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Orphan Wells in Alberta
Orphan wells are non-producing or inactive well assets left behind by bankrupt oil and gas producers without proper plugging or reclamation. The Orphan Well Association (OWA) is an industry funded consortium responsible for plugging orphan wells in Alberta. The current orphan fund levy, as mandated by the Alberta Energy Regulator (AER), is $45 million annually. As of April 1st 2018, there are 2888 orphan wells to be plugged. The number of wells which have been plugged but not remedied is 1062. However, the number of orphan wells to be abandoned is expected to grow by another 3000 with the recent bankruptcy of Sequoia Energy. The recent increase of the orphan well inventory pushed the Government of Alberta to provide a $235 million interest-free loan.

Classification of Oil and Gas Wells in Alberta
The Canadian Association of Petroleum Producers (CAPP) and Orphan Well Association (OWA) classifies oil and gas wells in the following categories.


 * Active: A well that is currently producing oil or natural gas.
 * Inactive: A well that has not produced oil or natural gas in 12 months.
 * Orphan: A well that no longer has an identifiable owner.
 * Abandoned: A well site that is permanently dismantled (plugged, cut and capped) and left in a safe and secure condition.
 * Reclaimed: A well site remediated and reclaimed to its original state before drilling.

Environmental Impacts of Orphan Wells
Gas contamination from both active and orphaned wells, particularly hydrogen sulfide and methane, is increasingly attracting attention from Alberta government and the public. In addition to fugitive gas emissions, shallow aquifers can also be contaminated by gas, causing very serious issues. Davies indicated that groundwater contamination can be caused by casing leaks (i.e. integrity failures), of which orphaned wells are susceptible. However, because orphaned well-induced groundwater contamination is not reported annually, statistical data is not available for now. In comparison, gas emissions are more easily monitored and tracked by operators. Despite the lack of groundwater contamination data, gas emission data collected by Alberta Energy Regulator (AER) from oil and gas industry may potentially reflect areas of groundwater contamination.

Surface Casing Vent Flow (SCVF) and Gas Migration (GM) are two commonly recognized gas contamination mechanisms. SCVF is defined as the flow of gas and/or liquid along the surface casing/casing annulus. GM is defined as a flow of gas that is detectable at the outer surface of the outermost casing string usually occurring at very shallow reservoir layers. According to recent statistics from the Alberta Energy Regulator (AER), a total of 617 billion m3 of methane was released into atmosphere through venting (GM and SCVF) and flaring in Alberta during 2016, which has been constantly decreasing since 2012. Among the total emitted gas, 81 ⁣⁣⁣⁣million m3 originated from 9,972 unrepaired wells by GM and SCVF. Historically, there are 18,829 repaired and unrepaired wells reported with SCVF, GM, or both in Alberta, with 7.0% of them being inactive (9,530 wells suspended and orphaned). Wells with reported gas migration issues within Alberta are shown by Bachu in 2017. It should be noted that most of the thermal wells are orphaned oil/gas wells. Bachu concluded that gas migration mainly occurs within the central-northeastern part of the province, focusing around the Edmonton, Cold Lake, and Lloydminster areas. This observation is in agreement with the total gas flaring and venting conditions reported by the Alberta Energy Regulator (AER).

According to recent studies provided by Hardie & Lewis (2015) and Bachu (2017), the primary factors that should be considered in the evaluation of gas emissions from oil and gas wells are: cementing, drilling orientation, geological conditions, well age, and reservoir depth.

Legal Constraints of Orphan Well Policies
Traditionally, extraction of natural resources and oil & gas belongs to the provincial regulation. Under normal circumstances, well abandonment and environmental policies are regulated by the AER.

Oil and Gas Conservation Act (OGCA) is the provincial statute or law dealing with licensing, producing, and managing aspects of all oil and gas assets in Alberta. Under section 18(1), the regulator holds rights to set conditions for approving drilling licenses. Sections 24(1) and 24(2) states that the regulator may set directives and rules to allow or deny asset transfers. It can deny asset sales or transfers if all the environmental requirements or liabilities are not resolved.

However, since orphan well cases deal with bankruptcy law, they are also subject to Bankruptcy and Insolvency Act (BIA), which is a federal jurisdiction. Since both the OGCA and BIA are at play, there is a significant jurisdictional issue, in terms of which of two laws should be valid.

The BIA states the rights of bankruptcy trustees. Under section 14.06, bankruptcy trustees may renounce assets and responsibility related to bankrupt producers. Bankruptcy trustees can use that clause to dispose of any rights and responsibility related to problematic assets. Due to the federal paramountcy, the BIA takes precedence over the OGCA. The application of the BIA effectively nullifies the provincial jurisdiction of orphan well policies.

The Redwater case is an example of how the conflict of those two jurisdiction come into play. The case is currently under review by the Supreme Court of Canada. Redwater Energy is a bankrupt Alberta based oil & gas company under the receivership. As a result of the growing number of orphan wells, the AER has forced bankruptcy trustees to pay for the cleanup costs before allowing asset/license sales or transfers. The current lawsuit was triggered by the bankruptcy trustee, Grant Thornton (GT), refusing to comply with the AER’s order for the environmental cleanup. Instead of complying with the order, GT wanted to sell Redwater’s asset and compensate its creditors. GT won the case in both the Alberta Court of Queen’s Bench and Alberta Court of Appeal. Due to the ruling, the AER cannot use the proceeds of bankrupt companies assets to pay for plugging orphan wells.

