Marcellus Shale Hydraulic Fracturing And Optimal Well Spacing To Maximize Recovery And Control Costs
- Krisanne L. Edwards (EQT Production) | Sean Weissert (EQT Production) | Joshua Brandon Jackson (EQT Production) | Donna Marcotte (Donna Marcotte Consulting)
- Document ID
- Society of Petroleum Engineers
- SPE Hydraulic Fracturing Technology Conference, 24-26 January, The Woodlands, Texas, USA
- Publication Date
- Document Type
- Conference Paper
- 2011. Society of Petroleum Engineers
- 5.2 Reservoir Fluid Dynamics, 5.6.1 Open hole/cased hole log analysis, 1.6 Drilling Operations, 3 Production and Well Operations, 2.4.3 Sand/Solids Control, 5.8.2 Shale Gas, 5.6.5 Tracers, 3.3.1 Production Logging, 1.10.1 Drill string components and drilling tools (tubulars, jars, subs, stabilisers, reamers, etc), 4.6 Natural Gas, 3.2.3 Hydraulic Fracturing Design, Implementation and Optimisation, 4.1.5 Processing Equipment, 2.2.2 Perforating, 4.2 Pipelines, Flowlines and Risers, 2.5.1 Fracture design and containment, 5.1.2 Faults and Fracture Characterisation, 5.5.8 History Matching, 2 Well Completion
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EQT wants to maximize recovery and control development costs in its Marcellus shale development program, which consists of multi-stage fractured horizontal wells. To achieve this objective the asset team considered tighter well spacing. But at what distance do fracture-stimulated wells directly interact? Microseismic data implies that the radius of influence is greater than 1,000 ft. However, after 6 months of production, a study using a nodal analysis software model suggests an effective frac half-length less than half of this, a finding that has been supported in other EQT wells across Pennsylvania and West Virginia.
To test this concept for horizontal wells with multi-stage slickwater, sand-propped frac completions in the Marcellus shale—where well spacing is typically 1000-1200 ft—well spacing was reduced to just 500 ft, in three different areas of the Marcellus. The goal was to better understand: How do the hydraulic fractures interact? Are the closer spaced wells more likely to share reserves? Does the frac design need to be adjusted for tighter spaced wells?
To answer these questions, 500-ft and 1000-ft offset wells were monitored during completion with microseismic, radioactive tracers, chemical tracers, and pressure gauges. Production logging was initially scheduled to begin 4-6 months after production, however, had to be postponed.
With more than 6 months of production data in the first of the three development areas, the 500-ft-spaced wells and 1000-ft-spaced wells are performing similarly, despite frac communication during the completion of the 500-ft wells. Estimates of effective frac half-length from the nodal analysis model support this conclusion.
A unique, comprehensive data set is collected across the Marcellus shale to document how hydraulic fracturing influences well performance, and the study attempts to reconcile conflicting frac half-length interpretations to identify optimal well spacing. The results to date support tighter spacing, which maximizes recovery and facilitates multiple wells to be drilled from the same pad, thereby minimizing the footprint for "greener?? operations.
When four horizontal wells drilled from the same pad came online in early 2010, EQT management and the asset team were very pleased with the strong production results. They were particularly pleased given an unusual fact about this particular well pad site: two of the horizontals were only 500 ft apart—which is half the 1000-ft spacing that is typical in Marcellus shale development. The team decided these good production results warranted further study.
This section outlines the events that led to the current study and lists the questions the team is working to answer, starting with the value of this study and the implications on completion design.
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