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| Fracing operation underway in the Marcellus region of rural Pennsylvania. The use of bi-fuel fracing pumps reduced the environmental footprint. Photo courtesy of Cabot Oil & Gas. |
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In the ongoing push to maximize production at minimal environmental impact and expense, oil and gas companies are searching for more efficient and cleaner E&P technologies that help achieve these goals. At North American wellsites, this search has led to a growing interest in engines for drilling rigs and frac pumps that are powered, in part, by natural gas. Bi-fuel or dual-fuel engines use a combination of diesel fuel and natural gas—which is abundant, relatively inexpensive and clean—to help operators lower their operating expenses and the environmental footprints.
Cabot Oil & Gas has successfully used bi-fuel engines on drilling rigs in its Marcellus shale assets, and realized economic and environmental benefits in its drilling operations. Cabot wanted to extend these benefits to its hydraulic fracturing operations by utilizing bi-fuel-powered pumps.
BI-FUEL ENVIRONMENTAL DRIVERS
Like many operators, Cabot views increased implementation of bi-fuel engines as a way to satisfy the industry’s need for greener completions. The term refers to methods that minimize the release of greenhouse gases and volatile organic compounds (VOCs) during the completion phase of a well, by limiting the exposure of the produced gas to the environment by capturing and injecting it into the sales line, rather than flaring.
Much of the drive for green completions comes from increased regulations at both the federal and state levels. As part of the Clean Air Act, the U.S. Environmental Protection Agency (EPA) has adopted multiple tiers of air emission standards for non-road diesel engines. Most recently, EPA has introduced a national program aimed at reducing engine emissions by integrating engine and fuel controls, as a system, to gain the greatest emission reductions. These Tier 4 emission standards will require engine manufacturers to decrease exhaust emissions by more than 90%, by producing engines with advanced emission control technologies similar to those already in place for highway trucks and buses.
Regulatory authorities at the state level also have their own sets of emissions regulations. In states such as California, Colorado and New York, many regulations go further, and are more restrictive than federal rules.
Apart from regulations placed on the industry, many companies are going above and beyond the requirements, whenever possible. One such example is Cabot’s ability to directly turn wells in-line after the completions process, rather than flaring. New EPA regulations will make this the industry standard in 2015, but Cabot is already adopting the process in areas, where pipelines are available.
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| Fig. 1. Baker Hughes Rhino pumps are driven by Cummins bi-fuel engines. |
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GREEN COLLABORATION
Cabot has worked closely with Baker Hughes to develop and implement frac services in the Marcellus region that aim to reduce the operator’s environmental footprint while sharing the economic incentives for green completions. On the bifuel engine front, Baker Hughes, working with its engine supplier, Cummins, has converted its Rhino hydraulic fracturing pumping units to run on natural gas-diesel fuel blends.
The Cummins diesel engines are retrofitted with bi-fuel conversion kits. The engine supplier has developed bi-fuel engines, ranging from 800 to 3,500 hp, for high-horsepower markets, such as oil and gas well servicing applications. While the first engines met Tier 2 EPA emissions regulations, Cummins is now developing bi-fuel engines that meet Tier 4 Final standards.
The process of converting a diesel engine to run on a natural gas-diesel mix is minimally invasive and requires little modification to the original engine. A conversion kit consists of a programmable logic controller (PLC), ductwork to transport natural gas to the engine, and a series of regulators to reduce the gas pressure prior to entering the engine’s combustion chamber. The PLC signals a throttle valve that controls the natural gas volume entering the engine, as well as the subsequent substitution rate of natural gas for diesel.
While natural gas can make up the majority of the fuel mixture, some diesel is required to act as the ignition source. However, once the diesel starts the engine, the PLC slowly ramps up the natural gas injection. The injection rate of natural gas increases with the horsepower output of the engine, up to a current maximum substitution level of 70% natural gas to 30% diesel.
The bi-fuel system responds quickly to changes in natural gas supply pressure, engine knock and cylinder temperature, by making systematic adjustments to optimize the substitution rate and protect the engine. If the natural gas supply is compromised, the PLC can react and turn off natural gas flow in as little as 250 msec, while the engine continues running without interruption on 100% diesel, until the gas supply problem is corrected. The well completion experiences no negative consequences with respect to engine performance, due to natural gas delivery variations.
