(HC)3 Hydrocracking Technology

With the annual growth of development scale and production, the research of heavy oil and oil sands become more and more important. Due to the characteristics of heavy oil and oil sands, the degree of reserves recovery is restricted by development mode. So there is a big difference in classification criterions and evaluation techniques of reserves in the world. In this paper, using the major heavy oil and oil sands accumulation areas —Venezuela heavy oil belt and Canada oil sands as example, we analyse the reservoir characteristic of heavy oil and oil sands, and then discuss the classification and evaluation techniques of reserves suitable for different development modes. The heavy oil belt in Venezuela and oil sands in Canada are all characterized by huge thickness, middle-fine sandstone, loose cementation, high porosity and high permeability. To adapt different development mode, we establish corresponding evaluation criterions for reservoir, including porosity, permeability, shale content, saturation, barrier and interbed, the thickness and width of continuous oil layer and so on. We classify the reserves as OOIP, economic reserves, reserves for horizontal well, reserves for steam flooding (SF)/ cyclic steam stimulation (CSS) and reserves for SAGD. Using logging and geophysical techniques, we evaluate and classify the reserves. 1.Introduction Heavy oil and oil sands are characterized by shallow buried depth, large thickness, huge reserves and unconsolidated structures. Because crude oil has high viscosity, conventional vertical wells generally have no or extremely low productivity. Currently, these reservoirs are predominantly developed by horizontal wells in two stages: cold production and thermal production. All these conditions have presented new requirements on contents and methods of reserve evaluation. In this essay, through study on reservoir features and corresponding development techniques for heavy oil in Venezuela and oil sands in Canada, we put forward reserve assessment methods and techniques by class for various development modes. 2.Reservoir evaluation and selection criteria for heavy oil and oil sands development Currently, cold production (CP) is the prevailing development method adopted for heavy oil in Venezuela, at the same time, cyclic steam stimulation (CSS), steam flooding (SF) and SAGD have been tested. Oil sands in Canada are mostly developed by SAGD and open mining. A series of reservoir selection criteria have been proposed to cope with requirements of different development methods with horizontal wells on oil layers (Table 1).

Extensive attention is being paid to the exploitation of unconventional oils, mainly heavy and ultra-heavy oils. Thereinto, the high viscosity nature of heavy and ultra-heavy oils is a major obstruction and challenge to the recovery of the heavy oil reservoir and the selection of the enhanced oil recovery methods. In order to investigate the characteristic of the viscosity variation in sequence temperature regions and the internal mechanism of the shear thinning property, the ordinary heavy and ultra-heavy oils were employed and studied. On the basis of the fundamental physic-chemical analyses, the viscosity-temperature and viscosity-shear rate characteristics in sequence temperature regions were evaluated comparatively for both heavy oils. In addition, the free volume theory was involved to clarify the mechanism of the shear thinning property and viscosity variation. Then the viscous activation energy variation in sequence temperature regions was validated and analyzed with the negative linear relationship between the viscous activation energy and the frequency factor (compensation effect). Satisfying viscosity prediction curves were obtained for both heavy oils with high regression precision (R2 > 0.99). A further understanding of the compensation effect existence and thermal oxidation characteristic comparison for the ultra-heavy oil and its components were obtained. From this study, a novel insight into the characteristic and prediction of viscosity-temperature relationship can be brought based on the viscous activation energy variation in sequence temperature regions.

Polyaromatic hydrocarbons (PAHs) were known to interact with the micro-aggregates of asphaltene compound in heavy crude oil. This study aims at designing, synthesizing, and applying a water-soluble self-assembled viscosity reducer (SAVR) bearing PAHs to efficiently reduce the viscosity of heavy oil through the formation of host-guest complex. The synthesized SAVR product was composed of two chemical components A and B. In an emulsion comprising heavy oil and the SAVR, the PAH groups from the hydrophobic part (component A) strongly interacted with the asphaltene in heavy oil via π-π stacking and hydrophobic association to solubilize these components, the hydrophilic part (component B) of the SAVR self-assembled with component A via host-guest complex to improve the solubility of the entire SAVR in an aqueous environment. The collapse of the asphaltene component results in a decrease of the viscosity of heavy crude oil. The SAVR products were compatible with high-salinity water, and able to form stable oil-in-water (O/W) emulsions with heavy oil. The SAVR formulation exhibited high effectiveness in heavy oil viscosity reduction, the viscosity of heavy oil was decreased by 80% at a 1:1 mass ratio of A:B and an oil-to-water ratio of 7:3. At the heavy oil-water interface, the oil bulk was found to gradually disperse in the aqueous phase containing SAVR in the form of small oil droplets. This new chemical formulation has great potential in heavy oil displacement from a reservoir or treating produced heavy oil, ultra-heavy oil, oil sands, etc. Since the viscosity of the heavy oil can be substantially reduced, the oil can be more easily produced and transported for further processing in an economical and efficient manner.

