Gas over Bitumen in North Eastern Alberta

Transcription

1 Gas over Bitumen in North Eastern Alberta Was the Alberta Energy and Utility Board s blanket shut-in approach appropriate? Prepared by: Brad Wooley Student ID: Professor: Joseph Doucette Class: BUEC 560 Date: June-2005

2 Table of Contents 1.0 Introduction 2.0 Objectives 3.0 Background 3.1 Gas-over Bitumen Understanding the Issue 3.2 Sequence of Events 4.0 The Regional Geological Study (RGS) 4.1 Overview 4.2 Technical Issues Complex Geology Pressure Data 5.0 Economics 5.1 The Oil Equivalence Approach of the EUB 5.2 Long-Term versus Near-Term Economic Value 6.0 Conclusion Appendix References Tables and Figures

3 1.0 Introduction The gas over bitumen issue in the Athabasca region of Northeast Alberta gained public attention in the mid-1990 s and has since been a topic of debate between gas producers and oil producers of Alberta. The Alberta Energy and Utilities Board (hereafter referred to as the EUB) have used their regulatory authority to address the issue. The EUB is an independent, quasi-judicial agency of the Government of Alberta 1. The mission of the EUB is: To ensure that the discovery, development, and delivery of Alberta's energy resources and utilities services take place in a manner that is fair, responsible, and in the public interest. The gas over bitumen issue first started in 1996 when the EUB received submission from Gulf Canada Resources Limited (now Conoco Phillips, Inc) requesting that the Board order the shut-in of associated gas production on its Surmont oil sands leases. The EUB ordered the shut-in of the majority of the gas wells in the Surmont case and nearly three years after the Surmont decision, in 2003, they made a decision to issue what is referred to by many as a blanket shut-in of natural gas wells within a specified application area. The decision was made using information collected over the six years and included; geological studies, past case studies, economic analysis and input from both the gas producers and oil producers.

4 2.0 Objectives In order to understand the decision of the EUB to shut-in natural gas wells in the Wabiskaw-McMurray geological zone of the Athabasca region, a general overview of the issue will be provided along with a brief description of the sequence of events from the time the issue was submitted to the EUB in 1996 to the decision in From here, I will discuss the nature of the geology in the Athabasca region and the economics that were taken into consideration by the EUB, both of which were key factors in the EUB s decision. The primary objective of the paper is to determine if the EUB s blanket shut-in approach to the gas over bitumen issue in the Wabiskaw-McMurray zone was fair, responsible and in the best interest of the public, as the EUB mission statement implies. 3.0 Background 3.1 Gas over bitumen Understanding the Issue It is no secret that Alberta s oil sands are host to the world s largest deposit of bitumen. This non-conventional source of energy is increasingly recognized as a strategic resource and a potential contributor to North American security. The demand for crude oil from the oil sands is expected to remain significant well beyond 2030.

5 The estimated volume of crude oil in Alberta by the time all exploratory and development activity has ceased is in the order of 400 billion cubic meters (2.5 Trillion barrels). Of this amount, 22 billion cubic meters (140 Billion barrels) are estimated to be recoverable with surface mining operations and 378 billion cubic meters (2.4 Billion barrels) are estimated to be recoverable with In-Situ or underground activities 2. Surface mining has been the prevalent technology for oil sands development in the Athabasca region since the early 1970 s, but with the significant potential of the oil sands not amenable to surface mining, there has been an increased focus towards in-situ technology development. Table 1 Bitumen Resources in Alberta The two most common technologies for in-situ oil sands production are cyclical ( huff and puff ) and Steam Assisted Gravity Drainage (hereafter referred to as SAGD). Cyclical oil production technology uses vertical injection wells to inject high pressure steam into an oil deposit. The steam and condensed water heats the viscous oil, which is then pumped to the surface through the same well. SAGD technology uses a very similar process, but consists of two horizontal

