Investment to infrastructure that transports crude oil, natural gas, and natural gas liquids (NGL’s) accelerate in response to growth in domestic production with a structural shift from import to export oriented infrastructure. Shale oil and gas production has been the primary driving force and IHS estimates a sustained period of high levels of investment over the next 12 years that will be accompanied by its fair share of challenges.

IHS forecasts that 60% of oil and gas infrastructure investments over the next 12 years will be allocated to crude oil and natural gas gathering systems and direct production support facilities. This forecast, made in its report "Oil & Natural Gas Transportation & Storage Infrastructure: Status, Trends, & Economic Benefits," showcases the scale of investment made. For example, direct capital investment in crude oil gathering and support facilities doubled from $15 billion in 2010 to $30 billion in 2013 and the cumulative spending forecast reaches $890 billion during this time frame.

(Aaron Brady, senior director of Global Oil Markets for IHS Energy discusses the transformation of North American oil logistics in this video.)

The nature of the investments is to redirect flow paths and migrate away from the use of rail and marine as modes of transportation. Historical patterns of using long distance pipelines will reemerge as the most efficient and economical choice while regional gathering systems will be required to aggregate production from the upstream unconventional oil and gas sector.

Over the next five years investments are forecast to display a bias towards liquids (crude oil and natural gas liquids). With historically low U.S. natural gas prices the spread in oil-to-gas prices has increased. Oversupply from natural gas shale production has initiated this short-term pivot that will persist until natural gas prices rebound.

As unconventional plays are exploited for the more valuable resource drilling and production rates outpace the development of gathering infrastructure. The resultant bottlenecks, areas where production rates exceed pipeline capacity, forces producers to flare the lower value product, natural gas.

Production Struggles

With a need for regional gathering infrastructure, namely the pipelines that need to be in place to collect the oil, producers are struggling. Increased regulations, unusual production rate, and composition variability collectively impose design challenges.

Regulations that restrict flaring of natural gas will require operators to increase gathering system capacity. Source: Energy Information Administration

Increasing pipeline capacity in liquid-rich unconventional fields is not as easy as it sounds. Production characteristics unique to unconventional plays include high initial production (IP) rates and a steep decline curve. This results in a highly variable production rate that impacts the producer’s ability to economically design gathering infrastructure. This holds true for dry gas plays as well where one disadvantage in over-sizing gathering lines is the excess capital investment. In oil shale plays, operating problems also exist.

As outlined in the article Liquid-Rich Resource Plays Challenge Facility Design published by The American Oil & Gas Reporter, over-sizing gathering lines in liquid rich plays increases slug volumes, which are quantities of liquids that can plug the pipeline. This occurs because the associated gas contains heavier hydrocarbons that are prone to phase changes, from gas to liquid, increasing drop-out rates.

Traditionally, a process known as gas line sweeping allows transport of a two-phase stream. As over-sizing gathering lines decreases line velocity the gas stream becomes unable to efficiently sweep the liquid portion through the piping. The excess hold-up volume, namely the liquid portion that accumulates in the gathering lines, adds to the slug volume and decreases pipeline capacity. In order to keep slug volumes manageable, excessive pigging (a term of art that refers to pipeline maintenance or cleaning) or special handling becomes an added capital expense.

A second challenge rising from the unusual production rates is hydrocarbon vapor formation. Declining pressure and increasing temperatures in the resource-bearing formation cause a shift in the gas-to-oil ratio (GOR). This occurs when pressures fall to meet production equipment requirements. Gas vapors break out from the production stream and cause an increase in the GOR.

Variability also exists between wells in unconventional plays. Characteristics such as GOR, crude oil and gas composition, temperature and pressure can fluctuate between wells in close proximity. This has two implications; first drilling activity is scheduled and approved incrementally forcing modifications to proposed gathering systems, secondly inflow behavior is unpredictable and requires new tools in order to make accurate predictions.
Increasing regulations, unusual production rates, composition variability and the need for design flexibility are significant challenges that will persist.

Accurate forecasting and flexibility in the development cycle will be required in order to meet the needs of the upstream oil and gas sector. Higher levels of investment are forecast to persist through 2025 after which there will be a moderate decline as the nature of unconventional fields will keep capital expenditure in midstream assets fairly steady for the unforeseen future.