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Shale reservoirs with multistage hydraulic fractures are commonly characterized by analyzing long-term gas production data, but flowback data is usually not included in the analysis. However, this work shows there can be benefits to including flowback data in well analysis. The flowback period is dominated by water flow. Field data indicate that only 15-30% of the frac water is recovered after the flowback. Past publications have suggested that the lost water is trapped in the natural fracture or imbibed into the rock matrix near the fracture face. In this paper, lost water scenarios are tested and examples are presented for including flowback and production data in the analysis of shale gas wells. A gas-water model was constructed for simulating the flowback and long-term production periods. Various physical assumptions were investigated for the saturations and properties in the fracture/matrix system that exists after hydraulic fracturing. The results of these simulations were compared with data from actual wells. The result of these comparisons led to certain conclusions and procedures that describe possible well/reservoir conditions after hydraulic fracturing and during production. In this work, the challenge of simulating a natural fracture with trapped water without imbibition is solved using a new hybrid relative permeability jail. This concept was tested for the period of flowback, shut-in and production. Natural fracture spacing could be a possible explanation of the lost water. In addition, this paper shows the benefits of combining flowback and long-term water production data in the analysis of shale gas wells. In some cases the time shift on diagnostic plots changes the apparent flow regime identification of the early gas production data. This leads to different models of the fracture/matrix system. The presented work encourages the engineer to collect flowback data in order to include it in the long-term production analysis.

Primarily, gas-production data are the main tool used to analyze shale-gas reservoirs. Water production is not usually included in the analysis. In this paper, post-fracturing water flowback and long-term water production are added to the analysis. The water data are usually available but are analyzed separately and not combined with long-term gas-production data. In this paper, procedures and examples are presented, including water-flowback and water-production data, in the analysis of shale-gas wells using rate transient analysis.A number of simulation cases were run. Various physical assumptions were used for the saturations and properties that exist in the fracture/matrix system after hydraulic fracturing. Water flowback and long-term production periods were then simulated. The results of these simulations were compared with data from actual wells by use of diagnostic and specialized plots. These comparisons led to certain conclusions which describe well/reservoir conditions after hydraulic fracturing and during production.This paper shows the benefits of a new method for combining water-flowback and long-term water-production data in shale-gas analysis. Water-production analysis can provide effective-fracture volume which was confirmed by the cumulative produced water. This can help when evaluating fracture-stimulation jobs. It also shows some pitfalls of ignoring flowback data. In some cases, the time shift on diagnostic plots changes the apparent flow-regime identification of the early gas-production data as well as waterproduction data. This leads to different models of the fracture/ matrix system. The presented work shows the importance of including water-flowback data in the long-term production analysis. IntroductionWater production is usually ignored when analyzing and forecasting shale-gas-well performance. The process involves pumping thousands of barrels of water with proppant and additives into the rock at high pressure. Numerous operators along with Wattenbarger and Alkouh (2013) have indicated that the percent of injected fluid recovered (load recovery) in shale-gas wells ranges from 10 to 40%. Flowback is the early data (water/gas rate and pressure) gathered after fracture stimulation of the well, which might be followed by a shut-in. The flow sequence of the usual shale well is presented in Fig. 1 where there is a shut-in period between flowback and production because delays in the pipeline connection. Most operators ignore flowback data and do not combine it with production data.The paper has four main parts: (1) a review of the literature related to flow-regime identification and the diffusivity equation, (2) verification of the new method with a simulated model, (3)

Sand control and sand management require a rigorous assessment of several contributing factors including the sand facies variation, fluid composition, near-wellbore velocities, interaction of the sand control with other completion tools and operational practices. A multivariate approach or risk analysis is required to consider the relative role of each parameter in the overall design for reliable and robust sand control. This paper introduces a qualitative risk factor model for this purpose. In this research, a series of Sand Retention Tests (SRT) was conducted, and results were used to formulate a set of design criteria for slotted liners. The proposed criteria specify both the slot width and density for different operational conditions and different classes of Particle Size Distribution (PSD) for the McMurray oil sands. The goal is to provide a qualitative rationale for choosing the best liner design that keeps the produced sand and skin within an acceptable level. The test is performed at several flow rates to account for different operational conditions for Steam Assisted Gravity Drainage (SAGD) and Cyclic Steam Stimulation (CSS) wells. A Traffic Light System (TLS) is adopted for presenting the design criteria in which the red and green colors are used to indicate, respectively, unacceptable and acceptable design concerning sanding and plugging. Yellow color in the TLS is also used to indicate marginal design. Testing results indicate the liner performance is affected by the near-wellbore flow velocities, geochemical composition of the produced water, PSD of the formation sand and fines content, and composition of formation clays. For low near-wellbore velocities and typical produced water composition, conservatively designed narrow slots show a similar performance compared to somewhat wider slots. However, high fluid flow velocities or unfavorable water composition results in excessive plugging of the pore space near the screen leading to significant pressure drops for narrow slots. The new design criteria suggest at low flow rates, slot widths up to three and half times of the mean grain size will result in minimal sand production. At elevated flow rates, however, this range shrinks to somewhere between one and a half to three times the mean grain size. This paper presents novel design criteria for slotted liners using the results of multi-slot coupons in SRT testing, which is deemed to be more realistic compared to the single-slot coupon experiments in the previous tests. The new design criteria consider not only certain points on the PSD curve (e.g., D50 or D70) but also the shape of the PSD curve, water cut, and gas oil ratio and other parameters.