Saskatchewan Research Council Research Articles

Improved scatter correction model for high attenuation gamma-ray tomography measurements

In this study a state-of-the-art gamma-ray tomography (GRT) unit was used to measure the solids concentration distributions of high density, high attenuation clay/water/sand slurries in a 4 in. (100 mm) diameter recirculating pipe loop. The presence of neighbouring radiation sources on the GRT results in a scattered radiation contribution to the total intensity measured at each detector. The scattered radiation decreases the signal-to-noise ratio of the measured radiation intensity and introduces error in the measured tomography data and the reconstructed tomograms (Maad et al 2008 Meas. Sci. Technol. 19 6). Because of the high attenuation of the materials being measured, the scatter contribution was a significant fraction of the total radiation measured at each detector. To correct for the scattered radiation contribution in the measurements, a test campaign was undertaken to characterize and model the scattering behaviour of the GRT at the Saskatchewan Research Council. The scattered radiation was measured experimentally from empty pipe, water filled pipe and a number of flowing clay/water/sand slurries at densities ranging from 1206 kg m−3 to 1580 kg m−3. A semi-empirical scatter correction model has been developed which allows the scattered contribution at each detector to be calculated iteratively based on the measured uncorrected attenuated radiation intensity. This article is an extension of the work presented at the 9th World Congress for Industrial Process Tomography (Spelay et al 2018 Proc. 9th World Congress Industrial Process Tomography p 14).

Technology Focus: New-Frontier Reservoirs II (October 2018)

Technology Focus With the recent increase in new-well activity in unconventional reservoirs and the well-factory approach, a natural limitation exists in the capacity for implementing hydraulic-fracturing optimization. An even greater limitation exists with the consideration of stimulating production from existing wells in decline. Great strides have been made in drilling and completion efficiencies and well-cost reduction during the past several years. That focus has been most important in the lower-for-longer oil-price environment we have fought through. Naturally, that focus has, to some extent, limited alteration of initial-stimulation design—for example, with respect to fracture-stage sizes, fracture-spacing optimization, and proppant types and volumes. Furthermore, restimulation of existing wells is not an area that has received as much attention as other areas, and, where it has, the focus has been on simply repeating refracturing with proppant. Remedial chemical-treatment options have not been explored to a significant extent, especially at the field level. Instead, greater attention has been placed on how to make the leap from primary production achieved from initial well completion to field-scale enhanced oil recovery (EOR). The in-between measure of remedial production enhancement in existing wells is largely being skipped. With low primary-recovery rates in unconventional reservoirs and the longer-term development prospects for EOR applications on a fieldwide scale, the potential for accelerated completion optimization in new wells and production-enhancement treatments in existing wells is substantial and perhaps comes with more immediate returns. Along those lines, the first of three papers featured this month addresses the optimization of fracture spacing and penetration ratio in unconventional reservoirs. The other two papers discuss studies related to remedial production and recovery improvement in existing wells—surfactant soak and flowback treatments in oil-bearing formations and solvent treatments for water and condensate blockage in tight formations, respectively. Recommended additional reading at OnePetro: www.onepetro.org. SPE 189805 Dual-Permeability Matrix-Fracture Corefloods for Studying Gasflooding in Tight Oil Reservoirs by Peng Luo, Saskatchewan Research Council, et al. SPE 190214 Underlying Mechanisms of Tight Reservoir Wettability and Its Alteration by Peng Luo, Saskatchewan Research Council, et al. SPE 187542 Limitation of EOR Applications in Tight Oil Formation by Ahmed Mansour, Texas Tech University, et al.

Developments in slurry flow modelling in a historical perspective

AbstractDurand's slurry flow model attempted to find a single formula for sand‐size particles and larger, but Babcock's data showed that a single formula could not apply. A subsequent group of models is based on Wilson's layered force‐balance analysis of slurry flows applied to friction losses and deposition limit. Models based on variants of this analysis include those by Shook and others at the Saskatchewan Research Council (SRC). Early versions of Wilson's model relied on particle fall velocity to find friction losses, but the classical iterative method of finding fall velocity has now been replaced by a direct method. This is based on the shear Reynolds number of the particle, which can be expressed in terms of the better known Archimedes number. Thus, calculations of slurry friction and limit of deposition involve two principal parameters: the Archimedes number and the diameter ratio d/D.

