Water Conservation, Efficiency and Productivity Plan Progress Report Upstream Oil and Gas Sector

Transcription

1 Guide Water Conservation, Efficiency and Productivity Plan Progress Report Upstream Oil and Gas Sector January

2 The Canadian Association of Petroleum Producers (CAPP) represents companies, large and small, that explore for, develop and produce natural gas and crude oil throughout Canada. CAPP s member companies produce about 90 per cent of Canada s natural gas and crude oil. CAPP's associate members provide a wide range of services that support the upstream crude oil and natural gas industry. Together CAPP's members and associate members are an important part of a national industry with revenues from oil and natural gas production of about $120 billion a year. CAPP s mission, on behalf of the Canadian upstream oil and gas industry, is to advocate for and enable economic competitiveness and safe, environmentally and socially responsible performance. DISCLAIMER This publication was prepared for the Canadian Association of Petroleum Producers (CAPP) by Golder Associates Ltd. (Golder). While it is believed that the information contained herein is reliable under the conditions and subject to the limitations set out, CAPP and Golder do not guarantee its accuracy. The use of this report or any information contained will be at the user s sole risk, regardless of any fault or negligence of Golder, CAPP or its co-funders. 2100, Avenue S.W. Calgary, Alberta Canada T2P 3N9 Tel Fax , 275 Slater Street Ottawa, Ontario Canada K1P 5H9 Tel Fax , 235 Water Street St. John s, Newfoundland and Labrador Canada A1C 1B6 Tel Fax , 1321 Blanshard Street Victoria, British Columbia Canada V8W 0B5 Tel Fax January 2016 Water CEP Progress Report - Upstream Oil and Gas Sector Page i

3 Overview This document is written to satisfy the request of the Alberta Water Council for a progress report that describes and evaluates the upstream oil and gas sector s success in meeting the objectives and targets described in its Water Conservation, Efficiency and Productivity (CEP) Plan (2011). The sector s CEP performance measure was non-saline water use productivity; i.e., the volume of non-saline water used to produce each unit of oil or bitumen. Water use statistics are provided to describe the improvements in non-saline water use productivity made by the following industry sub-sectors: oil sands mining, oil sands in situ, conventional oil, well drilling and gas plants. Statistics are not yet available for shale gas, tight gas and tight oil water use. In each of the sub-sectors, water productivity has surpassed the Water for Life strategy s provincial target of a 30% improvement from 2005 levels by The report discusses the level of adoption, challenges and successes of each of the 21 CEP opportunities identified in the CEP plan developed in These CEP opportunities cover a range of initiatives, including improved efficiencies in non-saline water use due to technological innovations, and substitution of non-saline water sources with alternatives such as municipal effluent, industrial effluent, saline groundwater, produced water and flowback. The document also describes how the CEP plan has been implemented, the concurrent environmental or social benefits as well as environmental tradeoffs of CEP efforts, and how the plan relates to other government and sector water-related initiatives. 1 Sector statistics are provided for a slightly different timeframe, which compare averaged non-saline water use productivity during a baseline period of against 2014 (the most recently available year) January 2016 Water CEP Progress Report - Upstream Oil and Gas Sector Page ii

4 Contents Contents... iii 1 Acknowledgements Introduction Report Objective About the Alberta Oil and Gas Sector Report Scope and Contents Non-saline Water Use Statistics Introduction Data Sources Oil and Bitumen Production Gas Production Total Sector Water Use Oil Sands Mining Water Use Total Water Use - Mining Non-Saline Water Use Productivity - Mining Oil Sands In Situ Water Use Total Water Use In Situ Non-Saline Water Use Productivity In Situ Conventional Oil Water Use Total Water Use Conventional Oil Non-Saline Water Use Productivity Conventional Oil Well Drilling Water Use Conventional Natural Gas Plants Water Use Summary Water Conservation, Efficiency and Productivity Opportunities and Implementation Introduction Review of Opportunities Plan Implementation and Environmental Performance January 2016 Water CEP Progress Report - Upstream Oil and Gas Sector Page iii

5 4.3.1 Summary of Extent to Which Opportunities Have Been Implemented Development of Company-Specific CEP Plans by Sector Members Interactions with Stakeholders on Sector Plan Implementation and Progress Improved Health of Aquatic Ecosystems Contribution of CEP Plan Implementation to Water for Life Strategy Goals and Water-Related Environmental Impacts Integration with Government of Alberta Initiatives and Regulations And Other Water-Related Sector initiatives Suggested Adjustments to the Sector Plan Summary References Figures Figure 3-1: Historic Oil and Bitumen Production (2000 to 2014)... 5 Figure 3-2: Historic Conventional Gas Production (2000 to 2014)... 6 Figure 3-3: Total Non-Saline Water Use for Overall Sector (2002 to 2014)... 7 Figure 3-4: Non-Saline Water Use Productivity for Overall Sector (2002 to 2014)... 7 Figure 3-5: Oil Sands Mining Water Use (2000 to 2014)... 9 Figure 3-6: Oil Sands Mining Non-Saline Water Use Productivity (2000 to 2014) Figure 3-7: Oil Sands In Situ Water Use (2002 to 2014) Figure 3-8: Oil Sands In Situ Non-Saline Water Use Productivity (2002 to 2014) Figure 3-9: Conventional Oil Water Use (2000 to 2014) Figure 3-10: Conventional Oil Non-Saline Water Use Productivity (2000 to 2014) Figure 3-11: Well Drilling Water Use (2000 to 2014) Figure 3-12: Gas Plants Water Use (2005 to 2014) Tables Table 3-1: Data Sources... 4 Table 3-2: Baseline, Projected and Actual Non-Saline Water Use Productivity for Selected Sub- Sectors... 8 Table 3-3: Overall Sector Comparison in 2014 Relative to Baseline ( ) Table 4-1: Summary of Opportunities January 2016 Water CEP Progress Report - Upstream Oil and Gas Sector Page iv

