A Case History Of Massive Hydraulic Refracturing In The Tight Muddy "J" Formation
- D.I. Parrot (Amoco Production Co.) | M.G. Long (Amoco Production Co.)
- Document ID
- Society of Petroleum Engineers
- Symposium on Low Permeability Gas Reservoirs, 20-22 May, Denver, Colorado
- Publication Date
- Document Type
- Conference Paper
- 1979. Society of Petroleum Engineers
- 2.5.2 Fracturing Materials (Fluids, Proppant), 3.2.3 Hydraulic Fracturing Design, Implementation and Optimisation, 2.4.3 Sand/Solids Control, 4.3.4 Scale, 5.2.1 Phase Behavior and PVT Measurements, 4.1.2 Separation and Treating
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This paper evaluates the refracturing of wells in the tight (.04 to .0003 md - 40 X 10(-6) to .3 X 10(-6) um2) Muddy "J" formation in Wattenberg Field using massive hydraulic fracturing (MHF). Twenty-nine wells that originally received 50,000 gallon (189 m3) gelled water fracture treatments on completion have been refractured with 300,000 gallon (1136 m3) polymer emulsion treatments. This study shows that wells initially completed successfully with small volume fracture treatments can be successfully restimulated with MHF. Those which did not have successful initial stimulations may not be economic candidates for refracturing.
Initial attempts in Wattenberg Field to achieve gas production in commercial quantities were made with fracturing treatments of up to 50,000 gallons (189 m3) gelled water and up to 150,000# (68,039 Kg) of proppant. Low initial production rates and rapid declines indicated most production rates and rapid declines indicated most of the stimulations would result in uneconomical wells. Through laboratory and field research, massive hydraulic fracturing treatments evolved with 300,000 gallons (1136 m3) polyemulsion fluid and up to 735,000 lb. (333,390 Kg) of proppant becoming the predominant treatment. Once this massive treatment was deemed economically feasible for new wells, candidates for restimulation were selected. Though some wells selected for refracturing were commercial producers with 50,000 gallon (189 m3) initial treatments, it was felt their productivity could be increased substantially with larger treatments. However, most refracturing candidate wells were selected on the basis of unsatisfactory performance. Recently, constant well production performance. Recently, constant well production rate and pressure type curves have been used to determine percent recovery of gas in place and "effective" fracture length in a refracturing candidate. When compared to offset wells, an assessment of the success of the original stimulation on the candidate well and the potential for refracturing can be made.
Wattenberg Field is located 25 miles (40 Km) north of Denver covering 980 square miles (2538 Km2) in Weld and Adams Counties in the western portion of the D-J Basin (Figure 1). Amoco Production portion of the D-J Basin (Figure 1). Amoco Production Company is the major operator with more than 400 wells. Average gas production per well is 150 MCFD (4247 m3/d).
The Muddy "J" formation of Cretaceous age is the gas producing horizon in Wattenberg. This sand is at depths from 7600-8400 feet (2316-2560 m), averaging 50-100 feet (15-30 m) gross thickness with 10-50 feet (3-15 m) net pay sand thickness. Porosity ranges from 8-12%. Formation permeability varies from .04 to .0003 md (40 X 10(-6) permeability varies from .04 to .0003 md (40 X 10(-6) to .3 X 10(-6) um2). Static bottom hole temperature averages 260 degrees F (400 degrees K) and original bottom hole pressure was 2900 psi (1.99 X 10(4) kPa). The reservoir is stratigraphically controlled by sand pinchout to the southwest and a permeability reduction pinchout to the southwest and a permeability reduction to the northeast. Unstimulated wells produce from a show of gas to 100 MCFD (2832 m3/d).
Evolution of Stimulation
During the initial phase of Wattenberg Field development, wells were treated with 30,000 to 50,000 gallons (114-189 m3) of gelled water down 4 1/2" casing with a maximum of 150,000 lb (68,039 Kg) proppant. These treatments created fracture lengths from 100-500 feet (30-152 m). Several wells were put on production in late 1971 for long term testing. By early 1973, it was determined that only by creating longer fractures would these wells prove to be economical. A 183,000 gallon (693 m3) polymer emulsion treatment using 277,000 lb. (125,645 Kg) sand evolved as a standard procedure from 1973 to late 1974 which created fracture lengths of 1500-2000 feet (457-610 m)
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