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The production of shale gas requires both vertical and horizontal drilling. Vertical drilling, a commonly used technology in the conventional oil and gas industry, is used to reach the deep shale formation. Nonetheless, vertical wells can

47 intersect a limited amount of the shale reservoir, since shale formations are usually thin layers, less than 90 m (295.3 ft), extending over areas of thousands of acres [161]. Horizontal drilling is then needed in order to extend the vertical well horizontally to access a wider area of the formation, reducing the need for surface disturbance. Metal casing and cement are used to secure each section of the well. Although, drilling a horizontal well could cost between three or four times more than a vertical well, total drilling costs for intersecting the same area is much lower when horizontal wells are used. Drilling costs depend on a number of variables, including depth, well configuration and design, location, and formation type.

3.1.2.2 Stimulation

Due to the low permeability of shale formations, successful production is only achievable by means of stimulation techniques such as hydraulic fracturing. Therefore, after drilling the well, the cemented casing across the formation is perforated in order to stimulate the reservoir and start the production of shale gas. The design of the hydraulic fracture is a crucial step in achieving good performance of a well in terms of productivity. A proper design seeks to maximise the SRV by contacting as much as possible of the natural fractures with the wellbore. Local geological stresses are essential parameters to predict the hydraulic fracture growth in the formation. Commonly, the fracture stages are located perpendicular to the natural fracture network to intersect as many fractures as possible [162].

In reservoir simulation, a hydraulic fracture can be modelled as a complex geometry, commonly driven by microseismic data [149], or as a simple planar structure [159]. Usually, due to limitations in the information about the formation, preliminary assessments of the performance of a fracture are based on the planar structure approach. Five parameters are necessary to define the properties of a hydraulic fracture: width, permeability, half-length, height and fracture spacing. Figure 3.2 illustrates some of these parameters.

48

Figure 3.2. Hydraulic fracture components (x-axis ranges from 6,300 ft to 7,300 ft, and y-axis ranges from -2,000 ft to -1,300 ft).

3.2 Performance Metrics

In order to quantify the performance of a well-pad design from economic and environmental perspectives, different performance metrics are relevant and are presented next. The first metric is related to the efficiency of the investment, denoted as the Profitability Index , where index d is used to denotes the design of a specific well-pad. Another valuable metric, particularly from an environmental point of view, is the Water Intensity . The calculation of the above mentioned metrics are summarised in the following sections.

3.2.1 Economic model 3.2.1.1 Net Present Value

The Net Present Value (NPV), associated with the implementation of a specific well-pad design, is defined as the difference between the present value of the cash inflows and the initial capital investment, , as stated

 

 

 

 

49 in Equation (3.3). The capital investment depends on the fracture dimensions and the total number of fractures completed at each well, as well as on the total number of wells drilled on the single well-pad. Scalar represents the discount rate. Additionally, index is used to denote number of time periods in years within the time horizon of interest.

𝑁𝑃𝑉(𝑑) = ∑𝐶𝑎𝑠ℎ𝐹𝑙𝑜𝑤(𝑑, 𝑡)

(1 + 𝑟)𝑡−1 𝑡

− 𝐶𝑎𝑝𝑒𝑥(𝑑) ∀𝑑 _(3.3)

3.2.1.2 Cash Flow

The cash flow, for a specific design and during a given time period, is calculated from the cash balance expressed in Equation (3.4)

𝐶𝑎𝑠ℎ𝐹𝑙𝑜𝑤(𝑑, 𝑡) = 𝑃𝑟𝑜𝑓𝑖𝑡(𝑑, 𝑡) + 𝐷𝑒𝑝 ∗ 𝐶𝑎𝑝𝑒𝑥(𝑑) − 𝑇𝑎𝑥𝑒𝑠(𝑑, 𝑡) ∀𝑑, 𝑡 (3.4)

where and denote the profit, and taxes fees respectively. Additionally, scalar represents the depreciation rate.

3.2.1.3 Profit and Taxes

The profit refers to the surplus remaining once total cash outflows are deducted from the revenue. The profit is estimated as stated in Equation (3.5). Here, , , and represent the revenue, the royalties, and the total operating expenditures, respectively.

𝑃𝑟𝑜𝑓𝑖𝑡(𝑑, 𝑡) = 𝑅𝑒𝑣𝑒𝑛𝑢𝑒(𝑑, 𝑡) − 𝑅𝑜𝑦𝑎𝑙𝑡𝑦(𝑑, 𝑡) − 𝑂𝑝𝑒𝑥(𝑑, 𝑡)

−𝐷𝑒𝑝 ∗ 𝐶𝑎𝑝𝑒𝑥(𝑑) ∀𝑑, 𝑡 (3.5)

Taxes are fees levied by governments on profit that is generated from business activities. Taxes paid are defined in Equation (3.6), the scalar represents the tax rate. 𝑇𝑎𝑥𝑒𝑠(𝑑, 𝑡) = 𝑡𝑟 ∗ 𝑃𝑟𝑜𝑓𝑖𝑡(𝑑, 𝑡) ∀𝑑, 𝑡 (3.6) r t

 

 

 

Revenue d t Royalty d t

 

 

50

3.2.1.4 Revenue

The amount of money received by the company from selling the shale gas to the market is defined as revenue, which is expressed as the product of product prices and total amount sold to the market. The revenue can be estimated from Equation (3.7); where , , and are the unit price of gas products, the shale gas composition, and the total shale gas production during each period of time, respectively.