6 1 Acknowledgements This report was compiled by Golder Associates Ltd. (Golder) with support from Geowa Information Technologies Ltd., in collaboration with the Canadian Association of Petroleum Producers (CAPP). Golder wishes to thank the following individuals, organization and companies that contributed technical expertise and guidance in the direction and review of this document. Tara Payment Nancy O Brien Scott Hillier Lindsay Stephens Sharla Howard James Guthrie Canadian Association of Petroleum Producers Cenovus Energy ConocoPhillips Canada Encana Corporation Husky Energy Imperial January 2016 Water CEP Progress Report - Upstream Oil and Gas Sector Page 1

7 2 Introduction 2.1 Report Objective The purpose of this document is to satisfy the request of the Alberta Water Council (AWC, described below) for a report describing the upstream oil and gas sector s progress in improving non-saline water use productivity in Alberta. The Government of Alberta, as part of its Water for Life: Alberta s Strategy for Sustainability, has articulated the following target for improvements in water use in the province: Demonstration in all sectors of best management practices, ensuring overall efficiency and productivity of water in Alberta improves by 30% from 2005 levels by This will occur when either demand for water is reduced or water use efficiency and productivity are increased. The AWC is a multi-stakeholder partnership with members from governments, industry and non-government organizations, and its primary task is to monitor and steward implementation of the Water for Life strategy. The AWC requested the development of publicly-available Water Conservation, Efficiency and Productivity (CEP) plans from each of the seven major water-using sectors in the province. To fulfill this request, Golder prepared the Water CEP Plan for the Upstream Oil and Gas Sector on behalf CAPP and the Oil Sands Developers Group (OSDG) in In March 2013, the AWC recommended that all seven priority sectors prepare sector progress reports based on actual water use data as of December 31, 2014, and submit these reports at the AWC s final meeting in October About the Alberta Oil and Gas Sector Alberta is Canada s largest oil and natural gas producer and is home to vast deposits of oil sands. The following are some quick facts about the sector: $9.1 billion - in payments industry made for the use of Alberta's oil and gas resources in fiscal 2014/15, 18 per cent of total government revenue. Note: This figure does not include corporate, personal or municipal taxes. $105 billion - in contributions to the provincial government over the last ten years. $26.7 billion - in industry spending on exploration and development in conventional areas in $33.9 billion - in investment spending in the oil sands in billion - cubic feet per day of natural gas produced in ,000 - barrels per day of conventional oil produced in 2014, an increase of 7,400 barrels per day from million - barrels per day produced from the oil sands in 2014, an increase of over 220,000 barrels per day from million - barrels per day of oil upgraded. January 2016 Water CEP Progress Report - Upstream Oil and Gas Sector Page 2

8 2.3 Report Scope and Contents This report addresses water use in the following oil and gas sub-sectors: oil sands mining bitumen production; oil sands in situ bitumen production; conventional oil production; well drilling; and gas plants. Shale gas, tight gas and tight oil water use was not included in the 2011 CEP plan. Operators are required to report all water used for hydraulic fracturing operations to the Alberta Energy Regulator (AER) under Directive 059, effective December 31, However, this data is not yet available from the AER and thus is not included in this progress report. The recommended contents of the progress reports are provided in the AWC report entitled Sector Planning for Water Conservation, Efficiency and Productivity (March 2013). January 2016 Water CEP Progress Report - Upstream Oil and Gas Sector Page 3

9 3 Non-saline Water Use Statistics 3.1 Introduction This section describes how water use in Alberta s upstream oil and gas sector has changed since the early 2000s. Water use statistics are presented both in terms of: total volume of water used per year; and water use productivity m 3 of non-saline water required per m 3 of bitumen or oil produced. For context, statistics on the volume of production are also included. Graphs are included to show the year-to-year changes in water use, and data tables are provided to compare water use in 2014 to the baseline period; i.e., the average water use over the years 2002 to For this progress report, water use and production data was compared to the baseline conditions outlined in the 2011 CEP Plan. In the CEP plan, forecasts from 2010 to 2015 were made to predict future non-saline water use productivity based on projected production levels and associated water demand. These forecasts are included for comparison, but are not the focus of this section. Details on how the water demand forecasts were originally developed can be found in Section 3.1 of the 2011 CEP Plan. There have been improvements in non-saline water productivity relative to the baseline period in each of the upstream oil and gas sub-sectors. Section 3 quantifies these changes at the sub-sector level using non-saline water use statistics, but does not discuss or quantify the factors influencing these improvements. Section 4 discusses the CEP opportunities (i.e., the efforts influencing these improvements) and qualitatively describes which were considered to be the most important. There has been no attempt to quantify the impact of these individual Opportunities, which is beyond the scope of this document. 3.2 Data Sources All information used to prepare this report is publicly available. Key data sources are listed in Table 3-1, below. Table 3-1: Data Sources Data type Oil and bitumen production and water use (2000 to 2014) Gas production (2000 to 2014) Mined bitumen production and water use (2000 to 2014) Source Petrinex (formally known as the Petroleum Registry of Alberta) Petrinex, confirmed with marketable gas volumes reported in the Alberta Energy Regulator s (AER) ST98: Alberta's Energy Reserves & Supply/Demand Outlook. AER ST39: Alberta Mineable Oil Sands Plant Statistics January 2016 Water CEP Progress Report - Upstream Oil and Gas Sector Page 4

