Precise Fracture Initiation Using Dynamic Fluid Movement Allows Effective Fracture Development in Deviated Wellbores
- Michael J. Eberhard (Halliburton Energy Services, Inc.) | Jim Surjaatmadja (Halliburton Energy Services, Inc.) | Ellis M. Peterson (Flying J. Oil & Gas, Inc.) | Russell R. Lockman (Halliburton Energy Services, Inc.) | Steven R. Grundmann (Halliburton Energy Services, Inc.)
- Document ID
- Society of Petroleum Engineers
- SPE Annual Technical Conference and Exhibition, 1-4 October, Dallas, Texas
- Publication Date
- Document Type
- Conference Paper
- 2000. Society of Petroleum Engineers
- 3.2.3 Hydraulic Fracturing Design, Implementation and Optimisation, 1.10 Drilling Equipment, 4.6 Natural Gas, 1.6 Drilling Operations, 2.4.3 Sand/Solids Control, 1.8 Formation Damage, 4.1.2 Separation and Treating, 2.2.2 Perforating, 5.4.2 Gas Injection Methods, 1.6.9 Coring, Fishing, 3 Production and Well Operations, 2.5.2 Fracturing Materials (Fluids, Proppant), 1.14 Casing and Cementing, 5.4.3 Gas Cycling
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In deviated wellbores with long perforated intervals, conventional fracture initiation with wellbore pressurization often creates multiple fracture initiations, resulting in severe fracture tortuosity. When this happens, treatments are generally plagued with high injection pressures, low injection rates and, quite often, early screenouts.
One solution to the problem of multiple fractures is to use the fluid's own dynamic movement to divert flow to a specific point. This method accurately positions and directs fracture initiation. With proper planning, a single fracture can be initiated and proppant can be easily placed without tortuosity effects.
This paper discusses the use of the dynamic fluid movement treatment in a well positioned on an incline through the pay section. Premature screenout had occurred when proppant first entered the formation on a previous treatment attempt, and fracture modeling indicated that multiple fractures were the apparent cause of the screenout. When the dynamic fluid movement method was used on a subsequent treatment, a fracture was initiated properly, and a large proppant treatment was placed successfully.
The North Grieve Unit (NGU) 23-23 is located in the North Grieve Field, 40 miles west of Casper, WY, in the southeast portion of the Wind River Basin (Fig. 1, Page 5). The formation, discovered in 1973, produces from channel-deposited Cretaceous Muddy Sandstone at a depth of approximately 10,000 ft. At North Grieve, the Muddy reservoir dips 30° to the northeast with the sand deposited on a north-south axis. Wells are deviated up to 30° to the southwest at Muddy depth, caused in part by the steeply dipping beds and natural bit drift that occurred while drilling. The Muddy produces 45° API "sweet" oil with fluid expansion and gravity drainage as principal drive mechanisms. A secondary gas cap formed early in the reservoir, and continuous gas reinjection has occurred into the gas cap since 1987. At present, gas cycling continues, with mixed natural gas liquid recovery of approximately 140 B/D and oil production of 100 BOPD. Two active gas-injection wells and four producing wells, including the subject well, are located in the North Grieve Field.
Well NGU 23-23
This well, originally completed in April 1987 in the Muddy without stimulation, had an initial production of 193 BOPD, 183 Mcf/D of gas, and no water production. A core taken in the productive Muddy had average porosity of 13.2% and average air permeability of 64 md. In January 1995, after producing approximately 232,000 STBO, the operator attempted to side-track the well downdip to a more oil-productive position below the secondary gas cap. The first sidetrack attempt penetrated margins of the Muddy channel without encountering any net pay. In late 1995, a second sidetrack was drilled slightly updip and encountered 25 ft of net pay with log parameters similar to the original productive wellbore. The wellbore consists of 5½-in. N-80 casing cemented at a measured depth of 10,435 ft with a deviation of 26° at Muddy depth.
The second sidetrack was underbalanced-perforated from 10,301 to 10,326 ft with 4 shots per foot at 90° phasing. Pressure surveys indicated an adequate reservoir pressure of 3,100 psi, but the well failed to produce commercially. In December 1995, the operator attempted a fracture stimulation treatment with 20/40-mesh sand and gelled crude oil. The treatment screened out early, resulting in only an estimated 8,000 lbm of sand being placed in the formation. Subsequent efforts to produce the well failed to recover economical quantities of oil, and the well was shut in during January 1996.
A new operator became responsible for the field. After continued periodic pressure surveys indicated that the reservoir in the vicinity of this well was not being drained, the new operator planned another fracture treatment attempt late in 1999.
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