BP NOEL - A CANADIAN UNCONVENTIONAL GAS DEVELOPMENT AND EXAMPLE OF ENVIRONMENTAL IMPACT REDUCTION

Trent Yackimec

1, Phil Aldis

2, Dario Castro

3

1. BP Canada Energy Company 2. BP Canada Energy Company 3. BP Canada Energy Company

Keywords: 1. Emission reduction; 2. Footprint reduction; 3. Engineering design; 4. Well Site;

5. Pipeline 1 Introduction/Background

Amongst mature oil and gas producing areas, unconventional gas resources are becoming an increasingly important part of the hydrocarbon supply picture. While holding large quantities of reserves, tight gas, coal bed methane, and shale gas plays inherently present difficulties to development. By their very definition, these projects require an extensive infrastructure investment in wells, technology, pipelines, and compressor capacity in order to monetize the resource.

Now, more than at any time in history, the environmental impacts of public works projects receive

the public scrutiny they rightly deserve. Projects are continually challenged to address their impact on the environments around them and mitigate those effects. Air emissions, physical footprints, water usage, wildlife disruptions: all are issues that must be addressed while completing conceptual studies and design. While these issues are relevant to all developments, they are even more so to unconventional gas projects with hundreds or thousands of wells planned over hundreds of square kilometers. The surface disruption is much larger than that of a conventional field development and the environmental impacts are therefore that much more extensive. Actively minimizing your environmental footprint has many positive benefits for a project including enhanced stakeholder relations, potential reduced capital costs, and continuing regulatory goodwill.

2 Objectives of the paper

This paper will highlight some of the key strategies available for minimizing the environmental impact of unconventional gas projects and highlight examples from a case study, BP’s Noel Major Project, a tight gas development in the foothills of the Canadian Rocky Mountains. The project scope includes 133 gas wells, drilled into two distinct reservoirs (111 sweet gas wells, 22 sour gas wells), at 85 well site pads with recoveries in excess of 75 mmboe. Approximately 210 km of low pressure gathering system delivers the gas volumes to one of three nodal facilities where the gas is compressed and dehydrated. In addition to the low pressure gathering system, the project includes 60 km of high pressure, large diameter (8” – 12”) trunk lines transporting the dry, high pressure gas to a third party delivery point for final processing and sales transfer. Through innovation and engagement with local stakeholders, the project has managed to significantly reduce its environmental impact.

Figure 1 : Noel Project Area

3 Development/Methods

a. Front End Engineering and Design

An articulated position written into the project Statement of Requirements, addressing the minimization of environmental impacts, is the absolute first step required to focus team energy and activities and place an emphasis on environmental impact reduction activities. Unless visible management support exists for the activity, the best intentions of individual project team members will fall aside as the team develops the overall definition of the project particularly in unconventional gas plays were economics are often challenged. Similar to the other facets of the design, decisions and changes made to the project, in an attempt to realize environmental considerations, during initial Front End Engineering have a much smaller impact than trying to force fit solutions later in the project life. Management support in dedicating time and resources during the initial design phase of a project allows for environmental considerations to be evaluated as design options are progressed.

Inherent to unconventional gas developments are large numbers of wells (hundreds or thousands)

over a large land area. Decisions made early in the project on types of wells and well site placement have a direct impact on both environmental impact and capital costs of development. Often, the project team needs to challenge their own assumptions and inertia to realize gains. For instance, tremendous savings can be achieved through the use of multi-well pads. Utilizing a single pad for numerous wells allows for both an environmental achievement (reduction in physical ground disturbance) as well as a potentially significant capital savings as multiple wells utilize the same infrastructure. Access roads, pipelines, telecommunications, etc. can all be reduced in scope by utilizing multi well pads but the benefits cannot be achieved without challenging the project team early to incorporate such a design.