10 Oil and Bitumen Production (kbpd) Data type Oil sands mining production and water use (from 2000 to 2014) Oil sands in situ production and water use (2002 to 2014) Conventional oil production and water use (2000 to 2014) Gas plant water use (2005 to 2013) Well drilling water use (2000 to 2014) Source Alberta Environment and Parks (AEP) Water Use Reporting System (WURS) database, verified against AEP s Oil Sands Information Portal website Petrinex AEP database queries of the Environment Management System (EMS). AEP database queries of the EMS. The major gas plants at Empress and around Fort Saskatchewan are not included. The upgraders at Scotford and Lloydminster are not included, although water use by upgraders at oil sands mines is included with usage by the mines. There is no available water use data prior to Information on number of wells drilled annually taken from AER ST98: Alberta's Energy Reserves & Supply/Demand Outlook. Information on water use per well drilled was based on typical industry rates (assumed to be constant over 2000 to 2014 period). 3.3 Oil and Bitumen Production Historic oil and bitumen production in Alberta is shown in Figure 3-1. Conventional oil production decreased slightly between the baseline period (2002 to 2004) and 2014, while both in situ and mining oil sands production has increased substantially. Figure 3-1: Historic Oil and Bitumen Production (2000 to 2014) Conventional Oil Oil Sands In-Situ Oil Sands Mining Note: 1. Total historical in situ production includes primary, thermal, and experimental operations. 2. Conventional oil includes light, medium, and heavy production. January 2016 Water CEP Progress Report - Upstream Oil and Gas Sector Page 5

11 3.4 Gas Production Historic conventional marketable gas production in Alberta is shown in Figure 3-2. The majority of gas production is from conventional sources. Gas production decreased roughly 25% between the baseline period (2002 to 2004) and Source: AER publication ST Figure 3-2: Historic Conventional Gas Production (2000 to 2014) Gas Production (x10 9 m 3 ) Total Sector Water Use Total upstream oil and gas sector non-saline water use (excluding shale gas, tight gas and tight oil production) is shown in Figure 3-3. Overall, oil equivalent (bitumen plus oil) production increased by 82% between the baseline period ( ) and Total non-saline water use over the same period increased by 10% to approximately 200 Mm3. Total non-saline water use in 2014 was also lower than predicted in the 2011 CEP plan, despite higher than projected oil equivalent production. The overall water use productivity, or the volume of non-saline water used per volume of hydrocarbon produced, for the sector was approximately 1.2 m 3 water use/m 3 oil equivalent in This represents an improvement of 40% from baseline conditions and was largely driven by the improvements within oil sands mining operations. Water use in this sub-sector accounts for roughly 80% of sector s non-saline water use. The historical overall water use productivity for the sector is shown in Figure 3-4. A summary of water use by each sub-sector is provided in Table 3-2. Details of each subsector s use are discussed in the remainder of this section. January 2016 Water CEP Progress Report - Upstream Oil and Gas Sector Page 6

12 Figure 3-3: Total Non-Saline Water Use for Overall Sector (2002 to 2014) Non-Saline Water Use Unit Rate (m 3 non-saline water used:m 3 bitumen/oil produced) 250 Industry Non-Saline Water Use (Mm 3 ) Oil and Bitumen Production (Mm 3 ) Gas Plants (All Sources) Conventional Oil (Non-Saline Sources) Oil Sands Mining (Other Non-Saline Sources) Well Drilling and Completions (All Sources) Oil Sands In-Situ (Non-Saline Sources) Oil Sands Mining (Athabasca River Water) Bitumen and Oil Production Figure 3-4: Non-Saline Water Use Productivity for Overall Sector (2002 to 2014) Actual Overall Sector Productivity of Non-Saline Sources (excluding gas,well drilling and completions) Note: Dotted line is original projection from 2011 CEP Plan (CAPP, 2011) January 2016 Water CEP Progress Report - Upstream Oil and Gas Sector Page 7

13 Table 3-2: Baseline, Projected and Actual Non-Saline Water Use Productivity for Selected Sub-Sectors Baseline (2002 to 2004) 2014 Activity Production (Mm 3 OE) Non- Saline Water Use (Mm 3 ) Productivity (m 3 water:m 3 oil/bitumen) Production (Mm 3 OE) Non- Saline Water Use (Mm 3 ) Productivity (m 3 water:m 3 oil/bitumen) Projected (2015) Productivity Improvement (%) Actual Productivity Improvement (%) Oil Sands Mining (Athabasca River water only) % 48% Oil Sands Mining % 31% Oil Sands In Situ % 58% Conventional Oil % 46% Total % 40% January 2016 Water CEP Progress Report - Upstream Oil and Gas Sector Page 8

