The following paragraphs link several aspects of the massive and TSO generations by using the informa- tion available from the diagnostic log-log plot for fracturing in Appendix Fig. 8. Appendix Table 1 lists the interpretations for various slopes exhibited in the figure by the net pressure during fracturing. The data are from two massive treatments in tight gas forma- tions. The top curve is a treatment in the Wattenberg field, the first microdarcy-permeability field develop- ment (Fast et al., 1977). The behavior shown by the lower treatment curve, which was designed by this author, provided insight for developing the TSO treatment that enables successfully fracturing darcy- scale oil formations. The treatment related to the lower curve was not particularly successful. How- ever, it was one of the first 2 million lbm treatments and hence functioned better as a “sand-disposal” treatment than a gas-stimulation treatment. The sand was disposed of with 900,000 gal of crosslinked fluid containing 90 lbm/1000 gal of polymer, or approxi- mately 80,000 lbm of polymer.
The marginal success of the treatment is readily understood by considering Appendix Eq. 3. For the treatment average of 2.1 ppa, the equation predicts 1900 lbm/1000 gal crosslinked fluid (in reality, a solid) remaining in the proppant pack porosity after the treatment. However, the size and viscosity for this treatment provided an ideal test condition of how a formation responds to fluid pressure and an excellent illustration for the concept of formation
capacity. The capacity (Nolte, 1982) defines the pres- sure limit for efficient fracture extension and is anal- ogous to the pressure-capacity rating for a pressure vessel. The cited reference has an unsurprising theme of the negative effects of excesses of pressure, polymer and viscosity.
Three mechanisms for a formation can define its pressure capacity before “rupture” accelerates fluid loss from the formation’s pay zone. The subsequent fluid loss also leaves proppant behind to further enhance slurry dehydration and proppant bridging. Each mechanism is defined by the in-situ stress state and results in a constant injection pressure condition, or zero log-log slope, when the net pressure reaches the mechanism’s initiation pressure. The mecha- nisims are
Appendix Figure 8. Log-log diagnostic plot for fracturing
(Nolte, 1982).
*
x 2000 1000 500 [5 MPa] Net pressure, p net (psi) log p net 40 60 100 200 400 600 1000 Time (min)log time or volume Idealized Data Field Data I II II II III-a III-a III-b IV Inefficient extension for pnet ≥ formation capacity pfc
I
Proppant begins
Proppant begins Variable injection rate
III-a III-b II
I IV
Appendix Table 1. Slopes of fracturing pressures and their interpretation in Appendix Fig. 8.
Type Approximate log-log slope value Interpretation
I 1⁄
8to 1⁄4 Restricted height and unrestricted expansion
II 0 Height growth through pinch point, fissure opening
or T-shaped fracture
III-a 1 Restricted tip extension (two active wings)
III-b 2 Restricted extension (one active wing)
• opening the natural fissures in the formation, gov- erned by the difference in the horizontal stresses • extending the height through a vertical stress bar-
rier and into a lower stress (and most likely per- meable) zone, governed by the difference in the horizontal stress for the barrier and pay zone • initiating a horizontal fracture component when
the pressure increases to exceed the level of the overburden stress.
An important observation for the pressure capacity is that it depends on the in-situ stress state and there- fore does not change for the formation in other well locations unless there are significant local tectonic effects. As a result, all future treatments for the field can generally be effectively designed on the basis of only one bottomhole pressure recording and its detailed analysis (see Section 9-4).
The upper curve on Appendix Fig. 8, for the Wattenberg treatment, illustrates the fissure-opening mechanism with the Type II zero slope occurring at a net pressure of 1700 psi. This value provides one of the largest formation capacities ever reported. The fis- sure opening is preceded by restricted height growth and unrestricted extension (Type I slope) that provide the most efficient mode of fracture extension. There- fore, conditions in this formation are favorable for propagating a massive fracture; not by coincidence, this was the first field successfully developed in the massive treatment generation (Fast et al., 1997), and it provided incentive to continue the development of massive treatment technology. Returning to Appendix Fig. 8, after the period of constant pressure and enhanced fluid loss, a Type III-a slope for a fracture screenout occurs because slurry dehydration forms frictional proppant bridges that stop additional exten- sion (i.e., a generally undesired screenout for a tight formation requiring fracture length over conductivity). After the penetration is arrested, the major portion of the fluid injected is stored by increasing width (see Appendix Eq. 4) and the net pressure develops the unit slope characteristic of storage. The amount of width increase is proportional to the net pressure increase.