Through exactly such a challenge, the Noel Major Project team was able to extensively make use of

multi-well pads for the development of the sweet, tight gas (Cadomin) horizon. With respect to the Cadomin portion of the project, the field development includes 111 well sites on 66 well pads. Multi-well pads by themselves are certainly not a stretch and are used extensively in industry. Challenging the well design to maximize the use of the pads is where the real benefit lies. In the Noel field, competitor activities in the area

began with vertical wells to access the formation. The result was costly both from environmental and capital viewpoints as it resulted in extensive well site development. Execution of the BP Noel Major Project using a conventional vertical well design would require an incredible 592 wells with a surface footprint of 5,920,000 m²!

Over the period of 5 years, even prior to the official formation of the Noel Major Project, BP

subsurface and drilling personnel have been challenging the status quo and pushing well design in the project area beyond the norm. Over that period of time, the design has evolved into open-hole wells with horizontal legs in excess of 2000 m. Developing the capability and understanding requried to utilize such wells for the project has allowed for the achievement of a staggering 80% reduction in the number of well sites required to develop the field. When including all associated aspects of the well site construction, including site preparation, well site construction, and pipeline infrastructure, having the space and resources available to challenge the well design has resulted in savings in excess of $700 MM USD and reduced the physical footprint of the project by 8,658,000 m² of forested land

Relative Comparison - Conventional

Vertical Well Design vs Noel Major Project

Wells Cost Footprint

Conventional Development Noel Major Project

Figure 2 : Relative comparision of Noel Project Design vs Traditional Design of

Competitors in the Project Area It’s important to note that at this stage, environmental responsibility and capital efficiency are not

mutually exclusive objectives. Through management giving the project team the time and space, and political will, to challenge the norm, the project was able to develop the subsurface and drilling understanding to the point that allowed for the use of horizontal wells on multi-well pads, thus reducing both the capital required to develop the field and the environmental footprint of the overall project. The savings achieved moved the project from uneconomic to viable and distinctive.

b. Pipeline Footprint

A further benefit of a robust engineering design supported with a thorough front end loading effort is the identification and understanding of design features over the entire scope of the project. Unconventional gas developments including hundreds or thousands of wells ultimately lead to a spider web of pipeline infrastructure. As described in the previous section, the strategy of utilizing multiple well pads can reduce this footprint and is employed successfully on many projects. But, in addition to this, a thorough understanding of the project details over the entire field development allows for the identification of construction efficiencies that enable a reduction in physical footprint and overall capital costs. For example,

identification of a well scheduled to be drilled in the future may facilitate the installation of its gathering system tie-in pipeline along a common right of way with other lines being installed today. A strategy of installing future pipelines along a common right-of-way with other pipelines being put in service immediately has two distinct advantages. Firstly, the right-of-way width (and subsequently the amount of trees required to be cleared) for two lines in the same ditch is 70% that of running the two lines in separate ditches in the future. This benefit is further enhanced with more lines running parallel in the common trench. Three common lines reduce the right-of-way space 44% over separate installations. Capital efficiency can also be achieved by running two lines in a common ditch versus separately. An additional 4” line, for example, costs 33% of the first 4” line installed. Likewise, a 6” line can be installed for 36% of the cost of running it separately at a later date. It’s appreciated that there is an economic component that must be evaluated when deciding if lines should be installed today for future use.

The Noel project, through a tremendous effort of early planning, has identified all well locations

required to access the reserves in place and designed the entire pipeline infrastructure required to support those wells. During construction, multiple pipelines are being laid into a common right-of-way and riser sites not necessarily required for initial production are being installed to allow for easy tie-in of future wells with zero impact to the existing right-of-ways. While this strategy requires an emphasis on upfront planning and an investment in pipelines to be utilized in the future, it reduces the footprint of the pipeline infrastructure to a minimum.