Research and development impact assessment for innovation-enabling organizations

The Saskatchewan Research Council has developed an economic and socio-environmental impact audit process that enables research and technology organizations to use solid, verifiable data to provide a realistic indication of the direct impacts of their research and development work. For direct economic and jobs impacts, the audit methodology has high credibility because the data come directly from the clients, who are the direct users of the organization's services. For government research and technology organizations, these economic impact audit reports and the statistics they contain can be useful for communicating key performance indicators such as the mandate effectiveness, real-world value, and economic return on government investment to all stakeholders. The same methodology could be easily adapted for governments, not-for-profits, or private-sector companies that conduct, fund, or contract research and development.

Verification of the near-wall model for slurry flow

For a number of years , an analytical model of particulate slurry flow has been under development at GIW Industries, USA, while large bodies of experimental data, including concentration profiles, were obtained at the Saskatchewan Research Council, Canada, and other laboratories. The present paper amalgamates information from these sources, showing that the analytic predictions match the observed concentration profiles.

Cold Flow: A Multi-Well Cold Production (CHOPS) Model

Abstract A multi-well cold production (CHOPS) model, developed at the Saskatchewan Research Council, was used in conjunction with a commercial reservoir simulator, to predict the effect of well spacing and in-filling on oil recovery in cold production. The oil and sand production from the Lindbergh/Frog Lake cold production wells was history matched initially. The comparative economics of five different well spacings (10 acre, 20 acre, 40 acre, 60 acre and 80 acre) was estimated. The 20 acre spacing was the most economic overall for heavy oil prices varying between C$251/m3 (C$40/barrel) and C$502/m3 (C$80/barrel). The multi-well model was used to estimate the additional oil recovery from in-fill wells at different in-fill times. In-filling a 40 acre spacing well with 10 acre spacing wells was not economic for a Lindbergh/Frog Lake type of reservoir. In-filling the same well with 20 acre spacing wells was economic at higher oil prices in the C$502/m3 range (C$80/barrel). Introduction The main mechanisms which contribute to the success of the cold production process are solution gas drive and sand production. Maini(1) argued that the greater oil recovery for heavy oil compared to light oil was due to the formation of a gas in oil dispersion which he called "foamy oil." This dispersion would have a greater compressibility which would maintain the reservoir pressure for longer times. Firoozabadi(2), based on a series of solution gas drive experiments performed at reservoir-type oil velocities, attributes the greater oil recovery for heavy oil to a higher critical gas saturation and to reduced gas flow leading to reservoir pressure maintenance. Three basic scenarios were proposed in the literature to explain how sand production leads to greater oil recovery:a limited dilated sand region around the wellbore(3),a dilated sand region around the wellbore with wormholes extending into the formation(4) andonly wormholes extending out into the formation(5, 6). The third scenario can best explain the rapid (within a few hours) travel time of a fluorescein tracer dye between an injector and a producer, observed by Amoco in a tracer test(5). Since the concentration of this dye, which is known to adsorb on the surface of a porous medium, did not change at the producer, Squires(5) concluded that an open (sand-free) channel connected the injector and producer. This observation contradicts scenarios 1 and 2 since these scenarios preclude the existence of an open channel throughout the length of the wormholes. Field engineers have observed that they sometimes lose fluid circulation while drilling into cold produced reservoirs. The location at which fluid loss occurs can help in mapping the wormhole network in the field. For example, when Nexen Inc. drilled two horizontal wells in a field after cold production, they observed lost circulation to neighbouring wells at the locations indicated by the ? marks in Figure 1. These 40 acre spacing cold production wells had produced large quantities of sand.