𝑅𝑒𝑣𝑒𝑛𝑢𝑒(𝑑, 𝑡) = ∑ 𝑃𝑟𝑖𝑐𝑒(𝑘, 𝑡) 𝑘

∗ 𝐶𝑜𝑚(𝑘) ∗ 𝑃𝑟𝑜𝑑(𝑑, 𝑡) ∀𝑑, 𝑡 _(3.7)

3.2.1.5 Royalties

When a company wants to develop a natural resource, shale gas in this case, it has to pay compensation to the owner of the mineral rights, for instance, a person or government. This compensation is known as royalty, and is usually defined as a percentage of total production or an amount of money agreed in the contract between the company and the mineral rights owner. In this work, the royalties are defined as a percentage of the revenue, as expressed in Equation (3.8). The scalar represents the royalty rate.

𝑅𝑜𝑦𝑎𝑙𝑡𝑦(𝑑, 𝑡) = 𝑟𝑜𝑦 ∗ 𝑅𝑒𝑣𝑒𝑛𝑢𝑒(𝑑, 𝑡) ∀𝑑, 𝑡 (3.8)

3.2.1.6 Operating Expenditures

Wellhead shale gas is usually a mixture of different hydrocarbons, gases such as carbon dioxide and nitrogen, as well as flowback or produced water. In order to meet gas quality requirements, shale gas should be transported and processed. In addition, flowback and produced water may require physical and chemical treatment to meet regulations for discharge or water quality specifications for re-use and recycling. The total cost associated with these activities is defined as the operating expenditures, and is given by Equation (3.9). The scalar represents the unit operating cost for gas, while scalar denotes the unit cost for the

 

Price k t Com k

 

 

roy

WellOpex

51 treatment of the flowback and produced water. Total water production (flowback and/or produced water) is denoted by parameter .

𝑂𝑝𝑒𝑥(𝑑, 𝑡) = 𝑊𝑒𝑙𝑙𝑂𝑝𝑒𝑥 ∗ 𝑃𝑟𝑜𝑑(𝑑, 𝑡) + 𝑇𝑟𝑒𝑎𝑡𝐶𝑜𝑠𝑡 ∗ 𝑊𝑎𝑡𝑒𝑟(𝑑, 𝑡) ∀𝑑, 𝑡 (3.9)

3.2.2 Profitability Index

The profitability index, which is a cost benefit relationship for a given well-pad, is defined as the ratio of the NPV to the capital investment, as expressed by Equation (3.10). The higher the profitability index is, the more economically attractive the proposed investment is. The variables and are estimated as described previously in Section 3.2.1.

𝑃𝐼(𝑑) = 𝑁𝑃𝑉(𝑑)

𝐶𝑎𝑝𝑒𝑥(𝑑) ∀𝑑 (3.10)

3.2.3 Water Intensity

Water intensity, defined as the ratio of water consumption to Estimated Ultimate Energy Recovery , is a measurement of water use efficiency. A lower value of water intensity means a higher efficiency in the use of water resources and consequently less environmental impact associated with water supply and management. Regarding water use, different studies have been reported on the life cycle of water consumption associated with the development of shale gas resources [7,163,164]. The life cycle includes not only water consumption for drilling and hydraulic fracturing operations but also flowback, produced, and disposed water. This study focuses principally on water consumption during the drilling and hydraulic fracturing operation. That is, given that the wastewater management is not addressed in this work, flowback and produced water, as well as water disposed are not included in the water balance. In addition, the is estimated as the product of the energy density of the shale gas (MM Btu/MMSCF) and the estimated ultimate recovery . The water intensity associated with a specific well-pad design is determined as shown in Equation (3.11).

 

 

 

 

 

 

 

52

𝑊𝐼(𝑑) =𝑊𝑎𝑡𝐷𝑒𝑚(𝑑)

𝐸𝑈𝐸𝑅(𝑑) ∀𝑑 (3.11)

3.3 Reservoir Simulation

Reservoir simulation is a robust tool that allows to study the influence of formation properties along with well-pad designs on production profiles. In this section, a discussion regarding the state of art of available tools for reservoir simulation is presented. In particular, it is highlighted the extension of well- established methods developed primarily for conventional reservoirs and their application in more complex systems such as unconventional reservoirs.