wells are not as complicated as the one shown, and often their shape is controlled (and limited) by the capability of the drilling company performing the operation. Another controlling factor is rock characteristics (e.g., the presence of brittle hard rock may incapacitate steering mechanisms in many drilling systems).
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