This section presents an overview of the issues that must be considered in the development of shale gas reservoirs, the design of the gas supply chain, and its integration with water management strategies. A generic shale gas supply chain superstructure is presented in Figure 4.1.
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Figure 4.1. Generic superstructure for shale gas supply chain (Reproduced from Guerra et al., 2016 [45]).
Initially, fresh water is transported via trucks or pipelines from sources such as rivers and lakes to locations with high prospective production of shale gas. The transported water is mainly used to produce a fracturing fluid necessary for drilling and hydraulic fracturing operations, the latter activity being highly water-intensive as it accounts for about 86% of the total water consumption over the life-cycle of a well-pad [163]. The fracturing fluid is composed mainly of water (≈90-95 vol%), sand (≈ 4-9 vol%), which is used as a proppant to maintain high permeability of the artificial fractures, and chemical additives (≈ less than 1 vol%). A well-pad can be defined as a cluster of single wells connected at the wellhead to a common point. In its most general form, the design of a well-pad can be described in terms of the number of wells, the horizontal length of each well, and the number of hydraulic fractures per well. The design of a well-pad is a critical aspect in the shale gas supply chain design and planning, since it affects the productivity of the well-pad and also the water requirements. During the early stage of the production of a well-pad, from 1 to 2 weeks, a fraction of the fracturing fluid returns to the wellhead. This fractions is highly variable, ranging between 10%-40% and it depends on geomechanical properties of the formation as well as on the composition of the fracturing fluid. This stream is known as flowback water and presents an average flow rate of 1000 m3/day. There can be additional production of water due to the presence of formation
80 water. This stream is known as produced water and its flow rate is significantly lower than the flowback water, around 2–8 m3/day. Total suspended solids (TSS) and total dissolved solids (TDS) are two important parameters for the characterisation of the wastewater (flowback and produced water) associated with the production of shale gas [85]. For flowback water, the TSS concentration varies from 0.001-0.5 g/L and the concentration of TDS ranges between 5 to 250 m/L. The same ranges of TSS concentration apply to produced water, however, the TDS concentration varies between 10 and 336 g/L [238]. Concentration of TDS in flowback water increases with time, given that minerals and organic constituents present in the formation dissolve into the fracturing fluid [90,239]. Given these characteristics, water management strategies clearly play an important role in dealing with the wastewater associated with shale gas production. According to the wastewater characterisation and its final use, produced and flowback water can be sent either to water treatment plants, for primary and/or secondary treatment, or to deep-injection sites. Primary treatment processes only TSS and re-uses the treated water in new well-pad locations provided that the concentration of TDS is low. Secondary treatment is required if the TDS are higher than the specifications required for drilling and fracturing. In this case, the treated wastewater can be recycled to new well-pad locations or discharged into rivers. Finally, if the technology is available on-site, deep-injection is the most-preferred option as it avoids water treatment costs. However, if the injection point is located far from the reservoir, the trucking costs can be high enough to consider water treatment technologies instead. The concentration of TDS is one of the most important evaluation parameters for wastewater treatment economics and management strategy.
The composition of the produced shale gas depends on the geochemical characterisation of the shale formation. Shale gas can be classified as dry gas (methane > 90%, with the rest largely CO2 and N2) or wet gas (methane, ethane, condensable fractions of propane, butane, iso-butane, CO2, N2). Usually, the composition of shale gas varies not only with location but also as the production progresses. The produced shale gas is sent to gas treatment facilities via pipelines
81 either directly or through compressor stations. The gas is separated into different fractions and then the final products are sent to final customers, i.e. petrochemical plants, power stations, national gas pipeline network, etc. The novelties of the optimisation framework are summarised as follows:
Off-line integration of reservoir simulation tools in shale gas supply chain design and planning: Implementation of reservoir simulation techniques that allow the assessment of optimisation of shale gas supply chains by taking into account geological properties of the shale reservoirs.
Off-line integration of geographic information systems (GIS): ArcGIS® 10.2 [240] is implemented in order to design of potential infrastructure of shale gas and water supply chains. In addition, this tool is used to carry out a national hydrological balance to estimate water availability based on historical data on precipitation, evapotranspiration, infiltration, and downstream demand.
Novel formulation of water management aspects: The explicit modelling of water blending for fracturing operations as well as in wastewater treatment plants considered. The formulation also takes into account constraints on spatial and temporal variations of Total Dissolved Solid (TDS) in fracturing operations and wastewater treatment plants.
Integration of design and planning of the gas supply chain along with water management: The optimisation framework allows the simultaneous optimisation of the decisions involved in the design and planning of the gas supply chain and the water management.
The corresponding optimisation framework is presented in section 4.3