CERI: Energy, operational efficiencies possible in Canadian oil, gas

Measures can be taken by operators in the expanding resource-intensive Canadian oil and gas sector to improve both energy efficiency and operational efficiencies, according to a report from the Canadian Energy Research Institute (CERI).

That increasing strain on resources can manifest through rising capital cost intensity due to limited labor supplies and construction materials, and environmental costs such as consumptive use of fresh water and emissions of greenhouse gases (GHG), CERI explained in its report, “Process Efficiencies of Unconventional Oil & Gas.”

Primary options for improving energy efficiency include using readily available, economically viable technologies that reduce overall energy consumption, which may not be used currently because of the age of a facility or slow adoption of new technologies, the report says.

Strategies range from optimizing the operations of existing equipment to replacement of outdated equipment with more modern, energy efficient versions. CERI cites as an example that “significant” energy savings can be had in steam assisted gravity drainage (SAGD) operations by adding mechanical downhole pumps rather than using reservoir pressure to retrieve bitumen from a well.

In oil sands mining, use of paraffinic froth treatment to partially upgrade bitumen through asphaltene removal can eliminate the need for an onsite upgrader, which reduces the overall life cycle emissions of mined oil sands bitumen.

Adopting best practices can result in a 10% reduction in energy consumed per unit of production, with improvements by way of lower GHG intensity, lower air emissions, and lower operating costs, the report says.

Operational challenges

Meanwhile, growth is anticipated in both natural gas production from shale resources and in situ bitumen production from oil sands, placing pressure on the construction industry and leading to inflated costs.

CERI notes that shale gas resources in the Montney and Horn River basins of northeastern British Columbia are in regions with relatively little previous drilling, and services tend to reside in areas distant to the location of drilling. Construction delays due to transport or scarcity of materials can be avoided by:

• Locating rig storage and servicing equipment in municipalities closer to British Columbia shale development.

• Coordinating drilling activity on a large scale to achieve savings from economies of scale.

• Developing local sales points of important hydraulic fracturing materials such as chemical additives and sand for proppant.

With in situ oil sands, a promising way to cut construction costs is to increase the degree of modularization used in the facility design, which allows much of the facility to be produced offsite in areas with higher labor productivity, shipped to the well site, and constructed in a short period of time, the report says.

It notes that modularization prevents cost escalation from the overshooting of construction timelines, and allows for the equipment to be quickly taken down and moved to a new well site at the end of a project’s lifetime.

Environmental challenges

Production growth also exerts upward pressure on Canadian GHG emissions, and shale gas production has the additional challenge of using large volumes of water. In the main shale gas basins in British Columbia, low availability of surface fresh water is often an issue.

CERI emphasizes that larger impact changes to operations must be adopted to overcome those challenges, as incremental reductions in fuel or resource use are low enough in magnitude to be overshadowed by projected growth in production. Shale gas resources can reduce reliance on local freshwater by using municipal or industrial wastewater, using fracturing additives that are compatible with lower water purity, or increasing the rate of recycling of flowback water from previously fractured wells. Switching from diesel rigs to those operating with natural gas can reduce energy costs and GHG emissions.

Use of hydrocarbon solvents for in situ bitumen production may increase the energy and operating cost efficiency of a project compared with steam-only thermal extraction while reducing water usage. In steam-solvent hybrid methods, a small amount of light hydrocarbon solvent can reduce steam-oil ratios by half, reducing the amount of water needed per barrel of oil and, as a result, the amount of fuel needed to generate steam.

Solvent methods without steam can eliminate the need for water, operate at much lower temperatures and pressures and thus require less natural gas for heat, and produce a partially upgraded bitumen product by removing asphaltenes in the reservoir.

The major barrier to solvent methods is the rate of recovery of solvent from the reservoir, the report says. Substantial loss of solvent to the reservoir could represent a major increase in operating costs that counter savings from fuel use reduction. Waterless solvent processes would likely have significant capital cost reduction compared with SAGD variations as facilities can be much simpler in scope and design.

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