The Provost Upper Mannville B Pool of the heavy oil belt in east central Alberta is contained in McLaren Formation sands of Upper Mannville (Lower Cretaceous) age. The reservoir is up to 35 m thick and contains local areas of underlying water, a water-in-oil transition zone and patches of overlying gas. The reservoir sands were deposited in fluvial environments filling the McLaren valley as it was aggraded during a sea level rise. The sands are mineralogically mature and composed predominantly of quartz. The reservoir pore systems are being characterized using petrographic image analysis techniques. Actual pore images obtained from thin sections are used to provide petrophysical data and to correlate the pore systems with geological facies. An important feature of the reservoir is the presence of zones of shale clasts in a sand matrix. These zones vary in thickness from several centimetres to several metres. Shale clasts constitute as much as 85% by volume in some zones and thus represent a significant barrier to vertical fluid flow. In order to numerically simulate the impact of the shale clast zones on recovery processes, parameters such as kh and kv have to be estimated. To arrive at realistic parameters, small-scale numerical models, based on actual clast distributions from core, have been constructed and equivalent alues for kh and kv have been obtained at the core and grid block scale. Introduction The oil sands and heavy oil deposits of western Canada with their impressive (471.6 × 109 m3(1–3)) resources represent Canada's "ace-in- the-hole" for future energy resources. Of these resources only a small portion is recoverable by mining methods. The greatest percentage must be recovered by in situ techniques. The oil sands and heavy oil reservoirs are complex and heterogeneous, and an integrated team of geologists, petrophysicists, reservoir engineers and numerical modellers is needed to develop processes specific to particular reservoirs for the recovery of these resources. These recovery processes need to be based on a detailed characterization of the reservoir. It was with this in mind that the Alberta Geological Survey, in its Joint Oil Sands Geology Program with the Alberta Oil Sands Technology and Research Authority (AOSTRA) and the Alberta Department of Energy, initiated a project to characterize oil sands/heavy oil reservoirs. The objective is to develop and evaluate techniques for the detailed characterization of oil sands and heavy oil reservoirs for use in numerical process simulations. This paper reports on studies carried out in the Provost Upper Mannville B Pool In this project a detailed geological characterization of the reservoir has served as a basis on which specific aspects of the reservoir description (or characterization) are focussed on, using novel techniques. The pore systems of the more "uniform" portions of the reservoir have been characterized at the pore scale using petrographic image analysis techniques and relating geology to permeability.

The ebullated-bed reactor (EBR) is an important system used in the upgrading of heavy oil residue into valuable light products in petroleum refinery operations. The assessment of the gas separation region hydrodynamics is very significant to investigate the performance of EBR. An advanced understanding of EBR fluid dynamics will help in improving the design of existing and future commercial units. For this reason, the development of a computational fluid dynamics (CFD) model is very challenging, where understanding the fundamentals of fluid dynamics in EBR is carried out using a three dimensional model and the turbulence model with a standard wall function in cup geometric design. The two models were used to analyze the influence of operational parameters such as recycle ratio, and inlet velocity on gas fraction recycled and separation efficiency. Moreover, the prediction of the regime transitions occurring in the freeboard region of the EBRs was achieved using the two aforementioned models. The results of the fluid dynamics behavior revealed that the inlet velocity has a substantial effect on gas fraction recycled and separation efficiency. The liquid mean residence time scale provided a valuable efficiency result for the separation within the range of expected mean residence times. This investigation, therefore, provided a good framework for the evaluation of future design and gave a better understanding of gas and liquid flow patterns in EBR.

Manufacture of light hydrocarbons from heavy oils – processes and developments. High quality crude oils are running short and their price continues to increase. At the same time there is a trend towards light petroleum products for use as transportation fuels or petrochemical raw materials. Consequently, the conversion of heavy oils, i.e., particularly distillation residues but also heavy oils from tar sands, is gaining increasing commercial importance. The cracking processes currently used in the refining industry are reviewed. Emphasis is placed on their application to metal‐and asphaltene‐containing heavy oils. Feed pretreatment by solvent deasphalting is discussed and the manufacture of syncrude from tar sands is considered. New developments for conversion of heavy oils are outlined. The future production of shale oil and of transportation fuels from oil shale is briefly treated.

