Figure 9 – uploaded by Experience Nduagu

Table 2 The OTSG can be operated in one of three modes: constant dry gas, constant firing rate, or constant feed water flow rate. Table 2.4 shows the attributes of the technology when operated at constant dry gas conditions. The technology vendor has also reported that feed water quality does not have to be better than what is currently being fed to the traditional OTSGs for the SQ90™ design to achieve 90 percent steam quality. The technology improves boiler efficiency through the reduction in feed water volumes required for a given steam load, thereby resulting in reduced water treatment cost.?° This is a commercially available technology for deployment in the oil sands industry. With most OTSGs in the industry producing 78 percent steam quality, SQ90™ promises to take that to 90 percent while preventing dry outs. The technology is based on the use of rifled pipes within the radiant section of the OTSG. The use of rifled tubes is common in nuclear reactor designs where very high heat fluxes can be easily attained. The pipes are designed with a swirl pattern that induces a rotational flow to the fluid stream, thus, providing an even, wet layer on the pipe wall which promotes heat transfer to the liquid and reduced risk of dry out.?° The stream travels through the tubing in a spinning motion, creating a centrifugal force that separates water from steam using less energy. This is unlike the traditional smooth pipes where liquid droplets tend to remain in the lower section of the pipe due to the affects of gravity. Figure 2.4 compares the cross-sectional views of a smooth pipe and a rifled pipe in operation. does not have to be better than what is currently being fed to the traditional OTSGs for the

Related Figures (57)

able E.1: Optimal Technology Configurations for Brown and Greenfield Developments The technology configurations that meet the minimum costs and emissions objective criteria will allow for significantly more room for oil sands production growth. These technology configurations have the potential to reduce bitumen supply cost by 34-40 percent, reduce fuel- derived emissions from in situ oil sands production by more than 80 percent, and consequently delay the time until the emissions cap is reached by several decades.

Figure E.1: Combined Impact of Technologies under Different Cost and GHG Emissions Scenarios Reducing emissions usually comes with a cost penalty. Interestingly, the results of this study prove otherwise. They show that emissions and cost reduction objectives are not adversely related. This means the two objectives can be achieved simultaneously. Even more interesting is the fact that by simply choosing to implement the minimum cost objective configuration, dramatic emissions cuts are made as a result. The different technology configurations (in Table E.1 and Figure E.1) result in new direct emissions profiles? for the oil sands industry and these are compared with the business as usual profile (BAU with policy changes‘) and the 100 MtCOz cap in Figure E.2.

The new GHG emissions profiles? based on the optimal cost and emissions technology configurations will allow for oil sands production growth. These technology configurations have the potential to reduce bitumen supply cost by 40 percent, and avoid reaching the 100 Mt CO2eq. per year cap during the study period (2016-2036). However, further research and development work is needed to de-risk the promising technologies through pilot and field demonstration studies if the prospects of delivering these costs and emissions reductions are to be realized. For more information on possible ways of how to fuel a greener and more cost competitive oil sands industry, see the Appendix.

Figure 1.1: Production Costs and Greenhouse Gas Emissions of World Crude Oils Extraction of bitumen from oil sands resources has brought significant economic benefits to the province of Alberta and across Canada through the delivery of services, tax revenues, royalties and job creation. However, the oil sands industry is faced with several challenges, including access to markets, high production costs, and high energy and emissions intensities compared to conventional and non-conventional crude counterparts.

Figure 1.2: Pictorial Event Timeline of In Situ Oil Sands Technology Development and Production Growth

Figure 2.2: Wastewater Treatment and Steam Generation Superstructure for SAGD Bitumen Production Figure 2.2 shows a superstructure of various processes and technologies that form the basis of innovations deployable for water/wastewater treatment. It also shows the interconnections of the WWT segment with the steam generation stage in a SAGD production facility. The water/wastewater treatment step can be subdivided into an oil and water separation unit and water treatment unit.

Figure 2.3: Process Flow Diagram of the FTB Process As depicted in Figure 2.3, there are four options for handling the blowdown from the process, including: BD-1, BD-2, BD-3, and solid waste discharge. The first three blowdown options are reduced liquid discharge (RLD) options, whereas the solid waste discharge option is a zero-liquid discharge (ZLD) option that may handle 35 percent of the BD-1 stream. A medium pressure separator (SEP) can remove additional water from the BD-1 stream (about 30 percent mass of BD-1), while the multiple-effect evaporator (MEE) removes another 35 percent water content. Some CO? from the stack gas could be sequestered with the BD-3 or the solid waste streams to give a small reduction of the process emissions. Electrocoagulation is one of several electrochemical techniques for water treatment. Other electrolytic cell technologies include sedimentation, flotation, and filtration.2” The EC method removes the dissolved solids in the produced water by electrically generating the coagulant and floating the sludge using a gas (methane, nitrogen, hydrogen). It often uses an iron electrode which ionizes by the release of electrons that are used to precipitate dissolved ions in the produced water. The high temperature EC process can operate at temperatures nearing 95°C.

