Tiltmeter Hydraulic Fracture Mapping in the North Robertson Field, West Texas

Mayerhofer, Michael; Demetrius, S.L.; Griffin, Lawrence Gene; Bezant, R.B.; Nevans, J.; Doublet, Louis

doi:10.2118/59715-ms

Cited by 18 publications

(2 citation statements)

References 11 publications

Supporting

Mentioning

Contrasting

Order By: Relevance

“…This technology has been published many times, and therefore is not discussed in depth (McDaniel and Willett 2002;Rees et al 2001;Surjaatmadja et al 2002). Unlike other techniques that use conventional packers or bridge plugs (Meyerhofer et al 2000;Warpinski et al 2001), this technology uses dynamic sealing to "seal" flow into the present fracture instead of reopening previous frac locations. Therefore, this method can treat openhole, preperforated liners very effectively; it has even been used effectively in multilateral wellbores.…”

Section: Hydrajet Fracturing: Designed For Transverse Fracture Placementmentioning

confidence: 99%

Consideration for Future Stimulation Options Is Vital in Deciding Horizontal Well Drilling and Completion Schemes for Production Optimization

Surjaatmadja

McDaniel

Case

et al. 2008

SPE Production &Amp; Operations

View full text Add to dashboard Cite

Summary 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).

show abstract

Section: Hydrajet Fracturing: Designed For Transverse Fracture Placementmentioning

confidence: 99%

Consideration for Future Stimulation Options Is Vital in Deciding Horizontal Well Drilling and Completion Schemes for Production Optimization

Surjaatmadja

McDaniel

Case

et al. 2008

SPE Production &Amp; Operations

View full text Add to dashboard Cite

show abstract

“…Surface Tiltmeter Mapping has been utilized for many years to determine induced hydraulic fracture (or fracture network) azimuth, induced fracture dip, and the relative volumetric component of the fractures that are either generally vertical or horizontal [1][2][3][4][5][6][7][8] . More recently, the process has been applied to a variety of long-term reservoir monitoring projects in which water or steam injection is tracked in an effort to determine the relative locations of reservoir dilation or compaction [9][10][11][12] .…”

Section: Introductionmentioning

confidence: 99%

A New Method for Vertical Leak Detection in Low to Moderate Permeability Flooded Reservoirs

Walser¹,

Stanley²,

Astakhov³

2008

SPE Symposium on Improved Oil Recovery

View full text Add to dashboard Cite

Rising commodity prices have resulted in an increase in secondary recovery projects that are associated with lower permeability reservoirs. These processes often inject fluids above the parting pressure for the duration of the life of the flood, and pressurization takes place as fluids leak off from the exposed surface area of the induced fracture into the surrounding moderate or low-permeability reservoir matrix. The primary difference between these situations and conventional flooding is that matrix fluid migration is initiating off an induced fracturing plane, as opposed to point-source initiation.During the early history of a flood, mass-balance issues are often ignored, as average reservoir pressures are typically low, and injection rates can dramatically exceed production. As pressures rise, some localized portions of the reservoir not only can exceed virgin static pressures, but volumes near existing induced fractures can approach or equal the pressure in those fractures. When this occurs, vertical fracturing can be initiated, either above or below the reservoir, depending upon the location of the closest lower stress interval.A new method to detect the location of vertical "leakage" has been developed. This method utilizes existing Surface Tiltmeter (STM) technologies and a new surface deformation calculation regime to zero in on volumetric changes that occur above or below the limits of the given reservoir. This method uses measured surface deformation from observed tilt to extrapolate the volumetric change at different specified depths. With a number of constraints, and using a linear geophysical model based on poroelastic equations, an inversion routine is used to find the reservoir compaction or expansion at different depths. When volumetric change best fits the measured deformation data (or tilt) at the surface, the depth and aerial location is then correlated to the area near a specific well or wells.

show abstract

Integrating microdeformation and microseismicity to better resolve hydraulic fracture height

Waltman¹,

Moradi²,

Angus³

2021

First International Meeting for Applied Geoscience &Amp; Energy Expanded Abstracts

View full text Add to dashboard Cite

Tiltmeter Hydraulic Fracture Mapping in the North Robertson Field, West Texas

Cited by 18 publications

References 11 publications

Consideration for Future Stimulation Options Is Vital in Deciding Horizontal Well Drilling and Completion Schemes for Production Optimization

Consideration for Future Stimulation Options Is Vital in Deciding Horizontal Well Drilling and Completion Schemes for Production Optimization

A New Method for Vertical Leak Detection in Low to Moderate Permeability Flooded Reservoirs

Integrating microdeformation and microseismicity to better resolve hydraulic fracture height

Contact Info

Product

Resources

About