Summary Fireflooding of tar sand reservoirs following a preheating phase exploiting a reservoir heterogeneity was investigated in three dimensional (3D) physical models. The research strategy for applying the results and the experimental facility developed for this work are discussed along with the results from four tests. Three different types of reservoir heterogeneities were used: communicating and noncommunicating bottom-water zones and a thin, heated layer simulating a fracture. The preheating phase with the bottomwater zone was found to have a pronounced effect on fireflood performance. A short steam preheating phase did not provide sufficient oil saturation in the communicating bot-tomwater zone to ensure formation of a closed combustion front. A longer steamflood at a lower rate resulted in gravity override of the steam and the subsequent fireflood. A thin, electrically heated horizontal layer simulating a heated fracture yielded encouraging results with potential for further improvements. Introduction The great demand for crude oil and the decrease in conventional reserves have generated more interest in heavy oil and tar sands. Although an important fraction of the world crude supply comes from heavy oil, there is nocommercial in-situ production of the immobile oil con-tained in tar sands. However, tar sands have become an attractive alternative source for liquid hydrocarbons because of the size of the resource base. Canada and Venezuela have the largest tar sand/heavy oil deposits, each estimated at more than 1012 bbl (150×109 m3) of hydrocarbons in place.1x002D;3 Currently, most of this resource is too deep to be recovered economically by surface mining. Extensive work is being performed to develop in-situ methods for producing tar sands.2x002D;4 Although the sands are usually very permeable, the bitumen is immobile because of its high viscosity, often exceeding 106 cp (1 kPa·s). Most of the proposed recovery methods apply heat to the reservoir to increase the bitumen temperature, which drastically reduces its viscosity. Steam injection has been the most common method used for heating the reservoirs. However, fireflooding could be performed with more effective use of surface energy.5 In-situ combustion has been tested in more than 100 field applications, many of which have been reviewed and compared in the literature.6x002D;8 Screening guides have been developed for evaluating the suitability of reservoirs for forward combustion.7,9,10 An important criterion in each of these guides is that the reservoir must have sufficient fluid transmissibility. Since most tar sand reservoirs do not meet this criterion, they traditionally are not considered good candidates for fireflooding. Local heating of the reservoir near an injection well will not provide the communication between wellbores necessary for a displacement process. In-situ combustion in a tar sand requires some scheme to provide initial interweIl communication and mobility to a portion of the tar. A pretreatment might involveheating through a naturally occurring reservoir heterogeneity, such as an adjacent mobile water zone, or an induced fracture with steam injection or fireflooding. Combustion has been field tested in induced frac-tures11,12 and at oil/water interfaces.13 Alternatively, interwell communication might be achieved by reverse combustion14 or electrolinking. Preheating also could be performed by extensive steam stimulation or electrical techniques. The cost of the preheating phase might limit its duration to the minimum extent necessary to begin a displacement process.

The ultra-low sulfur diesel (ULSD) is required to comply with stricter government policy on low sulfur content of transportation fuels. Better knowledge of the different factors that concern deep desulfurization of fuels is necessary to achieve ultra-low sulfur content and cheaper way of producing ULSD. Both the capital and operating cost of the adsorptive desulfurization process is cheaper compare to the conventional hydroprocessing. In the future, the need to produce more volume of fuels with very low sulphur content from low-grade feedstocks like heavy oil and light cycle oil in order to meet up with the global demand for sulphur-free fuels is pertinent. Several on-going researches are pointing to the use of adsorbents for removal of sulfur compounds from hydrocarbon refining stream. In this chapter, varieties of carbon nanomaterials suitable for adsorptive desulfurization are discussed. If the active lifetime, where the capacity of the adsorbents are adequate, the approach is practically feasible for commercial application.

Low temperature oxidation characteristics analysis of ultra-heavy oil by thermal methods

Three Alberta lawyers, representing different corporate entities in the oil and gas industry, discuss the approach to and treatment of technology de veloped in relation to oil sands, heavy oil and frontier exploration activ ities. Part One provides an introduction to some of the legal challenges created by new developments in resource technology, and examines the experience of Petro-Canada in its frontier operations. Part Two focusses upon the Syncrude project, and the unique problems to which it has given rise. Part Three discusses the role of the Alberta Oil Sands Technology and Research Authority.