Table 2.2: Acceptable Quality of OTSG Feed Water he OTSGs are normally designed for 80 percent steam quality, but many run between 70 percent 9 80 percent steam qualities, and 78 percent is considered the industry standard.°7°3 Of the 2maining 22 percent that is mostly liquid, about 7 percent is blowdown which could be sent to disposal well to get rid of hardness and silica, and about 15 percent is recovered and returned ack to the process. The presence of impurities in the boiler feed water, due to poor treatment r treatment limitations occasioned by economic and/or operational constraints, necessitate the 2tainment of a portion of the fluid as liquid so that the impurities can stay in that phase.*? If the quid were to be completely vaporized, the impurities would drop out of solution/sludge and eposit onto the internal walls of the boiler tubes; creating sites for overheating and likely amage to the flow channels. Steam generation is a critical part of the bitumen production process via Steam Assisted Gravit Drainage (SAGD). In oil sands in-situ recovery operations, Once-Through Steam Generator (OTSGs) are the most common type of boilers in use as they are more robust and can handle fee water with higher TDS content (<8000 ppm). In Western Canada, there about 170-200 OTSG installed in various facilities.2? However, OTSGs may face various operational challenges an should be coupled with a vapor-liquid separator to increase the steam quality prior to injectio into a SAGD well. There are also some Heat Recovery Steam Generators (HRSGs) that ar associated with cogeneration power plants, and a few drum boilers that have been deployed i recent projects. Drum boilers are considered more reliable and efficient than OTSGs but mu: operate with higher quality feed water supply. A hybrid drum boiler known as a Force Circulation Oil Sands Steam Generator (FC-OSSG) has also been utilized where it acts much lik an OTSG from a maintenance perspective, but with the operational benefits of a drum boiler. large portion of the feed water to the boiler comes from recycled produced water which | augmented with make-up water that is often drawn from saline aquifers. Table 2.2 shows summary of the generally acceptable feed water quality requirements for OTSGs.

Table 2.4: Attributes of SQ90™ Operated at Constant Dry Gas Conditions

Figure 2.5: DCSG Process and Technology Design Further benefits may also be derived through even smaller equipment sizes, greater portability, ease of separating and capturing CO2, and higher steam production per fuel consumed. It is also expected that the use of DCSG will shrink much of the water treatment components of the conventional oil sands CPF into only a de-oiling unit. Figure 2.5 depicts the DCSG unit with its two compartments for combustion and steam generation.

Figure 2.6: Illustrative Diagram of a Solid Oxide Fuel Cell Operation

Table 2.5: Summary of Steam Generation Technologies

Table 2.7: Brief Summary of Technologies Assessed in the UPG Segment The assessment aims to determine primarily the ability of the technology to reduce supply costs of bitumen and cut greenhouse gas (GHG) emissions. In order to compute the impact of the technology on the supply cost of oil, capital expenditures (CAPEX) and operating expenditures (OPEX) obtained from the technology vendors, available literature, and expert elicitation are used. More details about UPG technologies are provided below.

Figure 2.8: Adoption and Implementation of Digitalization in the Oil Sands Industry

Table 2.9: Brief Description of WWP Technologies and their Performance

Table 3.1: 2016 Field Gate Bitumen and SCO Supply Costs Source: CERI It is also assumed that the facility is operated at 90 percent utilization (assuming one month downtime). When necessary, the six-tenths rule®° was used for equipment or plant capacity scale-up or scale-down. Using the Nelson-Farrar cost indices for refinery construction, the dollar values reported for different years are converted to 2015 dollar values. The cost indices account for industry’s inflationary or deflationary pressures on costs. Where applicable, all cost information in this assessment is brought to 2015 real Canadian dollars, with 2015 as a base year. Unless specifically stated, the dollar values are provided in Canadian currency (CS) and amounts in US dollars (USS) are converted to Canadian dollars using the Bank of Canada conversion rate of CS1/USS0.85.

Figure 4.1: Range of Supply Costs for Various Bitumen Extraction Process Segments For bitumen production supply costs, CERI’s supply cost model is used to evaluate the constant dollar price needed to recover all capital expenditures, operating costs, royalties and taxes as well as earn a 12 percent nominal (10 percent real, with 2 percent inflation rate) return on investment. The supply cost assessed here is the constant 2015 bitumen price (at the field gate) in Canadian dollars per barrel (CS/bbl) that gives a net present value of zero (using a real discount rate of 10 percent) at the end of life of an in situ bitumen extraction project (assumed to be 30 years). This excludes diluent addition, upgrading or transportation costs. The range of bitumen supply costs associated with oil sands technologies, described under RES, WWP, BM, SG and WWT segments, which are likely to be commercial in 5-7 years are shown in Figure 4.1. From the range plot (Figure 4.1), the supply costs from each segment are compared with that of the SAGD Base. From the values, the potential supply cost reductions can be deduced. The blue horizontal dashed line in Figure 4.1 aligns with C$43.3/bbl, which is the bitumen supply cost of the SAGD Base.