Produced Fluids Separation Using a Coalescer Column

Abstract A coalescer column —a simple, inexpensive and environmentally friendly technology —successfully removed water from produced heavy oil emulsions. The laboratory study tested the use of the column and the effects of column length, column packing size, temperature, flow rate, demulsifier concentration and water addition. The use of the column improved basic sediment and water (BS&W) values after 4 hours of settling time by an average of 38%. Flowing the emulsions through the column at lower temperatures and much lower demulsifier concentrations matched the results of conventional treating. The results indicated that incorporating a coalescer column into a treatment facility allowed the reduction of demulsifier concentration from 250 ppm to 70 ppm, translating to an annual cost savings of $320,000 to $1,100,000 per battery. The column also promoted faster treating. Water droplets grew by as much as 34%, suggesting that treating time could be sped up by an average of 21% and as high as 80%. Introduction Heavy oil producers have reported that chemical costs represent the highest fraction of their operating expenses. A small survey of battery operators showed that demulsifier concentrations at heavy oil batteries ranged from 200 to 333 ppm (1 L/5 m3 to 1 L/3 m3) in 2001(1). These operators also reported that demulsifier doses were rising; within the last five years, the concentration of demulsifier used to treat a typical heavy oil has risen by 25 to 50% for many reasons. A battery in the heavy oil region can easily spend over $100,000 annually on demulsifying chemicals. The two treating batteries which supplied emulsion samples for this set of experiments were estimated to spend between $400,000 and $1,100,000 every year on such costs. Heating costs are also considerable. Some heavy oil batteries heat their pressurized treating vessels to 130 °C. In addition to the cost of heating, producers are becoming increasingly aware of the importance of reducing greenhouse gas production. An alternate, inexpensive and environmentally friendly technology to help separate oil and water would be highly desirable. One promising separation method is of the passive mechanical type: a coalescer column. Over the past 18 years, the Saskatchewan Research Council (SRC) and the University of Regina have applied this technique to break water-in-oil emulsions(2–8). Whereas our previous work focused on resolving slop oils, this study applied the coalescer column to the treatment of wellhead emulsions. A literature survey on the subject of coalescers and resolving crude oil emulsions is deceptive. A number of researchers use the word coalescer, but apply it to plate separators or pipes with no packing. Our use of the term restricts it to a pipe filled with some sort of porous packing material which aids in the coalescence of dispersed droplets of an emulsion. In their review of the literature on coalescing media, Stocker et al. listed the many types of packing materials that have been tested(9). These fall into the categories of fixed media, granular packing and fiber packing. The materials range from high-tech oleophilic plastic fibers to such exotic packing materials as granulated black walnut shells.

Determining the Most Profitable ASP Flood Strategy for Enhanced Oil Recovery

Abstract While chemical floods have proven technically successful, the high cost of chemicals makes it challenging to develop a costeffective tertiary process. If high interfacial tension (IFT) exists between the oil and water phases, the resulting capillary forces will resist externally applied viscous forces. This could cause the injected water and chemicals to bypass the residual oil and go to waste. The experimental studies presented here include reservoir fluid characterization, IFT measurements, and coreflood tests; all critical elements in designing a cost-effective alkaline/surfactant/ polymer (ASP) injection strategy. Coreflood tests used either sandpacks or composite reservoir cores with a selected medium crude oil. Injected surfactant concentration, slug size, chasing fluid, and residual oil saturation were the varied parameters. The optimal surfactant concentration of 0.15 wt% and slug size of 0.5 pore volume (PV) obtained relatively high oil recovery while maintaining a favourably high displacement efficiency ratio. Incremental recovery was 23 – 41% initial oil-in-place (IOIP) in sandpack tests and about 16% IOIP with reservoir cores. Overall, these coreflood results indicate that ASP flooding is a suitable enhanced oil recovery method for medium oil if the right chemical concentration and slug size are selected. Introduction The use of ASP flooding to recover oil left behind by waterflooding has become more common in recent years. Several significant developments have made ASP flooding a viable option for field enhanced oil recovery (EOR) projects and more attractive than polymer or micellar/polymer flooding. First, because world oil consumption continues to grow while production in many mature fields continues to decline, oil prices are predicted to stabilize above US$20/bbl. Second, newly developed cheaper surfactants have reduced the cost of EOR formulations by 40 to 60%, while maintaining the same high oil recoveries obtained using more expensive surfactants. The incremental cost per barrel of oil produced has been reduced to a reasonable level, between US$1.44 and $5.83(1). Third, chemical flooding can be evaluated in the oil field faster and more economically than in the past using the single-well EOR pilot test and field-scale numerical simulations. Fourth, waterfloods in most mature reservoirs have experienced early water breakthrough and have reached their economic limit. Therefore, oil companies have to consider applying new EOR technologies to increase recovery factors in such fields. The proven medium oil resource in southwest Saskatchewan, estimated at 534.5 × 106 m3, is located in reservoirs characterized by thin pay and shaly sand. Primary and secondary methods have recovered an estimated 25% IOIP from these reservoirs(2) and are nearing their economic limit. There has been little development of this resource by EOR technologies. The Saskatchewan Research Council (SRC) has conducted extensive studies to develop ASP flooding for a selected reservoir- Instow-with reserves of about 22.1 × 106 m3 of medium oil originally in place. Instow field is located in Ranges 18 and 19 of Townships 9 and 10 in southwest Saskatchewan. This moderate- permeability sandstone reservoir (Upper Shaunavon sand at a depth of 1,370 m) was discovered in 1954 and has been waterflooded since 1959.