Published in Petroleum Transactions, AIME, Volume 213, 1958, pages 236–244. Abstract Results of a field research project on the thermal recovery of oil by movement of a combustion front are presented. This field test was conducted in the South Belridge field, Calif. The test pattern was a single 2.5-acre five-spot pattern in the 700-ft deep Tulare sand. Results of this project indicate the technical feasibility of producing high viscosity, low-gravity crude oils by thermal means. It was demonstrated that heavy oils could be moved rapidly over considerable distances by thermal drive, and that high percentage recoveries of oil could be effected. The bulk of the oil recovery came after arrival of the burning front at a production well. However, rapid corrosion and high-temperature failure of conventional pipe and equipment both below and above surface occurred. Stainless steels gave more satisfactory performance under these conditions than did conventional steels. Oxygen was seldom observed in gas from wells ahead of the burning front, and it appears that the front was continuous throughout the life of the experiment. Introduction During late 1953 and early 1954, industry-wide attention was focused on the thermal recovery of oil by movement of a combustion front through an oil zone. Two separate Oklahoma field tests were described in publications by. Kuhn and Koch, and Grant and Szasz. To obtain basic information needed for making engineering and economic appraisals of commercial recovery of heavy oil by this thermal recovery method, a new field research project was started May 31, 1955. Twelve oil companies contributed to this project with General Petroleum Corp. as operator. Since combustion recovery experiments with heavy oils in other areas had been conducted In small patterns, an important purpose of this test was to determine whether the process could be operated in a pattern of near-commercial well spacing. The South Belridge field, located 30 miles north of Taft, Calif., was chosen because its oil sands are similar to many heavy oil sands which typically have low primary recovery and leave a large amount of oil in place. Such fields are not particularly suited for common secondary recovery methods.

Chapter 9 - Thermal Methods of Recovery

This month we will be presenting our fifth year of the one day "Slugging it Out" conference series. Co-sponsored by the Heavy Oil Special Interest Group and the Canadian Heavy Oil Association, this successful series gathers individuals interested in all areas of heavy oil development for an informal and informative brainstorming ession. our theme this year is "Riding the Wave," which we feel is very appropriate given the resurgence in heavy oil activity, primarily due to heavy oil wellhead prices in the $20/bbl range. The conference will be held at the Metropolitan Centre on April 10 and registration information is available by contacting The Petroleum Society office. Now that I've dispensed with the commercial, let's consider the last 12 years of our heavy oil industry. I believe this is my second major price cycle in the heavy oil business. As a production engineer in Lloyminster in 1985, it appeared that all that was required to make money was to get oil out of the ground, by whatever means possible. Wellhead prices for heavy oil were in the $30/bbl range, and economic analysis would support drilling a 20 bopd well. Price forecasts were of the "hockey stick" variety, and the majors were amassing infrastructure to be ready when prices hit $50/bbl. Thermal projects (primarily Cyclic Steam Stimulation) were in full operation predicting 30% recovery of the original oil in place. A conventional vertical primary well was drilled on 40 acre spacing and the rule of thumb recovery factor was 5%. Sand production was a necessary evil that contributed to higher operating costs and could sometimes be mitigated by reducinghe drawdown on your well. Progressive (or as they are more correctly called now Progressing) Cavity Pumps had appeared on the scene, but were generally not accepted as a means of producing heavy oil. The decision by OPEC in early 1986 to recapture market share lost over the years was a dramatic "wake-up" call to our industry. By mid to late 1986, a barrel of heavy oil in Lloydminster was selling for less than $10 and companies were scrambling to minimize the losses. The first to go were the thermal projects as operating costs were typically in excess of $10/bbl. Next, the marginal primary producing wells were shut-in. The human toll was most obvious as the vacancy rate at my apartment complex went from 0.1 % to 30% in a matter of eight months. Throughouthis process, I realized that I had very little understanding of the factors that influenced the pricing of heavy oil, and perhaps it was time to remedy that situation. Pricing for heavy crude is based on a differential to a light sweet crude (usually the Edmonton par price for a 40 API crude) which encompasses differences in quality (density and sulfur content) and the amount of condensate (C5+) required to make up a heavy oil blend suitable for pipelining. A Lloydminster type blend is typically in the order of 22 API and will contain anywhere from 20 – 25% condensate.

Heavy oil—evermore mobile

Canada's oil sands and heavy oil represent a major North American energy source. However, many technological, economic, and environmental challenges must be overcome in order to improve the effectiveness and efficiency required for converting these unconventional oils into clean and high‐quality transportation fuels that meet the ever‐increasing social licence associated with these energy resources. In oil sands bitumen and heavy oil upgrading, and petroleum refining, over 70 % of the processes involve catalysts and catalytic technologies. To advance new catalysts and catalytic technology development for bitumen upgrading and refining, fundamental and applied research has been conducted at CanmetENERGY on hydroprocessing (including catalyst development, reaction mechanism and kinetics, and process/reactor modelling and simulation), fluid catalytic cracking evaluation of bitumen‐derived feedstocks, and other related subjects. In addition, research collaborations have been established and maintained with a number of national and international universities, research organizations, and industrial companies to promote new upgrading and refining technology development. These research efforts have resulted in important impacts on academic R&D and industrial practice for catalytic conversion of Canadian oil sands bitumen and heavy oil. At the same time, reliable technical data and information have been generated to help government agencies in developing and implementing policies and regulations for oil sands development.