Stimulation Design for Short, Precise Hydraulic Fractures
- Michael B. Smith (Amoco Production Co.)
- Document ID
- Society of Petroleum Engineers
- Society of Petroleum Engineers Journal
- Publication Date
- June 1985
- Document Type
- Journal Paper
- 371 - 379
- 1985. Society of Petroleum Engineers
- 3 Production and Well Operations, 3.2.3 Hydraulic Fracturing Design, Implementation and Optimisation, 1.2.3 Rock properties, 2.4.3 Sand/Solids Control, 4.1.5 Processing Equipment, 5.6.4 Drillstem/Well Testing, 2.5.1 Fracture design and containment, 2.5.2 Fracturing Materials (Fluids, Proppant), 1.10.1 Drill string components and drilling tools (tubulars, jars, subs, stabilisers, reamers, etc), 2.2.2 Perforating, 4.1.2 Separation and Treating
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This report discusses the philosophy, design, and implementation of small, precise, hydraulic fracture stimulations as applied in a micellar pilot in Salt Creek field, located in central Wyoming.
Wellbore damage and relatively low permeability were resulting in low injection/withdrawal rates in the 1-acre [4046-M ] pilot in this field. Unchanged, these low rates would extend the pilot life by an unacceptable amount and also result in oil production rates too small for meaningful analysis. Accordingly, the decision was made to fracturestimulate the pilot wells on the basis of reservoir stimulation, which showed that the creation of very short (90 ft [29.5 m] tip-to-tip) fractures would not "harm" evaluation of the pilot's performance.
Normal stimulation practices in this area would not give the control desired for this pilot situation to create a 90-ft-[29.5-m-] long fractures in a formation with a thickness of 100 ft [32.8 m]. The procedure that was developed consisted of measuring bottomhole treating pressure (BHTP) while pumping the pad, using these data to calculate the required sand-laden fluid volume, and then switching directly from pad to heavy sand concentration.
A postappraisal of the treatments showed that BHTP measurement was necessary since the pressure varied from theoretical behavior for each well. After initial pressure increases that were predictable, a critical pressure was reached for each case and the value of this pressure (which governed slurry requirements) varied by 25 % from well to well. The effects of the treatments also were evaluated with postfracture pressure falloff tests (PFOT). The stimulations performed generally were successful (fracture design/PFOT lengths of 156/146, 90/100, 134/150, and 55/20), confirming that it is possible to create short, controlled hydraulic fractures by using the procedure outlined in this paper.
The Salt Creek field is located in the Casper Arch section of central Wyoming and originally was discovered around 1900. Several productive formations are present in the field, but the major producer is the Second Wall Creek formation, which was the target for the micellar pilot. The Second Wall Creek is found at a depth of 2,200 ft [722 m], and current reservoir pressure in the pilot area is 580 psi [4 MPa].
The basic problem being experienced in the pilot was low injection/withdrawal rates caused by relatively low permeability, wellbore damage, and the requirement that wells be operated below formation parting pressure. These low rates were extending the pilot life by an unacceptable amount and would eventually result in oil production rates too low for meaningful interpretation. It was decided that hydraulic fracturing stimulation was the best solution, provided that short, controlled fractures could be created.
Such a decision raises several questions. Theoretically, when a vertical hydraulic fracture is initiated, it will grow as a "penny-shaped" fracture until it encounters some barrier to vertical growth. Since the Second Wall Creek formation is on the order of 100 ft [32.8 m] thick, it would be seemingly difficult to limit fracture length to 90 ft [29.5 m]. Also, borehole televiewer and downhole television logs on offset openhole wells had shown the wells surveyed in the area to be "fractured," although these fractures were not Propped and, thus, not particularly conductive. Given this, the goal was respecified to create a propped fracture of the required length, without regard to the hydraulic length, and then to operate the wells below fracture closure pressure. It also was desired to create a propped fracture that calculated the required length from a standard PFOT analysis.
In similar situations, the industry in the past has used a low-rate, low-viscosity, low-proppant-concentration approach to "dribble-in" a short fracture. However, it was felt this approach did not allow the control needed for this pilot application. Major disadvantages in the prior procedure included the following: (1) inadequate knowledge and poor predictive capabilities concerning proppant settling made it difficult to design fracture length accurately; (2) low-viscosity fluid probably would result in a "triangular"-shaped proppant distribution; and (3) low sand concentration would result in nonuniform and inadequate fracture conductivity. Because of these disadvantages and the need to create precise-length fractures in the pilot area, a somewhat different approach was needed for these stimulations.
The development of this fracturing procedure is presented in detail in the following discussions on "fracturing parameters." The basic idea was to pump a relatively large pad, thus ensuring adequate width, and then to switch directly to a heavy-concentration slurry. Since the fracturing fluid was a crosslinked polymer gel, the proppant would be perfectly suspended for the short pump times involved, thus ensuring vertically uniform conductivity . If fracture height could be determined, then the only major unknown determining propped length would be fracture width. Width is proportional to the net fracturing pressure (BHTP-fracture closure pressure), which is a function of the fluid properties.
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