Economic Costs of Orphan Wells
At the current level of the orphan well inventory, the cost of well abandonment and reclamation is expected to be around $611 million. This is based on the estimation from the OWA's annual report. The cost of abandonment and remediation per well can be estimated from reviewing the OWA’s annual report; those costs are estimated to be $61,000 and $20,000 per well respectively.

However, this estimate of $611 million does not include potential orphan wells. In this context, potential candidates include wells owned by financially insolvent firms and nearly insolvent firms. The recent CD Howe report estimates that the social cost of orphan wells, including the one incurred by financially insolvent firms, can be upwards of $8.6 billion.

Responses
The new policy framework must consider the following stakeholders: small and large oil & gas producers, indigenous communities and landowners, and taxpayers.

The first option is reforming the orphan fund levy. The newly proposed levy structure takes the cyclicality of the industry into account. The energy industry faces recession every 7-10 years. By averaging inflation-adjusted orphan well abandonment expenses over the previous 10 years, OWA can raise enough revenue for the whole energy industry cycle. During the normal period of expansion, OWA accumulates reserves by collecting excess levy; the accumulated reserves are drawn during industry recession.

The second option is restricting the allowed time of inactivity. Less not abandoned inactive wells imply less orphan wells going down the road. Unlike the current system that gives producers flexibility, the forced abandonment will effectively reduce the number of orphan and inactive wells. North Dakota’s one-year closure rule is an example, which mandates producers to abandon inactive wells within one year of the last production. As a result of the policy, only one orphan well was abandoned by North Dakota Energy Regulator in 2016.

The third option is the mandated blanket bond. Under this option, producers are required to submit a company named bond to AER. That bond acts as a claim for well abandonment expenses. Before issuing drilling licenses, AER calculates expected expenses from well abandonment and reclamation. Also, the regulator assesses producers’ credit rating and financial debt. These metrics are used to determine their ability to pay for future expenses. Base on the expected expenses and financial health, the AER can determine the value of the bond to be submitted. This bond entails a condition, which names the AER as the first claimant of the company named assets in case of bankruptcy. The bond would be returned to the producer after wells are abandoned. If the producer cannot submit a bond due to its complex asset structures, it can submit a letter of credit from its designated bank. In case of the bankruptcy, the bank is responsible for environmental liabilities.

Regardless of options, the most likely solution for existing orphan wells is supplying additional funds for the OWA’s activity. That means giving additional government grants or indefinite to the OWA. There is a limitation of imposing new requirement for existing wells or drilling licenses. Given the magnitude of the expense required ($611 million), the private sector funded solutions for existing orphan wells are not feasible. There’s a case to be made for the public fund, since the government is the owner of resources, and environmental benefits of accelerated well abandonment is significant.

Potential Geothermal Conversion of Orphan Wells in Alberta
After oil wells become depleted, their depth and size make them good candidates for extraction of geothermal energy. The prospect of geothermal conversion of depleted wells is attractive for several reasons including potential recovery of abandonment costs, reduced consumption of non-renewable energy, and elimination of geothermal drilling costs (representing a significant component in geothermal projects). Several studies propose the conversion of existing wells into double pipe heat exchangers through the installation of an insulated pipe inside the well for fluid circulation.

The economics of this alternative requires further analysis, since geothermal systems tend to require a significant capital cost posing a significant risk for investors. Logistical issues such as proximity to potential customers would also be a significant factor affecting the feasibility of geothermal conversion.

Across the province, a general northwestern trend of increasing geothermal gradient is commonly recognized with geothermal gradients ranging between 10°C/km and 55°C/km. The controlling factors for this broad geothermal range in Alberta are poorly understood. Two main reasons have been proposed up to date to explain the observed patterns.
 * 1) The flow of formation waters is the main controlling factor of the geothermal field, where low geothermal gradient areas coincide with water recharge areas (major upland areas) and high geothermal gradient with discharge areas (major lowland areas).
 * 2) The differences in lithosphere thickness is responsible for the geothermal gradient distribution in Alberta since conduction is the main mechanism of transporting terrestrial heat from the basement to the surface.

The bottom hole temperatures (BHT) of wells within reasonable proximity to Albertan communities are, at best, sufficient for heating. Communities on the western side of Alberta are more likely to benefit from geothermal conversion for direct heat purposes. Previous projects in the United States have shown that temperatures around 80°C are feasible for direct heating of institutions and district heating. Another study also reported the use of a low-temperature geothermal well in China for heating within its proximity.

There was a recent push by the US Department of Energy to investigate the feasibility of Deep Direct-Use (DDU) of low temperature geothermal resources. Future studies originating from this program may help provide a better understanding of the costs and technologies needed to convert oil wells for geothermal energy and reduce the financial risk that geothermal technology may present.