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| Fig. 2. Overview of frac pump setup. |
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FIELD APPLICATION
Cabot planned a stimulation operation that called for the service company to provide a fleet of 14 bi-fuel pumps, to stimulate a 10-well Marcellus pad, with a total of 170 frac stages. While the pumps could operate on natural gas supplied as CNG or LNG, the operator chose to use its own field gas as the source, which was abundant and readily available from gathering lines in close proximity to the frac site.
LNG and CNG provide smaller carbon footprints compared to diesel, and they satisfy the lower emissions requirements for green completions in the field. However, these sources still require processing at remote facilities, over-the-road transportation to the field, and onsite storage, all of which adds cost and increased environmental and safety concerns.
Field gas was the lowest-cost, most-sustainable option, as its close proximity to the wellsite generated a lower, total carbon footprint, compared to any other natural gas source. Furthermore, Cabot’s exceptionally pure field gas is rich in methane, which increased the engine efficiency, required minimal processing and eased concerns about supply disruptions.
While it was not required in this application, the service company deployed a Joule-Thompson skid in other liquids-rich fields to separate heavier components, such as ethane, propane and butane. Rather than flare off these heavier hydrocarbons, the separated components can be recirculated into the operator’s sales line, further lowering both emissions and costs.
The field plan called for piping field gas from some of the operator’s producing wells to a gas processing unit (GPU) near the frac pumps. The GPU contained a dryer to remove condensate, and a filter to remove particulates from the field gas to avoid any reductions in engine performance. The pressure was then reduced from 600 psi to approximately 50 psi, after which the natural gas was piped to a conduit and distributed to each bank of bi-fuel pumps.
The bi-fuel technology performed as planned, consuming 15,100 Mcf of field-supplied natural gas, and delivering benefits in terms of both efficiency and environmental performance. There was no loss in hydraulic horsepower, compared to a diesel-only engine, and all 10 wells (170 stages) were fractured in 27 days. Cabot twice achieved a company record of nine stages fraced in a 24-hr period.
Substitution rates were uniformly high and frequently reached the maximum blend of 70% natural gas. Cabot calculated that the use of the Baker Hughes bi-fuel fleet allowed the firm to offset approximately 110,000 gal of diesel with its own natural gas, and saved more than $475,000 in fuel costs.
Cabot also eliminated as many as 16 diesel re-supply runs, based on the operator’s use of 7,200-gal tanker supply trucks, its simplification of logistics, and its reduction in the amount of traffic at the wellsite and through neighboring communities. The reduced diesel usage also lowered potential HSE risks related to refueling, including challenging and potentially dangerous “hot fueling” operations.
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| Fig. 3. Connection point between field gas supply and bi-fuel manifold. |
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FRAC FLUID SCREENING
Baker Hughes screened all frac fluid components, using its Chemical Evaluation Process Review (CEPR) program, an evaluation methodology designed to ensure that sustainable oilfield chemicals are developed and deployed, and adhere to all relevant regulatory requirements. Chemicals evaluated and deemed to meet stringent environmental and toxicological standards are categorized as SmartCare qualified products.
As part of the CEPR program, a team of specialized chemists and toxicologists evaluate the individual components of a product to determine their compliance with several criteria:
- Highly discouraged substances. All chemical components are screened to ensure that they do not fall on the United Nations’ list of persistent organic pollutants or the EPA’s lists of persistent bioaccumulative and toxic chemicals.
- OSPAR HMCS pre-screen. Formulated products and their constituent components are prescreened to regulatory criteria within the OSPAR Harmonized Mandatory Control System (HMCS), which oversees the use and discharge of oilfield chemicals in the North Sea.
- Regulatory assessment. Each chemical is assessed, based on criteria from more than 20 different regulatory lists from throughout the world, which helps Baker Hughes identify potential regional usage concerns and determine if suitable substitute chemistries are available.
- Chemical hazard evaluation. Products and components are scored, based on a quantitative assessment of environmental, toxicological and physical hazards. This method is patterned after the UN Globally Harmonized System (GHS) of Classifying and Labeling chemicals.
GREENER COMPLETIONS
The combined contribution of the bi-fuel system and qualified fracturing additives is helping Cabot achieve one of the cleanest completions in North America. The operator plans to repeat this success with Baker Hughes in future Marcellus frac operations in the year ahead, and will continue to collaborate to drive greater operating efficiencies and lower emissions from these service offerings, to stay ahead of newer, more stringent regulatory guidelines. 
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