14 Oil Sands Mining Non-Saline Water Use (Mm 3 ) Bitumen Production (Mm 3 ) 3.6 Oil Sands Mining Water Use Total Water Use - Mining Water for oil sands mining is drawn from three sources: Withdrawals from the Athabasca River Water collected from surface runoff on the mine site; and Water collection from groundwater flowing to the mine pit and mine depressurization. Bitumen production from oil sands mines increased by 68% between the baseline period and Over the same period, non-saline water use productivity improved (see Section 4 for the factors involved in this improvement) such that total non-saline water use for the oil sands mining sub-sector increased by only 16% to 168 Mm 3 The majority of water used for mining was drawn from the Athabasca River, but the proportion of use by each source has changed over the last decade. Historical total water use is shown on Figure 3-5. Figure 3-5: Oil Sands Mining Water Use (2000 to 2014) Non-Saline Groundwater Mine Site Surface Runoff Athabasca River Withdrawal Bitumen Production The total amount of water extracted from the Athabasca River has remained fairly consistent over the last decade (annual average of roughly 100 Mm 3 ). However, the proportion of total oil sands mining non-saline water withdrawals from the Athabasca River decreased from 79% during the baseline conditions to 59% in January 2016 Water CEP Progress Report - Upstream Oil and Gas Sector Page 9

15 The total amount of non-saline water available as surface runoff is variable due to climate conditions. However, the proportion of non-saline water from surface runoff has increased from 20% during the baseline conditions to 34% in Non-saline groundwater use has increased over the past decade. The proportion of total oil sands mining non-saline water withdrawals from groundwater has increased from 1% during the baseline period to about 6% in 2014, due to the requirement to manage the increased volume of mine depressurization water Non-Saline Water Use Productivity - Mining Figure 3-6 shows that non-saline water use productivity for all non-saline sources has improved by 31% relative to baseline conditions, similar to projections in the 2011 CEP plan. Figure 3-6: Oil Sands Mining Non-Saline Water Use Productivity (2000 to 2014) 7.0 All Non-Saline Water Sources Non-Saline Water Use Unit Rate (m 3 water used:m 3 bitumen produced) Athabasca River Withdrawals All Non-Saline Water Sources (excluding Athabasca River Withdrawals) Note: Dotted lines are projections from 2011 CEP Plan (CAPP, 2011) Oil Sands In Situ Water Use Total Water Use In Situ Total non-saline water use for the oil sands in situ sub-sector increased by 56% to 19.5 Mm 3 between the baseline period and Over the same period, in situ bitumen production increased by 269%. Non-saline water use is lower than was projected in the CEP plan although actual oil sands in situ bitumen production is substantially higher than original 2011 forecasts. The reduction in non-saline water use is considered to be attributable primarily to an increase in saline groundwater use and increased recycling. Figure 3-7 shows the historical total water use (including saline groundwater). Saline groundwater use for in situ operations has increased over the decade to about 20 Mm 3 January 2016 Water CEP Progress Report - Upstream Oil and Gas Sector Page 10

16 and represented 51% of the total amount of water used for in situ in 2014 compared to 23% in the baseline period. Figure 3-7: Oil Sands In Situ Water Use (2002 to 2014) 100 Saline Groundwater 90 Non-Saline Groundwater Oil Sands In-Situ Water Use (Mm 3 ) Surface Water Bitumen Production Bitumen Production (Mm 3 ) Non-Saline Water Use Productivity In Situ Oil sands in situ non-saline water use productivity has improved by 58% relative to baseline conditions. Improvements in water use productivity were greater than projected in the 2011 CEP plan. Historical water use productivity rates are shown on Figure 3-8. January 2016 Water CEP Progress Report - Upstream Oil and Gas Sector Page 11

17 Non-Saline Water Use Unit Rate (m 3 water used:m 3 bitumen produced) Figure 3-8: Oil Sands In Situ Non-Saline Water Use Productivity (2002 to 2014) All Non-Saline Water Sources for Oil Sands In-Situ Sub-Sector Note: Dotted lines are projection from 2011 CEP Plan (CAPP, 2011) Conventional Oil Water Use Total Water Use Conventional Oil Total non-saline water use for the conventional oil sub-sector decreased by 50% to about 13 Mm 3 between the baseline period and Over the same period, oil production decreased by 7%. Non-saline water use is similar to projections in the CEP plan although actual conventional oil production is higher than original forecasts. There was a steady decline in conventional production until it began to increase again in Historical total water use (including saline groundwater) is shown in Figure 3-9. Saline groundwater use for conventional oil operations has remained relatively constant over the last decade (annual average of roughly 9 Mm 3 ). However, the proportion of saline groundwater has increased from 25% to approximately 38% in January 2016 Water CEP Progress Report - Upstream Oil and Gas Sector Page 12

18 Figure 3-9: Conventional Oil Water Use (2000 to 2014) Non-Saline Water Use Productivity Conventional Oil Non-saline water use productivity for conventional oil production has improved by 46% relative to baseline conditions. Improvements in water use productivity were greater than the 15% improvement projected in the 2011 CEP plan. Historical water use productivity for conventional oil operations is shown in Figure Figure 3-10: Conventional Oil Non-Saline Water Use Productivity (2000 to 2014) January 2016 Water CEP Progress Report - Upstream Oil and Gas Sector Page 13