6 wells (one steam injection well above one producer well). The horizontal wells in the SAGD process can be up to 1000m in length and they perform best in high permeability reservoirs, resulting in lower injection pressures and steam/oil ratios. This process has been extensively piloted and in some cases commercialized by several companies. The development of SAGD projects in the region has been of great concern to natural gas producers. Natural gas producers in the greater Athabasca region have thousands of producing wells representing billions of dollars of investment. The source of the problem is that in many cases in the region, Figure 1 Impact of a Depleted Gas Zone the Wabiskaw-McMurray geological zones in particular, rights have been issued to different lease holders, permitting the production of oil or natural gas in the same zone. When natural gas pools are in pressure communication with underlying bitumen reservoirs, the depletion of the gas pool causes lower pressures in the zone above the bitumen reservoir and when steam is injected into the bitumen reservoir, there is a high potential for the steam to escape into the depleted gas pool. In addition, in situations where a water zone exists above the bitumen, operating at lower pressures increases the risk of water invading the bitumen reservoir.

7 3.2 Sequence of Events 1996 The EUB received submissions from several companies holding oil sands leases (Gulf Canada Resources Ltd, now Conoco-Phillips, Inc, being the first 3 ) requesting that associated gas production from the Wabiskaw- McMurray formation on its Surmont oil sands leases be shut in until oil sands development was completed EUB initially rejected the request, but after recognizing the implications of it s decisions, decided to initiate a General Inquiry into the issues and would reconsider Gulf s request when it was complete 1996 to EUB General Inquiry 4 is completed in March 1998 EUB Interim Directive ID is issued. It is largely based on the General Inquiry and concludes that although limited field data was available, sufficient evidence exists to suggest that associated gas production could have a detrimental effect on some bitumen resources EUB ID 99-1 also stated that any associated wells started prior to July in the specified area would be allowed to produce subject to resolution of any issues raised by the oilsand leaseholders or the board ( grandfathered ). Any wells drilled and/or completed in the defined area would require an application for approval prior to gas production The Surmont hearing decision 3, precipitated from the Gulf shut-in application in 1996, announced that 146 of the 183 wells applied would be shut-in. Compensation of $85M was ultimately provided to the natural gas producers 2003 March EUB issued decision in response to 27 applications relating to the approval to produce or shut-in gas from the Wabiskaw-McMurray deposit in the Chard-Leismer area. EUB endorsed the continued suitability of ID 99-1 and 60 of 145 wells were shut-in

8 2003 June EUB issues General Bulletin GB The bulletin states: Based on evidence and conclusions derived from lengthy proceedings before the board over the last year and further technical studies, the previously grandfathered wells completed before July 1998 present an unacceptable risk to future thermal recovery of thermal bitumen recovery. Effective August 1, 2003, shut in gas production from the Wabiskaw- McMurray in the new reduced application area Complete a detailed review of shut-in gas wells within the new application area to allow production of associated gas Allow the production of gas wells outside of the application area Amend ID 99-1 as per the new application area (map shown in Appendix) 2003 July EUB issues General Bulletin GB The bulletin states that it will be using a phased approach to shut in gas wells in the application area: Phase 1: Consists of an interim shut-in order with provision for exceptions. Gas producers have the opportunity to provide evidence that the gas zone is not associated with potentially recoverable bitumen Phase 2: Challenges to Phase 1 exemptions by way of expedited reviews Phase 3: Upon the completion of all or a portion of the EUB Regional Geologic Study (RGS), the EUB will make the recommendations and any objections will be followed up with a public hearing 2004 January EUB issues Regional Geological Study (RGS) 9, but it does not state which natural gas wells to be permanently shut in. EUB states the staff will issue recommendation January 26, The study does contain a list of 464 gas pools found to be in contact with the bitumen and 313 gas pools are not in contact with bitumen in the Wabiskaw-McMurray Proceedings as required and as described in EUB GB (Phase 3)

