Impact of Delays and Shut-Ins on Well Productivity
- Sandra Noe (CESI Chemical) | James W Crafton (Performance Sciences)
- Document ID
- Society of Petroleum Engineers
- SPE Eastern Regional Meeting, 20-22 August, Pittsburgh, Pennsylvania, USA
- Publication Date
- Document Type
- Conference Paper
- 2013, Society of Petroleum Engineers
- 5.8.2 Shale Gas, 3.2.3 Hydraulic Fracturing Design, Implementation and Optimisation, 5.6.5 Tracers, 2 Well Completion, 3 Production and Well Operations, 2.5.2 Fracturing Materials (Fluids, Proppant), 2.4.3 Sand/Solids Control, 4.1.5 Processing Equipment, 4.2 Pipelines, Flowlines and Risers
- Shut Ins, Flowback, IFT Mangement Chemistry, delay to first production, proppant conductivity
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A population of over 270 wells, including over 80 Marcellus wells, was investigated to assess the impact of various early production management strategies, with attention given to the time delay between stimulation and first production, often referred to as the "resting?? or "soak?? period and the effect of subsequent shut-ins. Subsets of this population were used to perform the various evaluations. Four significant control factors became apparent. The use of non-volatile interfacial tension management chemistry and the rate of change of the surface flowing pressure significantly impacted the long-term performance of the wells. The use of the IFT chemistry significantly mitigated, but did not prevent, damage arising from delay to first production or shut-ins. Based on the performance metric used, delay to first production is not beneficial. However, based on other data, the probability of improvement with IFT management was less than one in four and without IFT management was about one in eight. Once on production, the rate with which the flowing pressure was decreased had an important impact on the reservoir / wellbore connectivity. If the rate of surface flowing pressure decrease was greater than about 250 psi per day, the loss of connectivity was obvious. The last control factor was the benefit derived from using high conductivity proppants, in conjunction with the IFT management achieved with persistent Interfacial Tension Modifier fluids.
The practice of delaying first production after fracture stimulation of the multi-stage horizontal well completions is widely perceived as a beneficial operating strategy. The same practice was historically used in vertical wells (11). The subsequent events of intentional or unexpected shut-ins are a part of everyday well operations. A modest body of current literature is being developed regarding the management of first production (1 - 7). However, there is very limited literature on the impact of either delay to first production or the impact of shut-ins (12, 13). There may be other literature, but it was not obvious from an inspection of the SPE One Petro library. However, from the examination of a relatively large group of wells, it has become apparent that the well performance metric of connectivity between the reservoir and the wellbore, as measured by the "apparent fracture length??, suggests that the delay or soak time post-stimulation and the frequent shut-ins are, in fact, detrimental, rather than the perceived beneficial strategy. High rates of wellhead pressure change during the first production period are obviously detrimental. And the use of high conductivity proppants in conjunction with interfacial tension management is clearly beneficial.
The analysis of this body of data relied on the availability of hourly rates and pressures when available and daily data in all cases. The well's performance and performance metrics were determined using methods previously published (9 - 11). The primary metric used for this assessment will be referred to as the "apparent fracture length??, realizing that the number is not indicative of any measurable entity in the reservoir or adjacent to the wellbore. It is a surrogate for describing the degree of connectivity between the reservoir and the wellbore, nothing more. Three major discrepancies arise from its use: 1) the metric's "length?? is dependent on the actual and unknowable fracture height contribution as the square root of that contributing height, 2) the computation of that "length?? is predicated on the assumption that the fracture is efficiently voided of liquids, which is not the case in any of the wells in this study and 3) the overprint and contribution of the natural fracture system. Nevertheless, it is felt that the metric still provides a meaningful relative indicator of that connectivity. If for those reasons alone, there should be no expectation that the calculated values resemble any expected "fracture length?? value.
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