19 3.9 Well Drilling Water Use The water use forecast in the CEP plan for well drilling does not distinguish between non-saline and saline water because several water sources were used to compile the forecast. Although some of the water used for deep wells may be saline groundwater, all of the estimated water use was assumed to be from non-saline sources. Water use from drilled wells was based on a range of 400 m 3 to 600 m 3 of water required per well (as outlined in CEP plan) due to the highly variable drilling depths and geological conditions across the province. Total water use for well drilling in 2014 was 4.1 Mm 3. The historical estimated water use is shown in Figure The overall estimated water use for well drilling is roughly 50% lower than originally projected, based on the number of wells drilled. Total water use from well drilling accounts for less than 2% of oil and gas sector total water usage. Figure 3-11: Well Drilling Water Use (2000 to 2014) Non-Saline Water Use (Mm 3 ) Water Use for Well Drilling and Completions (estimated) Number of Wells Drilled Number of Wells Drilled (thousands) Conventional Natural Gas Plants Water Use The production of conventional natural gas in Alberta has decreased over the past decade. Water use from 2005 to 2014 has remained fairly consistent (1% increase) at roughly 4.9 Mm 3. The total water use for natural gas only includes gas plants and does not include cavern washing operations or other mid-stream plants. Historical water use and natural gas production is shown in Figure Total non-saline water use from gas plants accounts for less than 3% of upstream oil and gas sector total water usage. January 2016 Water CEP Progress Report - Upstream Oil and Gas Sector Page 14

20 Figure 3-12: Gas Plants Water Use (2005 to 2014) 10 9 Reported Water Use Total Production (Conventional Gas) Total Reported Non-Saline Water Use (Mm 3 ) Natural Gas Production (x10 9 m 3 ) Summary Overall, the entire sector and each sub-sector has experienced non-saline water use productivity improvements (m 3 water used per m 3 of bitumen/oil produced) which exceed the Alberta target of 30% improvement in water use discussed in Section 2.1. The entire sector had a 10% increase of total non-saline water use which corresponded with an 82% increase in production. Improvements in non-saline water use productivity were equal to or higher than originally projected across all sub-sectors. Overall the entire sector had a water use productivity improvement of 40% in comparison to a projected 24% improvement. The greatest improvement in water use productivity (58%) occurred in the oil sands in situ sub-sector, despite a 269% increase in production. A comparison of the actual water use productivity improvement and the projected productivity improvement is shown in Table 3-2. A summary of the overall sector for production, water use, and water use productivity is shown in Table 3-3. January 2016 Water CEP Progress Report - Upstream Oil and Gas Sector Page 15

21 Table 3-3: Overall Sector Comparison in 2014 Relative to Baseline ( ) Sub-Sector Metric Oil Sands Mining Oil Sands In Situ Conventional Oil Well Drilling Natural Gas Plants Overall Sector1 Production +68% +269% -7% -51% - 26% +82% Total Non-Saline Water Use Non-Saline Water Use Productivity +16% +56% -50% -51% +1% +10% +31% +58% +46% 0%2 N/A2 40% Notes: 1. Does not include the water use from well drilling. 2. Water use productivity estimates were not estimated for natural gas plants since no data are available from baseline conditions. Water use productivity estimates for well drilling based on assumptions identical to those in the CEP plan. January 2016 Water CEP Progress Report - Upstream Oil and Gas Sector Page 16

22 4 Water Conservation, Efficiency and Productivity Opportunities and Implementation 4.1 Introduction Section 3 quantified the changes in water use for bitumen, oil and gas production from the early 2000s to the present. The following section describes the measures (called CEP opportunities) that have been implemented or are being considered for implementation that are responsible for the improvements in the non-saline water use productivity documented in the Section 3. Twenty-one opportunities for water conservation, efficiency or productivity were identified in the 2011 CEP plan. Storage-related opportunities to reduce the environmental impact of water use by minimizing withdrawals from rivers and lakes during low-flow periods were also included. Details of these opportunities can be found in the 2011 CEP plan. The following sections address the implementation of the CEP opportunities, their environmental advantages and disadvantages, and how the CEP integrates and supports other initiatives such as Alberta s Water for Life strategy. 4.2 Review of Opportunities A survey of CAPP-member oil and gas companies was conducted to evaluate the level of adoption, challenges and successes of the 21 CEP opportunities since the CEP plan was issued in Responses to the survey were received from 11 companies, which represent almost 50 per cent of Western Canadian Sedimentary Basin oil production. These companies are identified as survey respondents in the section below. The following section summarizes the survey responses for each opportunity. Although water use data was not available for shale gas, tight gas and tight oil, some of the opportunities discussed below apply to hydraulic fracturing. Opportunity 1: Redefine Water Quality Regulations to Prioritize Use of Low Quality Non-Saline Water There is an opportunity for the oil and gas sector to use water that is unsuitable for domestic or agricultural uses in the province (i.e., low-quality non-saline groundwater). This was discussed in multi-stakeholder workshops held by the Government of Alberta in 2014 to inform the drafting of the Water Conservation Policy for Upstream Oil and Gas (pending release). The impact of the Policy on related Directives and/or Guidelines will determine the magnitude of future high-quality non-saline water use reductions. Opportunity 2: Reuse Municipal Wastewater as Alternative to Diverting Additional Non-Saline Water Four Respondents indicated that they had used or are using treated municipal wastewater in their operations. The water is being put to a variety of uses, including drilling. Respondents noted that this resulted in a marked reduction in the need for high quality surface water, and also assisted in their social license to operate. However, several challenges were identified, including insufficient volumes of available treated effluent in some cases, negative social perceptions of using dirty water, water quality January 2016 Water CEP Progress Report - Upstream Oil and Gas Sector Page 17