9 4.0 The Regional Geological Study 4.1 Overview The objective of the Regional Geological Study 9 (RGS) was to establish which gas pools are in pressure communication with stratigraphic units that have the potential to contain bitumen exceeding 10 meters in thickness within parts of the Athabasca Wabiskaw-McMurray deposit. The RGS was initiated as part of the process outlined by EUB General Bulletin (Phase 3). It was an extensive four month study (September through December 2003) by a team of staff and consultants from eleven different companies. The RGS studied the application area as outlined in the EUB GB (see map in Appendix). The intent of the study was to analyze the areas of which have the Figure 2 RGS Area Sub- Divided by Project Teams thickest bitumen within the Wabiskaw-McMurray, encompass most of the existing and proposed SAGD projects and had a history of gas production. The study was divided into two areas. The area south of Township 87 (see Appendix), excluding the Surmont lease, was identified as the main area and the area north of Township 87, excluding the mineable area and areas where gas production is not expected

10 to occur, was identified as the northern area. The study was also sub-divided into six different project areas. Separate teams studied each area, but worked together to ensure consistency. The RGS was an extension of the analysis completed for the EUB Chard- Leismer (EUB Decision ) case performed in In the Chard-Leismer study it was established that particular mudstone intervals could provide an effective barrier between a gas pool and bitumen deposit. The effectiveness of the mudstone as a barrier is determined by its lateral extent and continuity. Both depend on how well the mudstone was preserved and how it was deposited. A typical example is illustrated in Figure 3 below. Figure 3 - Typical Schematic of RGS, illustrating an Effective Mudstone Barrier (Non-associated gas pool highlighted in orange)

11 The RGS was completed using a four step process 9 : Step 1 Develop a regional stratigraphic model to understand the complexity of the geology in the region. This included both reservoir (gas pools, bitumen or water) and non-reservoir units. Step 2 Evaluate and map the vertical and vertical extent of gas pools and top water to establish the Region of Influence (ROI) of the gas Step 3 Evaluate and map the bitumen within the stratigraphic unit to assess the thickness, quality and distribution Step 4 Combine the information from steps 1 to 3 to determine where gas pools are in communication with bitumen pay zones in excess of 10-m Upon completion of the RGS, the EUB concluded the following: Gas in the Wabiskaw-McMurray has the potential to be associated with underlying channel bitumen, either through direct vertical continuity or indirectly through lateral continuity of the gas and top water zones. Regionally correlatable mudstones and shales may exist throughout the study area and possibly act as a barrier between gas pools and bitumen deposits. The occurrence of thick, bitumen saturated sand is extensive and randomly distributed throughout the area. Identified 464 gas pools considered to be associated with bitumen and 313 gas pools not associated with bitumen deposits.

12 4.2 Technical Issues Complex Geology The Wabiskaw-McMurray formations in the Athabasca region are incredibly complex. The channels within the formation originate from the tops of the McMurray sands and cut through variable thicknesses of underlying sediment (Figure 4). The channels themselves are also of random thickness and not always continuous. Figure 4: Schematic of the Main Area of Study There was over 5000 wells in the area of study, but not all of the wells had sufficient quality of data for a detailed geological evaluation. Overall, stratigraphic picks were made from 3600 wells for a total of 28,700 picks. A detailed examination was made of the core from 155 wells; this was equivalent to 10,000-meters of core sample.

13 The Stratigraphic model, which included the distribution and properties of the lithological units within the Wabiskaw-McMurray formation were determined using the core samples mentioned above. The analysis of the core samples provided detailed information for the immediate area at the location of the well, but the precision of the overall 3-D Stratigraphic model, which covered thousands of hectares was dependant on the location and density of the available wells in the area studied. The core samples illustrated in Figure 5 clearly identify the Figure 5 McMurray A2 Core photo variability of the geology. Furthermore, there is evidence of extensive faulting and jointing within the Wabiskaw-McMurray. So it is difficult to predict with accuracy if the regional mudstones provide an effective barrier between the gas pools and the bitumen deposits because they could be breached by the faults Pressure Data The SAGD process uses a technology called artificial gas lift to produce oil from the bitumen deposits and artificial gas lift requires a minimum pressure of ~ kpa (absolute pressure). So a key factor in determining the extent of