The potential for the process segments to reduce direct fuel-derived emissions of bitumen extraction are assessed. In this section, flaring and fugitive emissions and emissions from electricity (grid or cogeneration) generation are excluded. This is because most of the technologies assessed do not target reducing emissions associated with electricity generation, flaring or venting. Also, given that significant portions of the electricity requirements of the oil sands industry are met by the Alberta electric grid, the associated electricity generation emissions are not directly attributed to oil sands production. Based on the existing carbon policy regulations, the power producers are directly responsible and pay carbon tax for the GHG emissions they generate.

Table 4.1: In Situ Oil Sands Production and Processing Segments and their Associated Technologies

Figure 4.5: Volumetric Yield and API Gravity of Products from Partial and Full Upgrading Technologies These technologies are developed to reduce diluent requirements or as alternatives to diluent addition or full upgrading. These technologies are assessed using economic and environmental performances of dilbit and SCO (from delayed coker) as benchmarks. Some of the technologies, for example, those that dramatically reduce vacuum resid such as IYQ, HTL, Hi-Q, etc., aim to achieve deep conversions and, thus, preclude the use of diluent. Their products would be priced higher than those that require diluent addition.

Figure 4.6: GHG Emissions and Supply Cost of Partial and Full Upgrading Technologies

Figure 4.8: Oil Sands Production Forecast However, greenfield development may experience notable growth between 2016 and 2036, resulting in an increase of in situ bitumen production from 2016 levels of 1.1 million bbl/day to 3.8 million bbl/day in 2036. The in situ production profile is later used to determine in situ emissions profile for the SAGD Base and for cases where new technologies were applied.

Figure 4.9: Regulatory Impacts: Coal Power Phase-out (A) and CH, Emissions Reduction (B)

Under the Climate Leadership Plan,®’ the Government of Alberta legislated (Oil Sands Emissions Limit Act)®° a hard limit of 100 Mt CO2eq. per year on oil sands operations to spur efficiency improvements that yield higher productivity with fewer carbon emissions per barrel. 85 Based on the oil sands production forecast generated in the CERI’s 2016 oil sands update. 86 The profiles in Figure 19 include current direct and indirect emissions of all the oil sands production methods (mining, in situ, enhanced oil recovery and primary heavy oil production) and upgrading. Policy changes refer to the coal phase-out and methane emissions reductions. 87 Climate Leadership Plan of the Alberta Government. See hitps://www.alberta.ca/climate-leadership-plan.aspx 88 Fall 2016 — Bill 26: Oil Sands Emissions Limit Act. Available at https://albertandpcaucus.ca/our-work/project/fall- Pal) apa ae ee ee 1

Figure 4.11: GHG Emissions Profile for the Oil Sands Industry and the 100 MtCO2/year Emissions Cap with Coal Phase-Out In a low-price environment, producing at the lowest possible supply cost is a necessity; therefore, technologies that realize the minimum cost objective are preferred. A simplified version of the emissions profiles in Figure 4.10 are presented in Figure 4.11. In Figure 4.11, the profiles generated from the minimum emissions and cost objectives are shown. Also included in Figure 4.11 are SAGD Base profiles with or without future cogeneration additions or grid electricity.

Figure 5.2: Range of Direct GHG Emissions for Various Bitumen Extraction Process Segments

Table 5.1: Optimal Technology Configurations for Brown and Greenfield Developments The cumulative economic and direct GHG emissions impacts of adopting a combination of technologies or processes are captured as an overall impact, relative to the baseline SAGD facility. Six optimal configurations comprising compatible technologies from the process segments are identified; one for the brownfield and five for the greenfield facilities. For a brownfield development, the optimal technology configuration (Table E.1) is one that requires only a slight

Figure 5.4: GHG Emissions and Supply Cost of Partial and Full Upgrading Technologies The partial upgrading technologies show potential to add value to bitumen without significantly increasing costs and emissions. However, when brought to West Texas Intermediate (WTI)- equivalent, which is a product that is comparable to the SCO product grade, the supply costs of some of the technologies may not be competitive in a low oil price environment.

Ull Sands Emissions Fromes and the LUU MUtLU2 EMISSIONS Lap The different technology configurations (in Table 5.1 and Figure 5.3) result in new direct emissions profiles?” for the oil sands industry and these are compared with the business as usual profile (BAU with policy changes””) and the 100 MtCOz2 cap in Figure 5.5. Under the Climate Leadership Plan,?° the Government of Alberta legislated (Oil Sands Emissions Limit Act)?” a hare limit of 100 Mt COzeq. per year on oil sands operations to spur efficiency improvements that yield higher productivity with fewer carbon emissions per barrel. 2016-bill-25-oil-sands-emissions-limit-act

Figure 9 – uploaded by Experience Nduagu

Related Figures (57)

Connect with 287M+ leading minds in your field