23 compatibility, transportation issues for non-potable water and water regulation license issues. Some environmental tradeoffs include a reduction of return flows where wastewater was originally released, increased land disturbance due to piping and increased trucking where piping was not used. Given the relatively limited volume of treated wastewater that is both available and relatively close to oil and gas operators, the past and future impact of this Opportunity is considered low. Opportunity 3: Adopt Less Water-Intensive Tailings Management Technologies This Opportunity is currently being implemented by one Respondent and being evaluated by two other Respondents. Some mining companies are using less intensive water processes such as the cross flow filtration of tailings or the transitioning from whole tailing to non-segregating tailings. Companies are expecting non-saline water consumption to decrease by at least 10% and there is expected to be a lower dependence on water from tailings ponds (leading to smaller pond sizes). Energy and greenhouse gas (GHG) emissions have also been lowered since less water needs to be reheated for use in bitumen extraction. The water use impact of this Opportunity is rated as follows: Past Moderate; Future potential Unknown. Opportunity 4: Implement CO 2 Injection to Enhance Recovery as an Alternative to Water Injection This Opportunity is currently being investigated in Alberta by one Respondent. Respondents indicate that there are potential challenges due to the complexity of the operations, potential risks and uncertainties regarding leakages, and the potential cost for implementation. The impact to date of this Opportunity on sector water use in Alberta is negligible, and the future impact on water use is uncertain. Opportunity 5: Use Alternatives to Non-Saline Water for Drilling or Fracturing Fluids This Opportunity was among the more widely adopted, with eight Respondents indicating they have implemented it. Companies report using recycled flowback water and fluids, municipal treated effluent and saline water for well completions instead of using high quality non-saline water. Companies have proven that treated effluent has been successful although saline water sources require additional evaluation. Several challenges exist for this Opportunity including logistics and intensive capital investments, time to develop alternative sources of water, evaluation of environmental net effects and the creation of a business case. Some additional risks for the transmission and storage of saline water were also noted by Respondents. There was also some reservation against using waterless fracturing technology based on field performance. The water use impact of this Opportunity is rated as follows: Past Moderate; Future potential Moderate. January 2016 Water CEP Progress Report - Upstream Oil and Gas Sector Page 18

24 Opportunity 6: Use Saline Groundwater for Pressure Maintenance Three Respondents reported using saline groundwater for pressure maintenance for conventional oil operations. The success of this Opportunity is dependent on the availability of quality saline water sources and the compatibility of reservoirs. Some environment impacts were highlighted which may also limit the use of saline groundwater including the potential for additional land disturbance and risks of the transmission of saline water (i.e., spills or pipeline failures). This Opportunity is typically implemented where practical, but at a sector level its impact on water use is limited, and is therefore rated as follows: Past Low; Future potential Low. Opportunity 7: Update Equipment and Operating Procedures to Improve Water Efficiency This Opportunity has been widely adopted, with eight Respondents reporting having implemented it. Respondents document several practices such as laying pipelines instead of water trucks (which reduces environmental impacts other than water use), constructing flowback ponds, and upgrading equipment and facilities (e.g., pump gland seal water system, automatic backwashing strainer, hot lime softener, vapour recovery tank compressors, steam condensate capture, boilers in series, rifled tubes). These changes have resulted in many successes in addition to reducing non-saline water use, including: water security, reduction of trucking costs, competitive advantage and improved social license to operate. Some challenges and drawbacks include the potential increase to the project footprint and increased energy use in some cases which leads to higher GHG emissions. It was also noted by Respondents that there are often equipment failures or challenges that need to be resolved when first implementing new technologies or equipment. The water use impact of this Opportunity is rated as follows: Past High; Future potential High. Opportunity 8: Reuse Oil Sands Mining Wastewater Streams for In Situ Operations This opportunity is currently being implemented both within and between companies, where process-affected water from one company s mining operation is sent to supply either their own or a competitor s in situ operation. Respondents indicated the following potential challenges: Potentially high cost of infrastructure required, depending on pumping distance and volumes of water required; For inter-company water transfers, there are legal/contractual risks regarding the cost, reliability and quality of water delivered, timing risks (is the water available in sufficient quantities when needed), and the need to develop a costing model; Dependence of the in situ operation on a supply of water that must be adequate in terms of both quantity and quality January 2016 Water CEP Progress Report - Upstream Oil and Gas Sector Page 19