Coreflood Studies of Tertiary CO2 Flood in Naturally Fractured Midale Formation in Southeast Saskatchewan

Abstract The distinctive geology of the Weyburn and Midale reservoirs has important implications for the design of a CO2 injection process for these fields. They are contained within two distinct zones of the Mississippian Carbonate formation; the tight, high-porosity Marly zone sits on top of the low-porosity Vuggy zone. The latter zone has a higher permeability, and is more extensively fractured vertically, than the Marly zone. These geological features result in a relatively unswept Marly zone after waterflooding. The Marly/Vuggy sequence presents an opportunity for a CO2 flood to take advantage of gravity segregation to recover the large remaining oil target in the Marly zone. A series of coreflood tests were conducted to simulate tertiary CO2 injection in the Marly/Vuggy zones in the Weyburn and Midale reservoirs. Berea cores with different permeabilities were split lengthwise. The halved segments of the core were butted together to represent the Marly and Vuggy zones. Water (in waterflood mode) and CO2 (in tertiary CO2 flood mode) were injected into the bottom high-permeability section of the dualpermeability core. The coreflood results showed that, in the tertiary CO2 flood, CO2 could migrate to and recover the oil from the top low-permeability zone which was poorly swept by the waterflood. Also, the effects on tertiary oil recovery of operating pressure, injection rate, and permeability contrast could be significant. Introduction The Weyburn and Midale reservoirs in southeast Saskatchewan hold light and medium gravity oil in fractured, low permeability Midale Beds. These reservoirs are contained within two distinct zones of the Mississippian Carbonate formation: the tight, highporosity Marly zone sits on top of the low-porosity Vuggy zone. The latter zone has a higher permeability, and is more extensively fractured vertically than the Marly zone. These geological features result in a relatively unswept Marly zone after waterflooding. It is believed that the distinctive geology of these reservoirs has important implications for the design of a CO2 injection process for these fields, i.e., the Marly-Vuggy arrangement of the reservoir offers potential to utilize gravity segregation effects to enhance oil recovery. Numerical analyses(1, 2) of tertiary CO2 injection in these naturally fractured reservoirs showed that CO2 injected into the lower, more permeable Vuggy zone can contact and mobilise a large amount of oil in the Marly, which has remained relatively unaccessed by waterflooding. A coreflood program was designed at Saskatchewan Research Council (SRC) to address the CO2 injection process in Weyburn reservoir and comparable fields. Laboratory core displacement tests were conducted with a dual permeability split Berea core representing the Marly and Vuggy zones of a reservoir. Some preliminary results reported in a previous paper(3) showed that CO2 injected into the Vuggy zone could rise to the upper Marly zone, and that the potential to recover incremental oil by a tertiary CO2 slug flood is high. After the technique of butting the core halves was improved, the several additional tertiary CO2 coreflood tests reported here were performed with Weyburn reservoir fluid at 63 ° C (reservoir temperature) to confirm the previous finding.