Laying of multiple pipelines within a common trench

c. Well Site Emissions

The use of natural gas as motive gas for well site valves and pumps has been the industry standard for many years in Canada. This process utilizes high pressure well head gas to provide the driving force required to actuate emergency shutdown valves, pressure control valves, and well site chemical injection pumps. While functionally acceptable, this practice results in a continuous loss of natural gas vented to the atmosphere. The drawbacks of the practice are twofold. Firstly, the Intergovernmental Panel of Climate Change reports the global warming potential of methane to be 21 times that of carbon dioxide. Simply venting the gas has a much larger impact on the environment than burning the same volume of gas. Secondly, and more importantly, the continuous venting of process gas results in reduced gas flow at the sales meter. Although the volumes appear small, they can add up over time to measurable values with a definite impact on project cash flows.

Specific to the well site design incorporated on the Noel Major Project, it is estimated that 2.7 mmscf

/ well would be vented as instrument gas over the period of one year. Over the span of 111 sweet well sites in the full field development, 304 mmscf / year would be unrealized as a saleable product. At $4 USD / mmbtu, the value of this gas is approximately $1.2 MM USD. While small when compared to the overall production value of the field, it is worth chasing in an effort to maximize project value.

In an effort to eliminate these raw gas vents from sweet well sites, the Noel Project is utilizing a

combination of electric chemical injection pumps, electro-hydraulic valve actuators, and a solar panel array with battery storage and a thermo-electric generator backup. Inclusion of such a well site system is estimated to reduce greenhouse gas emissions by 1 kT CO2 / year for each well. Once the field is drilled out in approximately 8 years, savings of 111 kT CO2 / year will be achieved. See Figure 3.

Adopting a near-zero emission well site requires a capital commitment for the upgrade of well site

equipment. Electric chemical injection pumps are marginally more expensive than gas driven options ($3000 / pump versus $2500 / pump) but the upgrade to electro-hydraulic valve actuators and the power system required to operate the site is more substantial. Updating the emergency shutdown valve (ESD) and pressure control valve from Bettis and Fisher 46 actuators respectively to Rotork electro-hydraulic actuators has increased the cost of a well site by $20 K USD. Additionally, the well site power system must be capable of 3.44 amp output in order to allow for proper site operation. Each well site includes a hybrid power system comprising of 12 - 140W solar panels, a battery pack, and a thermo-electric generator (TEG) to serve as a backup power source. The Noel Major Project is located on latitude 55° 46' 0" N, approximately 60 km from Mile 0 of the Alaska Highway. The project area experiences eight hours of sunlight during the winter season and the TEG was added to provide a reliable backup power source during periods of reduced sunlight. Based on an average solar year at the project site, 80% of well site power will be supplied via the solar panels with the TEG operating the remaining 20% of the time. The hybrid power system adds an additional capital cost of $22 K USD / well.

Well Site Solar Panels Backup Therm-Electric Generators

The Noel project has chosen to include approximately $43 K USD of additional capital on each well site to allow for the capture of 2.7 mmscf of natural gas each year. Admittedly, the economics associated with the capture of the instrument gas is marginal but the choice allows for future positive benefits, including the avoidance of any carbon tax that may be applied over the life of the field. While far from certain, carbon taxes or emission credits are gaining traction within political discussions and are a risk to project economics around the globe. Indeed, the Province of British Columbia, in which the Noel Major Project is located, has already initiated a carbon tax for emitters in excess of 100 kt/yr. Based on a projected tax value of $12 to

$15 per tonne of CO2 emitted, the design of the near-zero emission well site allows for the avoidance of $1.2 MM to $1.5 MM USD in annual taxation.

d. Compression Facility Emissions Typical compressor drivers in remote areas are natural gas driven motors direct coupled to the

compressor. Technology surrounding low-NOx emitting engines allows companies to reduce some components of air emissions but the overall carbon dioxide produced by the engines still remains.