25 Limited supply of surplus water in tailings ponds (once legacy water in the tailings ponds is consumed, water supplied to the in situ operation must be provided by increased river withdrawals) Increased land disturbance and increased GHG emissions to pump effluent over long distances. The water use impact of this Opportunity is rated as follows: Past Low to Moderate; Future potential Low. Opportunity 9: Use Saline Water for In Situ Steam Generation In situ operators are using a mixture of saline and non-saline water in their operations. This Opportunity was reported in the CAPP survey as being in use by four Respondents and under evaluation by another company. A drawback to this Opportunity includes the need to treat the water prior to use; the extent of treatment is highly dependent on the level of salinity of the source water. Treatment creates a waste byproduct that must be disposed of. In addition, the practical challenges of sourcing and evaluating saline aquifers and the installation of saline source wells are significantly higher than nonsaline water source wells. Respondents also noted that this Opportunity increases GHG emissions and environmental risk due to treating and transporting saline water over long distances. The water use impact of this Opportunity is rated as follows: Past Low to Moderate; Future potential Low to Moderate. Opportunity 10: Implement Solvent Injection to Enhance Recovery of In Situ Bitumen This Opportunity was reported to be under investigation or in the pilot stage by five Respondents. Some examples of the Opportunity include the innovative use of lower temperature demulsifiers, cyclic solvent processes and use of butane, methane and diluent. If the pilot programs are successful it is expected that both non-saline water use and GHG emissions will be reduced. However, many Respondents identify that there are large capital and operating costs in addition to technical challenges, which limit the potential success of this Opportunity. The water use impact of this Opportunity is rated as follows: Past Negligible; Future potential Moderate (if pilots are successful) Opportunity 11: Recycle Produced Water Instead of Disposal or Release This opportunity is currently being implemented by six Respondents. One example of the Opportunity includes the processing of wet gas sent through separation equipment with the stripped water being reused in other operations. Respondents outline several benefits of this Opportunity: providing the social license to operate, lessened non-saline water extraction, and reduced trucking. Some challenges that were identified included increased costs and regulatory barriers. Respondents also noted this Opportunity increased GHG emissions and potentially costs if there are spills of recycled water. The water use impact of this Opportunity is rated as follows: Past High; Future potential Low to Moderate. January 2016 Water CEP Progress Report - Upstream Oil and Gas Sector Page 20

26 Opportunity 12: Implement In Situ Combustion to Enhance Recovery This Opportunity was reported to be currently under evaluation by three Respondents. Although this non-aqueous extraction method has proven potential in pilots, there are significant technical challenges that may limit the success of this Opportunity. Further evaluation is required. The water use impact of this Opportunity is rated as follows: Past Negligible (pilot); Future potential Unknown. Opportunity 13: Treat Flowback/Produced Water/Saline Water for Reuse or Release Instead of Disposal This Opportunity is being implemented by four Respondents for hydraulic fracturing, and for recycling and treating sweet flowback water for reuse by one Respondent. This Opportunity was proven to be successful when minimal water treatment was necessary and it was also shown to lessen non-saline water use. Several challenges to implementing this broader Opportunity were noted in the 2011 CEP plan, including the uncertainty of water forecasting of recycled sources, overall cost and lack of field testing results. Additional environmental and costs issues were noted: higher GHG emissions, higher potential costs due to potential spills and additional waste generation. The water use impact of this Opportunity is rated as follows: Past Low to Moderate; Future potential Low to Moderate Opportunity 14: Convert to Non-Water-Based Oil Sands Mining Extraction Methods This is currently being evaluated by two Respondents and early lab tests results indicate that non-aqueous extraction is possible and can be successful. However, many challenges exist to the future implementation of this Opportunity due to the cost and technical challenges of scaling up the lab results. The water use impact of this Opportunity is rated as follows: Past Negligible; Future potential Unknown. Opportunity 15: Reuse Produced Water Instead of Disposal or Release Five Respondents indicated that they had implemented this Opportunity. Some Respondents indicate that produced water is heavily used in the industry with some operations reusing up to 96% of produced water. Another Respondent indicated that all produced water is reused at their in situ operations. This has proven to be a very successful Opportunity implemented in Alberta. There are some challenges with regards to storage and transport requirements of the produced water in Alberta. Additional environmental impacts noted in the survey include additional waste generation from treatment processes and an increased risk of environmental impacts due to surface spills. This Opportunity has been exploited within companies in the past. It is possible that further reductions could be achieved by increased water transfers between companies where availability and location favours this. The water use impact of this Opportunity is rated as follows: Past Low; Future potential Moderate (if transfers between companies increase). January 2016 Water CEP Progress Report - Upstream Oil and Gas Sector Page 21

27 Opportunity 16: Use Evaporator Technology to Treat Blowdown at In Situ Operations As a treatment process for blowdown water alone, respondents noted this is a significant economic challenge. One Respondent is currently implementing this opportunity to treat produced water and makeup water at their facility, which as a primary water treatment process is significantly different than being implemented for treatment of blowdown water alone (as a separate process to an existing primary treatment process). The Respondent noted several successes: ease of operation, higher recycle rates, and additional flexibility to varying degrees of salinity. Respondents expressed concerns about reliability and challenges of the concentrated disposal stream in the blowdown-only evaporator treatment scenario, where the disposal stream is more likely to cause issues in disposal formations and can require additional treatment itself. Additional environmental impacts include higher electrical consumption leading to higher GHG emissions, but a smaller physical footprint in the cases where it also serves as primary water treatment otherwise it is an additional footprint to the primary water treatment process. The water use impact of this Opportunity is rated as follows: Past Low; Future potential Moderate. Opportunity 17: Reduce Evaporation from Ponds This Opportunity is not currently in use or being investigated by any Respondents. Given the relative low annual temperature in Alberta, evaporative losses for many operators is negligible relative to overall water consumption. The water use impact of this Opportunity is rated as follows: Past Negligible; Future potential Low to Negligible. Opportunity 18: Add Polymers to Waterfloods for Improved Productivity This Opportunity is being implemented by three Respondents at several locations across Alberta. Respondents indicate very positive results and some have seen an oil recovery factor increase. The higher efficiency in oil recovery has also resulted in less water injected and lower GHG emissions. Some challenges include the difficulty of treating produced fluids due to polymer returns. However, at a sector level, the impact of these changes on overall water use is considered relatively low. The water use impact of this Opportunity is rated as follows: Past Low; Future potential Low to Moderate. Opportunity 19: Store Water in Aquifers for Future Use Aquifer storage and recovery (ASR) is currently not being used or evaluated by any Respondents due to cost and technical challenges, although ASR has been used for other purposes in other jurisdictions. Like other storage options, ASR doesn t reduce water use, but is used to maximize withdrawals when river flows or lake water levels are high and minimize them when flows or levels are low, thereby lessening environmental impacts. January 2016 Water CEP Progress Report - Upstream Oil and Gas Sector Page 22