The Wattenberg treatment consisted of 300,000 gal of fluid and 600,000 lbm of sand with an average concentration of 2 ppa, similar to the previous exam- ple. However, the treatment was successful because a polymer-emulsion fluid with low proppant pack damage was used. After the treatment defined the formation capacity, model simulations indicated that
the required penetration could be obtained by not exceeding the formation capacity. A subsequent treat- ment designed using 150,000 gal and 900,000 lbm of sand (an average of 6 ppa) became the prototype for the remaining development of the field (Nolte, 1982).
The lower curve on Appendix Fig. 8 is for the aforementioned sand-disposal treatment in the Cot- ton Valley formation of East Texas. As previously discussed, the treatment provided an opportunity to observe a large range of fracturing behavior with five types of interpretive slopes occurring, including • Type I indicating extension with restricted height
growth
• Type II defining this formation’s lowest pressure capacity at 1000 psi for the penetration of a stress barrier
• Type IV, with decreasing pressure, indicating unre- stricted vertical growth through a lower stress zone after the barrier was penetrated.
The Type IV condition continued until proppant was introduced. Almost immediately after proppant entered the fracture the pressure increased, most likely because the proppant bridged vertically in the width pinch point formed by the penetrated stress barrier and restricted additional height growth. During the preceding 6-hr period of significant verti- cal growth, the horizontal growth was retarded. As a result, the very high polymer concentration formed a thick polymer filter cake at the fracture tip that proba- bly restricted further horizontal extension. Thus, the extremities of the fracture were restricted either by proppant or polymer cake, and continued injection was stored by increasing width indicated by the Type III-a unit slope. After a significant increase in pres- sure, the pressure became constant for a short period at 1200 psi with a Type II slope that probably resulted from opening natural fissures to define a second, higher capacity. Subsequently the slope increased to an approximately 2:1 slope indicated as Type III-b. This latter slope for a storage mechanism indicates that about one-half of the fracture area had become restricted to flow, which could have resulted from one wing of the fracture being blocked to flow near the well because of slurry dehydration from the fissure fluid loss. The wellbore region experiences the largest pressure and is most prone to adverse fluid-loss effects from exceeding a capacity limit.
Subsequent treatments were improved after under- standing the formation’s pressure behavior as in the Wattenberg case and for this area after understanding the implications of Appendix Eq. 3 for concentrating polymer. In addition, the observation that proppant bridging could restrict height growth was developed for treatments to mitigate height growth (Nolte, 1982). An effective and relatively impermeable bridge can be formed within the pinch point to retard height growth by mixing a range of coarse and fine sand for the first sand stage after the pad fluid.
Smith et al. (1984) later sought a means to signifi- cantly increase fracture width for the development of a chalk formation within the Valhall field in the Norwegian sector of the North Sea. The additional width was required because laboratory tests indicated the likelihood of substantial proppant embedment into the soft formation that would lead to the loss of effective propped width. Fracturing was considered for this formation because other completion tech- niques would not sustain production because of chalk flow. The resulting treatment design was based on the behavior on the log-log plot in Appendix Fig. 8 for the sand-disposal treatment: a purpose-designed TSO treatment. For the disposal treatment, they observed that after the initial screenout occurred, 2 million lbm of proppant could be placed, and the net pressure increase indicated that this occurred by doubling the width after the screenout initiated.
Smith et al. designed and successfully placed a TSO treatment in which proppant reached the tip and bridged to increase the width by a factor of 2 during continued slurry injection after the purpose-designed TSO occurred. This design, with successful place- ment of progressively larger propped width increases, became the tool that enabled the development of this formation. The ability to significantly increase the width after screenout results from the large storage capacity of a fracture, as detailed in the discussion following Appendix Eqs. 4 and 5. Additional discus- sion on the fracture completion in Valhall field and the TSO treatment is in the “Reservoir and Water Management by Indirect Fracturing” section.
As a historical note, a similar concept for a TSO was disclosed in a 1970 patent (Graham et al., 1972), with the bridging material consisting of petro- leum coke particles (approximately neutral density to ensure transport to the extremities). The patent’s goal was increased width to enable placing larger size proppant in the fracture.