Effect of Solution Gas in Oil on CO2 Minimum Miscibility Pressure

Abstract In this study, a rising bubble apparatus (RBA) was used to determine the CO2 MMP for various oils. RBA tests permit direct observation of changes in bubble behaviour and thus offered insight into the phase behaviour for the CO2-reservoir fluid system. The CO2 MMPs were estimated for two Steelman reservoir fluids with a high gas-oil ratio, the partially flashed reservoir fluids, and the dead oils. The composition of solution gas of each partially flashed reservoir fluid was determined and the effects of different gas components were analysed. The MMP was also determined and discussed for Weyburn reservoir fluids which had a low gas-oil ratio with pure and impure CO2. The results of this study demonstrated that the effect of solution gas in oil on CO2 MP could be significant. Furthermore, achieving a miscible CO2 flood (in a reservoir with a Steelman-like reservoir fluid) could be possible at a lower operating pressure than the measured CO2 MMP, by partially depleting the reservoir. This may be the only option for some reservoirs which cannot sustain the relatively high pressure required for achieving miscibility. Introduction Carbon dioxide flooding is a proven oil recovery process(1). Over the last decade, carbon dioxide injection has become the leading enhanced oil recovery (EOR) process for light oils(2). CO2 injection can prolong, by 15 to 20 years, the production life of light oil fields nearing depletion under waterflood, and may recover 15 to 25% of the original oil in place. More than 20 years of field experience of CO2 injection has advanced the CO2 technology. CO2 injection can be introduced gradually and use some of the same equipment currently in place for waterflooding. Saskatchewan's light and medium oil resource, representing nearly 45% of proven reserves, has been on waterflood for over 30 years and is fast approaching its economic limit of production(3). For the light and medium oil reservoirs in Saskatchewan, carbon dioxide or hydrocarbon injection is considered to be the most effective EOR process(4–6). These gases can be injected into the reservoir to develop miscible or immiscible conditions with the oil depending upon the operating pressure. Carbon dioxide is preferred over hydrocarbon gases (e.g., ethane, propane) because it is cheaper, has higher density, and offers environmental benefits by providing storage for CO2 in the reservoir. The Saskatchewan Research Council (SRC) is conducting a comprehensive research program to assess the suitability of miscible CO2 displacement for reservoirs in southeast Saskatchewan and to optimize the field operating procedures. The first step in determining if a field is a viable CO2 flood candidate is to conduct a screening study to provide a reasonable estimate of CO2 injection performance. The minimum miscibility pressure (MMP) is a key parameter used in the assessment. It has been recognized that the CO2 MMP for a reservoir oil depends on the reservoir temperature, oil composition, and the purity of injected CO2. The minimum miscibility pressure increases with increasing reservoir temperature.

A Multi-Offset Vertical Seismic Profiling (VSP) Experiment for Anisotropy Analysis and Imaging

Editors Note Editor's note: The Canadian International Petroleum Conference held June 4 - 8, 2000, featured a Graduate Student Presentation Competition as part of the Petroleum Society's tradition at the Annual Technical Meeting. Graduate students from respected universities across North America competed in these sessions. The objective of the competition was to give participants the opportunity to present highlights of their work to petroleum industry experts from around the world. The presentations were judged on technical content, applicability, and overall presentation quality. Judges included Dr. Nick Mungan, Mungan Petroleum Consultants Ltd.; Dr. Don Towson, IRAP; and Dr. Norman Freitag, Saskatchewan Research Council. A "Best Graduate Student Presentation Award" and two runner-up awards were presented by Don Mallory, chair of the Student Competition, shown here with the 1st Place presentation author, Graziella Grech of the University of Calgary. On behalf of the Petroleum Society, the JCPT is pleased to present Ms. Grech's award winning presentation. Abstract A multi-offset Vertical Seismic Profiling (VSP) experiment was carried out in the Rocky Mountain Foothills of Southern Alberta, Canada. The purpose of this survey was to determine whether the dipping shale strata in the study area exhibit seismic velocity anisotropy, and to obtain an estimate of the error in the imaged location of the target underneath these shales if anisotropy is not taken into account during seismic data processing. Traveltime inversion of the first arrival data from the multioffset VSP has revealed that the shales exhibit velocity anisotropy of about 10%. For a target depth of about 3,000 m and moderate dips of 30 ° to 50 ° in the anisotropic overburden, this may lead to a lateral shift in the imaged location of the target of up to 300 m in the up-dip direction of overlying bedding. The anisotropic parameters derived from this study will also be used in the anisotropic prestack depth migration of the VSP and surface seismic data. FIGURE 1: Interbedded thin layers of sandstone and shale found in the Western Canada Sedimentary Basin. Due to anisotropy, the velocity parallel to bedding (V90) is higher than the velocity perpendicular to bedding (V0). This class of anisotropy is termed Transverse Isotropy. (Photo courtesy D. Spratt) (Available in full paper) Introduction Vertical Seismic Profiling (VSP) and surface seismic data are used to image and locate hydrocarbon targets in the subsurface. It is well established that these depth images depend on the accuracy of the velocity model(1,2). If rocks overlying the target are anisotropic, and if this property is not accounted for during velocity model building and depth imaging, then the final image will be incorrect, hence increasing the risk of dry holes. It is therefore important to determine which formations exhibit seismic velocity anisotropy and quantify their parameters for use during seismic imaging. Seismic Velocity Anisotropy Seismic velocity anisotropy is the change in velocity with the direction in which it is measured. In rocks, it can be caused by the alignment of mineral grains, cracks and crystals in a preferred direction, and by the consecutive layering of thin beds.