28 Past impacts on water use are nil. Given the current state of adoption and future impacts of this Opportunity on overall water use are likely negligible. Opportunity 20: Implement Surface Water Storage for Oil Sands Mining While this Opportunity was reported to have been implemented by only one Respondent, recent approvals for new oil sands developments have typically required the provision of one to three months of storage without withdrawals from the Athabasca River. Approvals also provided for the limiting of withdrawals from the river when low flow thresholds are reached. The company reports that water is currently being stored in an external tailings area for use in production when flows in the Athabasca are low. Since this Opportunity relates to storage rather than reduced non-saline water consumption, the water use impact of this Opportunity is rated as follows: Past Negligible; Future potential Negligible. Opportunity 21: Treat Water to Increase Recycling Rate from Tailings Ponds at Oil Sands Mines This is currently not being implemented by any Respondents. Challenges for implementation of active treatment include the costs and technical challenges such as the management and disposal of the waste stream from the treatment processes. The water use impact of this Opportunity is rated as follows: Past Low; Future potential Negligible to Low. January 2016 Water CEP Progress Report - Upstream Oil and Gas Sector Page 23

29 Table 4-1: Summary of Opportunities Opportunity Relevant Sub-Sector Level of Adoption Impact on Water Use Past Future Potential Key Learning 1. Redefine water quality regulations to prioritize use of lower quality non-saline water Waterflood 1 Conventional Oil Conventional Gas Oil Sands In Situ N/A N/A Unknown Regulations not yet updated. Impact on water use will depend on regulations. Waterflood 1 2. Reuse municipal wastewater instead of diverting additional water Conventional Oil Unconventional Gas Oil Sands In Situ Moderate Low Low Adopted by several Respondents. Measured at a sector level, volumes of available non-saline water is low in comparison to overall use. 3. Consider alternative, less water-intensive oil sands tailings technologies and management techniques Oil Sands Mining Moderate Moderate to High Unknown The future impact of this Opportunity will depend on technological advances. 4. Implement CO 2 injection to enhance recovery instead of injected water Waterflood 1 Pilot Negligible Unknown At evaluation stage 5. Consider alternatives to non-saline water for drilling or fracturing fluids Waterflood 1 Conventional Oil Unconventional Gas Moderate Moderate Moderate Play-specific and depends on available alternatives and overall environmental net effects. 6. Use saline groundwater for pressure maintenance Waterflood 1 Conventional Oil High Low Low Opportunity being maximized by industry. Function of availability of source. 7. Update equipment and equipment operating procedure for improved water efficiency Waterflood 1 Conventional Oil Unconventional Gas Oil Sands In Situ Oil Sands Mining High High High Widely adopted resulting in reductions in water use. January 2016 Water CEP Progress Report - Upstream Oil and Gas Sector Page 24

30 Opportunity Relevant Sub-Sector Level of Adoption Impact on Water Use Past Future Potential Key Learning 8. Reuse oil sands mining wastewater streams for in situ makeup water, such as blowdown from upgraders or tailings pond water Oil Sands In Situ Oil Sands Mining Low Low to Moderate Low Opportunity currently implemented within and between operators. Function of availability, location, and evaluation of environmental net effects. 9. Use saline water for steam generation at oil sands in situ thermal operations Oil Sands In Situ High Low to Moderate Low to Moderate Dependent on availability of saline groundwater source, level of water salinity, and evaluation of environmental net effects; 10. Implement oil sands in situ enhanced recovery by solvent injection Oil Sands In Situ Pilot Negligible Moderate In pilot or evaluation stages Waterflood Recycle produced water from oil and gas wells instead of disposal or release Conventional Oil Unconventional Gas High High Low to Moderate Has been widely adopted, with expected modest increases in impact to water use Oil Sands In Situ 12. Implement in situ combustion to enhance recovery at oil sands in situ operations Oil Sands In Situ Pilot Negligible Unknown Under evaluation, adoption will depend on technological advances Waterflood Consider water treatment for waste/produced/saline water to be reused or released instead of disposal Conventional Oil Unconventional Gas Oil Sands In Situ Oil Sands Mining Moderate Low to Moderate Low to Moderate Regulatory barrier to treatment and release of oilfield wastewater to the environment. 14. Convert to oil sands mining extraction methods that are not water-based Oil Sands Mining Pilot Negligible Unknown Implementation to depend on technological advances 15. Reuse produced water from oil and gas wells instead of disposal or release Waterflood 1 Unconventional Gas Oil Sands In Situ Moderate Low Moderate Widely adopted. Further implementation dependent on availability, location and evaluation of environmental net effects. January 2016 Water CEP Progress Report - Upstream Oil and Gas Sector Page 25