14 association of a gas pool with a bitumen deposit is the pressure within each zone (pressure communication). Unfortunately, the quantity and quality of pressure data available for the RGS was limited. Of the ~5000 wells, only 83 wells were used for the purpose of pressure and production analysis. This represents less than 5% of the wells in the application area. Pressure data is difficult to achieve in solid bitumen deposits, so it is near impossible to determine if a gas well is in pressure communication with a bitumen deposit from pressure data alone. But if more pressure and production data were available for the study and combined with the stratigraphic-structural analysis and mapping from the RGS, the assessment of pressure communication between the gas pools and bitumen deposits would likely be more accurate Economics 5.1 The Oil Equivalence Approach of the EUB Although the EUB expressed their views of the economics presented to them from the gas producers and the oil producers, the decision to shut-in all wells in the Wabiskaw-McMurray in 2003 was ultimately based on the application of an oil equivalence standard. Within the area of application as per EUB Interim Directive ID and as described in EUB General Bulletin , there is approximately 80 billion cubic meters (500 billion barrels) of bitumen in the Wabiskaw-McMurray. The EUB used a conservative estimate for recovery of 20% (ultimate recovery from

15 SAGD technology is expected to be in the order of 40 to 70% 11 ), of which resulted in reserves of 16 billion cubic meters (100 billion barrels) of recoverable bitumen. Within the same area of application, there is approximately 30 billion cubic meters (1 trillion cubic feet) of remaining gas reserves. This is equivalent to about 2% of the province s total gas reserves. The EUB compared the gas to bitumen resources on an energy equivalence basis. The gas reserves in the application area are equivalent to approximately 28 million cubic meters of bitumen (175 million barrels). Based on this standard used by the EUB, the energy content of the recoverable bitumen reserves at risk is over 600 times larger than the energy content of the proposed shut-in gas production. This gross analysis may have been portrayed as cut and dry, but there are several issues that may have been overlooked. The definition of value as used by the EUB is open to interpretation, but in terms of strictly oil equivalence, the definition of value is only measured in terms of energy output (i.e. joules). It does not necessarily capture the full range of social costs and benefits for either gas or bitumen production. So the argument can be made quite easily that the EUB s use of the oil equivalence

16 standard does not completely take into account the public interest as their mission suggests 13. Gas and Bitumen are used to produce different kinds of energy. Natural gas is, in general, used for residential heating and electricity (more often now than in the past because natural gas is becoming recognized as a cleaner source of energy than crude oil or coal). The most common use for refined bitumen is for the transportation industry. So the oil equivalence standard is questionable even from an energy perspective because the social benefits and costs are different for each. The oil equivalence approach also does not include the costs associated with the production of the energy (i.e. capital investment, costs of energy required for operations, costs of shipping, costs to the environment, etc). In fact, in the General Bulletin s issued with respect to the interim blanket shut-in, there was very little reference to costs. In the Surmont case, the EUB report (EUB Decision ) was 160 pages and the Economics section was only 4 pages in length, two of which included discussion on potential compensation to the gas producers. 5.2 Long-Term versus Near-Term Value Gas over bitumen in Alberta is an issue of long term potential benefits from the conservation of bitumen versus short term benefits from both existing

17 and future gas production. The oil from the bitumen deposits can only be recovered using in-situ recovery technology, of which is a developing technology and even if SAGD operations produce on a large scale it will take hundreds of years to produce the resources in the region. On the other hand, gas production uses a technology that has been proven for a long time, production in the region prior to the gas over bitumen issue was equivalent to approximately 2% of Alberta s total gas production (~250 million cubic feet per day/mmcfd) 12 and the gas producers expected to deplete the remaining reserves in a relatively short time period. The position of the EUB was that the timing of the recovery was irrelevant between the two resources 3. The gas producers argued that the consideration of net present economic value would be a more appropriate measure of the relative social value of the gas and bitumen resources. Because the bitumen resources would take years to recover, the net present economic value of the bitumen relative to the value of the gas (hundreds of millions) would be very close to zero. One of the challenges of using net present economic value is that it is based on market price. When market price is used to determine economic value, not all social costs are considered. An example of a social cost that would not be considered in the economic value of bitumen or gas is the cost to the environment. Such factors of the market that impose costs to society are referred to as externalities.

