Attractive economics

Since electricity-transmission networks in the 10 largest shale gas countries outside the US are up to 10 times denser than gas-pipeline systems, distances from prospective areas to the grid are likely to be shorter than distances to the nearest available gas pipeline. The ratio between these distances is a fundamental factor in determining the relative economic attractiveness of modular gas-to-wire model and the pipeline-transportation model.

The proposed model tends to be the better alternative the greater the ratio becomes or the smaller the gas reserves being considered for development. When the distance to the grid is the same as the distance to a gas pipeline - a ratio of 1:1 - gas-to-wire is an attractive alternative for plays with reserves of up to 1 tcf. This rule-of-thumb (ratio of 1:1) is often used to model the economics of gas-to-wire systems but, in some regions, the 1 tcf figure is too conservative and caps the attractiveness of GTW model at too low a level (Figure 6).

However, the cap on the size of reserves increases in relation to the relative proximity of available transmission lines. For example, the proposed model remains attractive for reserves as large as 3 tcf or 6 tcf if the distance to the grid is three or five times shorter than the distance to pipelines, respectively.

The modular gas-to-wire model is expected to be a competitive economic solution for monetizing a shale play 500 km from gas pipeline infrastructure but five times closer to the grid - i.e. 100 km. With modular sizes of 500 MW or 100 MW, this model can add $1.4 to $1.5 per Mcf respectively, as costs of monetizing the gas, respectively. This cost is comparable to the estimated $1.2 per Mcf cost of monetizing gas produced in an area with access to gas pipeline infrastructure and 500 km distant from the gas delivery point.

In case of non-existing gas infrastructure, constructing a new pipeline to monetize gas to a delivery point situated 500 km away from producing area would only be an attractive option if the reserves exceeded 6 tcf. But proving up this amount of gas would require the drilling of more than 1,200 wells. However, constructing a pipeline before proved reserves reached 6 tcf could result in extremely high monetization costs if exploration fell short of expectations. For example, if 0.5 tcf or 1 tcf of gas were discovered for a pipeline that had been built to monetize over 6 tcf of gas, monetization costs would reach $4.8 or $3 per Mcf, respectively.

The biggest sources of monetization costs of the proposed gas-to-wire 500 MW modular development model are: $0.6 per Mcf for constructing and operating an in-field gas processing plant; $0.3 per Mcf for constructing and operating the first-mile transmission line; and $0.3 per Mcf for increased transmission fees, assuming distance-sensitive tariff for transmission. However, the distance-sensitive tariff method is a conservative assumption in view of other tariff structures (e.g.: the classic postage stamp electricity tariff model).

Depending on the regulatory framework of local power generation markets and commercial terms with consumers, power output might need to remain flat, with no variability throughout the plant's operating life. This would require a similar gas-production profile. Additionally, power-plant operations can be adversely impacted by variations in gas-supply volumes, which could also force the operator to adopt production-variability reduction measures.

In order to minimize this problem and ensure gas supply stability, a production buffer can be created by anticipating drilling campaigns. In such a situation, production could be controlled by choking back wells during periods of surplus.

Measures such as this can ensure virtually stable production - a 95% chance of achieving gas production variability of less than 1%. This would increase the cost of gas at the wellhead by a factor of ~10%. For example, monetization costs would increase by $0.3 per Mcf if producing costs were $ 3.00 per Mcf. If variability-reduction measures were not adopted, probabilistic Monte Carlo simulations indicate, with a confidence of 95%, that gas output would typically vary ± 20% from the expected production plateau. Cost and variability parameters would vary according to several factors, such as the initial production rate from wells and plateau production volume.

Date: 2015-12-11; view: 783