Laboratory Investigation of Weyburn CO2 Miscible Flooding

Abstract Weyburn reservoir, located in southeast Saskatchewan and operated by PanCanadian Petroleum Ltd., has reached its economic limit of production by waterflooding. The reservoir is a target for tertiary CO2 miscible flooding to enhance oil recovery and extend its production life. A comprehensive study has been conducted by the Saskatchewan Research Council and PanCanadian to assess the suitability of the process for Weyburn. This paper presents a technical evaluation of CO2 near-miscible injection for Weyburn reservoir. This is based on laboratory studies conducted with three Weyburn oils collected from different regions of the reservoir. These studies included:measurement of minimum miscibility pressure for the reconstituted reservoir fluids for pure and impure CO2,determination of PVT properties for reservoir fluid-CO2 mixtures, andassessment of recovery behavior from uniquely designed laboratory core-flood tests representing the permeability contrast of the reservoir. The studies indicated that the CO2 minimum miscibility pressure for the Weyburn reservoir oils varied from about 11.5 to 14.5 MPa, indicating suitability for CO2 miscible flooding. PVT data generated for the three Weyburn reservoir fluid-CO2 mixtures showed that viscosity reduction and oil swelling by CO2 also contributed to oil recovery. A slight manipulation of the measured PVT properties of the mixtures made it possible to obtain single property curves for the three Weyburn oils. This feature can be used to estimate the PVT behavior for any Weyburn oil from the reservoir. Core-flood studies showed that CO2 injected into the Vuggy zone could rise to the upper Marly zone and help enhance oil recovery. A separate simulation and modelling study conducted by PanCanadian Petroleum Ltd. satisfactorily matched the experimental PVT properties, MMP values and recovery mechanism suggested by the core-flood behaviour. Introduction The total oil reserves of Saskatchewan are estimated at over 3 billion m3 of initial oil-in-place (IOIP). The light and medium oil reserves contribute approximately 1.6 billion m3 IOIP(1). Over 10﹪ of the light and medium reserves, or 178 million m3 IOIP, are held in Weyburn reservoir. The Weyburn field is located approximately 130 km southeast of Regina in Saskatchewan and covers over 180 km2 of production area. The field was discovered in 1955 and PanCanadian Petroleum (PCP) Ltd. is the major operator. It has over 627 producing wells and 162 water injection wells on approximately 24 ha spacing(2). The oil production from the Weyburn field comes from Midale beds of the Mississippian Charles Formation in the Williston Basin at a depth of 1,310 to 1,500 m. The field was produced by primary depletion for about nine years until 1964. Waterflood was started thereafter using a nine-spot pattern. In 1985, to optimize the waterflood performance, both horizontal and vertical infill drilling programs were initiated. The combined oil recovery by primary and secondary production was approximately 28﹪ IOIP by 1994. Waterflooding has almost reached its economic limit for the Weyburn reservoir. The ultimate conventional recovery is expected to be 31﹪ IOIP, leaving a large target for tertiary recovery techniques(3). A similar situation exists for the majority of Saskatchewan's light and medium reservoirs(1,4).

Surface mesonet for BOREAS

This paper describes the mesonet sensor equipment installed by the Saskatchewan Research Council (SRC) for the Boreal Ecosystem‐Atmosphere Study (BOREAS) project as well as the data collection methods and modifications made to overcome environment‐related problems. The surface mesoscale atmospheric sciences mesonet for BOREAS is made up of 10 meteorological monitoring sites in western Canada designed to complement the two intensive sites for the BOREAS project. All stations monitored the atmosphere continuously from the start of the project in early 1994 to the end of the project in 1996. One site within the mesonet, the Saskatchewan Research Council's Climatological Reference Station, had over three decades of records. The BOREAS years of 1994 and 1995 had warmer air temperatures than normal; the year 1994 was 0.7°C above the long‐term annual average.