The ability to mitigate these emissions is not as ubiquitous as with the well sites but there are

strategies that can be employed to minimize emissions associated with compressor drivers. The most common (and that employed in the BP’s Noel Project) is to employ electric motor drivers on the compression trains. The availability of this solution though is dependent on the ability to provide large quantities of electric power to the site. In remote locations with no access to utility providers, this option is not attractive as it would require large-scale generators be installed. In areas where access to utility power exists, the adoption of electric motors is a valid alternative to reduce air emissions associated with the project. In addition to reduced carbon dioxide emissions, electric motor drives have enhanced availability when compared to natural gas engine alternatives. Industry data suggests a Mean Time Between Failure (MTBF) for electric motors of 15,529 hours compared to a MTBF of 1,998 hours for natural gas engines. After inclusion of preventative maintenance work downtime, this translates to an availability of 99.37% for electric motors versus 98.17% for natural gas engines. For the Noel Project, the additional availability translates to over 500 mmscf of additional sales gas each year, with a value of $2 MM USD.

In response to management challenge to reduce air emissions to the greatest extent possible, the

Noel project team chose to employ electric motor / variable frequency drive combinations as the drivers for the natural gas compressors. 16,000 hp of total compressor power will be supplied by 8 - 2000 hp electric motors. In order to enable this design to occur, the project is also constructing 70 km of 138 kV electric transmission line to power the facilities. There is a definite trade off between additional surface disturbances with a new transmission line versus air emission reductions. Specific to Noel, 358 hectares of forested area will be cleared for the transmission line but CO2 emissions are reduced by 69 kt / year. In order to assist in the decision regarding type of compressor drivers, the project invited the Pembina Institute to review the two options (natural gas drivers and electric motor drivers) and evaluate the costs / benefits for each. The Pembina Institute describe themselves as “promoting environmental, social, and economic sustainability in the public interest by developing practical solutions for communities, individuals, governments, and businesses.” The Institute reviewed the project and prepared a Life Cycle Value Assessment (LCVA) focusing on the “triple-bottom-line” impacts of the project, environmental, social, and economic. The conclusion of their study, when taking into account both the land cleared for the power line as well as the reduced air emissions, was that the “electric power case outperformed the natural gas engine base case on an overall triple-bottom-line basis”. The report also accounted for the indirect carbon dioxide produced by the electric utility in generation of the power. The grid fuel mix for the power utility is 84% hydro generation so the carbon dioxide associated with power generation is quite small. While adopting the electric motor drives in the project resulted in an added capital cost, ongoing operational expense is greatly reduced and the overall carbon dioxide emissions are reduced by over 85% at the individual compressor sites. Again, assuming the same carbon tax of $12 to $15 per tonne of CO2 emitted, the inclusion of the electric motors as compressor drives allows for the avoidance of $0.75 MM to $0.93 MM USD in annual taxation.

4 Summary/Conclusions/Perspectives

Emphasizing environmental reduction early in design allows for the opportunity to minimize impacts while, at the same time, reducing capital. The effort results not just in an environmentally sensitive project, but a well defined project set up for overall success Later in design, minimizing specific emissions at well sites and compressor stations does require the trade off of capital increases but this is offset with additional sales volumes and potential deferred taxes. Additionally, making specific choices around environmental impact reductions allows companies to achieve reputational benefits with local stakeholders, regulatory agencies, and government entities.

Focusing on minimizing environmental impacts within the Noel Major Project has led to a significant

savings when compared to a traditional gas development design. Spending time in conceptual design to challenge normal industry practices regarding well design allowed for the realization of facilities capital cost savings of $700 MM USD while at the same time reducing the project’s overall footprint by 8,658,000 m² of forested land.

Further efforts in detailed design to reduce air emissions allowed for an 85% reduction (when

compared to a conventional development), resulting in emission savings in excess of 180 kT of CO2e per year (once all wells are drilled). As the project is regulated by the Province of British Columbia, who have initiated a carbon tax, this reduction in emissions also provides relief from approximately $2 MM USD / year from carbon tax savings.

Figure 3 : Noel Project Carbon Footprint

Carbon Footprint (Ktpa, plateau year)

204

24

111

69

0

50

100

150

200

250

Convntnl Devlpmnt "zero" w ellsites Hydro Pow er Noel MP