18 Therefore, in order to determine the net present economic value of the gas and bitumen resources, all social costs and benefits must be internalized into the market price of the product. By no means is this a simple task; it involves the assignment of a monetary value to ecological goods and other goods whose value is extremely difficult to quantify Conclusion The gas over bitumen issue in Alberta is an incredibly complex issue; it involves competing interests from developers, emerging technologies (SAGD) with limited experience, complex geology and the consideration of both near and long term values. On the one hand, shutting in of the gas wells has the potential to curtail economic activity in North Eastern Alberta from lost gas production, resulting in lost royalties, taxes, wages and related spending. In addition, the gas producers realize an immediate impact due to related costs, lost cash flow and loss of investment opportunities. On the other hand, the shutting in of the gas wells may conserve bitumen resources that could provide significant economic and social benefits for many generations into the future.

19 Although the EUB s order to shut-in the wells was based on over six years of information, the time it will take to completely understand the uncertainties surrounding gas over bitumen will likely be in the order of decades. The geological model developed by the EUB from the Regional Geological Survey and the inferences made with regard to pressure communication between the gas pools and bitumen deposits were based on the most available and accurate information to date. Unfortunately, as discussed, the geology in the Athabasca region is extremely variable. With further development (SAGD and/or gas wells) within the Wabiskaw-McMurray, more information will become available and the geology will be better understood. But this will take a very long time and it is most likely that there will never be sufficient information to develop a model for the entire region that can be used on a case by case basis. There is no question that the social benefits and costs of both gas and bitumen resources in Alberta must be better understood. Although the EUB s oil equivalence comparison did not seem to take this into consideration, it is very difficult to accurately compare the societal benefits and costs of each with any valuation method, especially with an emerging technology (in-situ bitumen production). Again, this will be better understood with time.

20 In summary, it is obvious the EUB s decision to order the blanket shut-in of the gas wells in the Wabiskaw-McMurray was in the interest of energy conservation. I believe the decision was also fair, responsible and in the best interest of the public given the uncertainties of the issue and the relatively short time frame to make a decision. As time progresses and more information becomes more available, it will very likely make sense for the EUB to reconsider the production of gas in the application area on a case by case basis.

21 APPENDIX

22 References 1. Alberta Energy and Utilities Board Retrieved June 03, National Energy Board. Canada s Oil sands Opportunities and Challenges to ndsopportunitieschallenges2015 Retrieved June 03, EUB Decision Gulf Canada Limited. Request for the Shut-In of Associated Gas, Surmont Area. Retrieved June 05, EUB Inquiry. Gas/Bitumen Production in Oil sands Areas. Retrieved June 05, EUB Interim Directive ID Retrieved June 05, EUB Decision Chard Area and Leismer Field Area. Applications for the production and shut-in of gas. Retrieved June 21, EUB General Bulletin GB Proposed Conservation Policy Affecting Gas Production in Athabasca Wabiskaw-McMurray Oil Sands Areas. Retrieved June 21, EUB General Bulletin GB Bitumen Conservation Requirements, Athabasca Wabiskaw-McMurray Oil Sands Areas. Retrieved June 21, EUB Regional Geological Study. Retrieved June 21, A Review of the EUB Regional Geological Study. Dr. N.C. Wardlaw. December 16, Alberta Chamber of Resources. Oil Sands Technology Roadmap, Unlocking the Potential. January 30, Paramount Energy Trust. General Overview of Gas/Bitumen Issue. June 25, Canadian Institute of Resources Law. Valuing Energy Resources: A reflection on the EUB s Decision in the Surmont Gas Over Bitumen Controversy. Michael M. Wenig. Fall 2002.

23 Tables and Figures Table 1: Reference #2 Figure 1: Reference #11 Figure 2: Reference #9 Figure 3: Reference #9 Figure 4: Reference #9 Figure 5: Reference #9 Cover photo: Reference #9