Technical Feasibility of CO2 Flooding in Weyburn Reservoir - A Laboratory Investigation

Abstract Miscible or near-miscible flooding with CO2 or hydrocarbon gases will significantly increase, and extend the production life of, Saskatchewan light and medium oil reserves. These pools are approaching their economic limit of production under conventional technology (primary and secondary recovery methods). Responding to industry needs, a comprehensive study by Saskatchewan Research Council is assessing the suitability of the CO2 flooding process for reservoirs in southeast Saskatchewan. This paper presents the details of a laboratory study to evaluate the applicability of CO2 flooding for a southeast Saskatchewan reservoir, Weyburn. The evaluation is based on the measurement of CO2 minimum miscibility pressure for the Weyburn reservoir fluid, of PVT properties for reservoir fluid CO2 mixtures, and of oil recovery behaviour from core flood tests conducted in the near-miscible region. Laboratory studies showed that the tertiary CO2 injection at over 12 MPa into the waterflo'oded reservoir is expected to produce miscible flooding conditions. At this pressure of injection, over 60 mol % CO2 was dissolved in the reservoir fluid. This reduced the viscosity of the fluid nearly fourfold to 0.70 mPa.s and swelled the oil about 45%. Coreflood studies indicated that the microscopic displacement efficiency of the process increased with injection pressure in the near-miscible region. It is believed that the geology of the Weybum reservoir will prove advantageous for near-miscible operation. However, this aspect needs to be further investigated. Introduction Most of Saskatchewan's light and medium oil (LMO) reservoirs have reached their economic limit of production under conventional technology. Primary and secondary methods together recover about 21% of the initial oil-in-place (IOlP). Although the remaining light and medium oil-in-place in Saskatchewan is 1,373 million cubic metres(1) the remaining reserves producible under primary and secondary recovery are only 59 million cubic metres. This latter number would rise by 20 million cubic metres if medium oil in southwest Saskatchewan, not considered here, were included(1). The development of tertiary recovery techniques is, therefore, essential to increase the production life of these reservoirs and to maintain current production. Application of the miscible or near miscible oil displacement process using CO2, hydrocarbon or other gases as injection fluids is expected to increase the LMO reserves threefold and extend the production life of these pools by two decades(2). Miscible (or near-miscible) flooding with carbon dioxide or hydrocarbon solvents is considered to be one of the most effective enhanced oil recovery (EOR) processes applicable to LMO reservoirs. A comparison of effectiveness of CO2 and hydrocarbon gases as miscible solvents has been discussed(3). CO2 floods minimize gravity segregation compared with the hydrocarbon solvents. In addition, CO2 generally costs less than hydrocarbon miscible solvents in the United States(3). There is a limited supply of CO2 in Saskatchewan and Alberta for EOR purposes. However, CO2 can be imported from the U.S. to be implemented in miscible displacement projects in Canada. Current industry interest in CO2 miscible flooding is high, as evidenced by the growing level of activity in field testing(4) and increasing production from this method worldwide.

Pipeline Flow of Gas, Liquid And Sand Mixtures At Low Velocities

Abstract Experiments have been conducted to investigate the ability of gas-liquid mixtures to transport sand in a horizontal pipe or well at low velocities. Both laminar and turbulent liquid flow regimes! were investigated. The gas-containing flows were predominant1y in the slug regime. Sand transport rates in laminar oil flows were very low until the axial pressure gradient exceeded 1.5 kPaim. Gas addition did not improve this performance. With turbulent liquid flows, sand transport rates at low velocities could be estimated by the Meyer-Peter equation as long as the sand particle diameter exceeded 0.1 mm. As the gas flowrate increased, sand transport rates eventually exceeded these predictions because of mixing caused by passage of the slugs. Axial pressure gradients for turbulent gas-liquid-sand mixtures could be estimated from the Lockhart-Martinelli correlation. Introduction Horizontal wells are of growing importance in petroleum production in Western Canada and the flow within these wells have been under investigation at the Saskatchewan Research Council since 1990. Experimental studies have been conducted with the goal of defining the approaches to be taken in mechanistic modelling of wellbore flows of allldnds. Since as many as four phases (oil, water, gas and sand) may be present, a systematic investigation of gradually increasing complexity has been undertaken. In the first investigation, the effects of radial influx at a slotted section of wellbore were examined(1). Axial pressure gradients for single phase flows were shown to be predictable from the known laws of laminar and turbulent flow. No additional complications such as turbulence generation were detected in the experiments. When a stationary sand layer was present, the ability of the influx to mobilize the sand could be explained in terms of concepts defmed by previous studies of liquid-solid fluidization. