Evaluation of Selective vs. Point-Source Perforating for Hydraulic Fracturing
- P.J. Underwood (Halliburton Energy Services, Inc.) | L.A. Kerley (Santa Fe Energy Resources)
- Document ID
- Society of Petroleum Engineers
- SPE Drilling & Completion
- Publication Date
- September 1998
- Document Type
- Journal Paper
- 151 - 156
- 1998. Society of Petroleum Engineers
- 5.6.4 Drillstem/Well Testing, 2.2.2 Perforating, 2.5.1 Fracture design and containment, 3.2.3 Hydraulic Fracturing Design, Implementation and Optimisation, 2.4.3 Sand/Solids Control, 2.5.2 Fracturing Materials (Fluids, Proppant), 5.5.8 History Matching, 1.6 Drilling Operations, 5.2.1 Phase Behavior and PVT Measurements, 4.1.2 Separation and Treating, 3 Production and Well Operations, 5.5 Reservoir Simulation, 5.4.2 Gas Injection Methods, 5.4.1 Waterflooding, 4.1.5 Processing Equipment, 1.7 Pressure Management
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"Select-fire" (SF) and "point-source" (PS) perforating completions were used to fracture the Reef Ridge diatomite formation in the Midway-Sunset field, Kern county, California. Fracturing treatment analysis and production history matching were used to evaluate the reservoir and fracturing parameters for both completion types. Single fractures were created with the PS completions, and multiple fractures resulted from many of the SF completions.
Descriptions of the reservoir, production history, and fracturing techniques used leading up to this study are presented. Fracturing treatment analysis and production history matching were used to evaluate the reservoir and fracturing parameters for both completion types.
The work showed that single fractures were created with the PS completions, and multiple fractures resulted from many of the SF completions. A good correlation was developed between productivity and the product of formation permeability, net fracture height, bottomhole pressure, and propped fracture length. Results supported the continued development of 10 wells using the PS concept with a more efficient treatment design, resulting in substantial cost savings.
Diatomite formations have low permeability with high porosity and require hydraulic fracturing to yield commercial production. Development of the diatomite in this area of Midway-Sunset field began in 1985, reaching peak production in 1988 at 1,900 BOPD (Fig. 1). Less than anticipated production response from the 1994 program led to a review of the stimulation process to determine if the stimulation design could be modified to increase productivity or reduce treating cost.
Review of previous treatments using pressure history-matching techniques1 indicated the presence of multiple fractures and near-wellbore tortuosity. This finding was supported by a reinterpretation of the initial treatments conducted in 1985 and 1986. The severity of multiple fractures and tortuosity increases as the wellbore deviates from the preferred fracture plane.2 Minimizing the perforated interval minimizes the effects of multiple fractures.3 Since the authors believed that multiple fractures and tortuosity are primary causes of stimulation difficulties4 that can result in less production, they decided to develop a completion procedure to minimize these effects.
A 17-well drilling package scheduled for 1995 was used to evaluate the use of point-source (PS) perforating and its effect on the stimulation process. Thirteen wells were modeled in this study, consisting of five PS wells and eight wells completed with the conventional select-fire (SF) perforating technique. Limited-entry perforating theory was used for both methods. Perforations were limited to 30 or fewer per stage to accommodate the designed 55 bbl/min limited-entry injection rate.
For this project, a PS-perforated completion is defined as a perforated interval that is small relative to the larger pay section. The point source consisted of a 2- to 5- ft interval perforated with 2 to 6 shots per foot (spf) with 30 or fewer holes. While in theory, a single PS would fracture the whole interval; a total "leap of faith" to a single PS was not taken. The fear was that internal stress boundaries could limit fracture height and result in incomplete zone coverage. Typically, each PS zone was perforated with two PS intervals.
An SF-perforated completion consists of spacing 30 perforations evenly across the total interval to be fractured, avoiding casing collars, and poor-quality zones.
Santa Fe Energy Resources has approximately one-quarter section of productive diatomite on Section 9, Township 32 south, Range 23 east, Mount Diablo Base and Meridian, Kern county, California (Fig. 2). The Upper Miocene, Reef Ridge, diatomaceous reservoir is found trapped below the Top Miocene unconformity. The surface of the unconformity strikes northwest to southeast and dips to the northeast. Correlative units within the diatomite interval have greater dips and strike slightly different than the overlying trapping unconformity. The oil-water surface is near parallel to the Top Miocene unconformity.
The Reef Ridge diatomaceous interval is approximately 600 ft thick where it has not been truncated by the Top Miocene unconformity. The downdip limit appears to be a combination of diagenetic change and/or oil-water contact. The productive interval averages about 175 ft thick and is generally comprised of two distinct diagenetic phases of diatomite: the high 50 to 65% porosity Opal-A and the less porous 35 to 50% porosity Opal-CT. Cross-section A-A (Fig. 3) shows the Opal-A section above the transition marker and the Opal-CT below. Both phases are characterized by very low permeability (less than 0.1 md) and varying percentages of clays (10 to 30%). Oil saturations from the sidewall samples are greater than 20% in the Opal-A section and grade from less than 20% below the diagenetic transition marker to 0% at the oil-water contact. The Reef Ridge diatomaceous oil gravity is approximately 23°API with a 1,000 R (ft3/bbl). Prefracture pressure buildup results and fluid analysis on six wells conducted from June 1985 to May 1986 are given in Table 1.
The Reef Ridge diatomaceous reservoir in Section 9 was originally developed on 5-acre spacing, which was later reduced to 2 1/2-acre spacing. This spacing was further reduced starting in 1990 to a modified five-sixth-acre spacing based on fracture azimuths from N 10° E to N 50° E. For this modified five-sixth-acre spacing, the wells are 110 ft apart along an eastwest line through the existing wells (i.e., nearly perpendicular to the fracture azimuth) and 330 ft apart along a north-south line. Some pressure depletion was anticipated in the five-sixth-acre locations, but the five-sixth-acre wells were expected to perform at 85 to 90% of the levels seen in the 5- and 2 1/2-acre wells. Subsequent analysis in 1993 (using a linear flow model) confirmed that some depletion was indeed encountered in the five-sixth-acre locations, as seen by lower production levels.
Fracture orientation was obtained in 1986 using tiltmeters. The tiltmeters indicated that for the eastern one half of the reservoir, the fractures had an orientation of N 10° E and rotated to N 50° E on the western edge of Section 9. This orientation was confirmed when a waterflood pilot was initiated in 1992. The waterflood pilot was laid out as a four-well injector project based on the tiltmeter data. The first injector was placed on injection and communication to the offset wells indicated only a slight variation in fracture azimuth as compared to tiltmeter data. Hydraulic fracture dips of 5 to 24° from vertical were determined from 29 tiltmeter maps with an average of 9.5°.
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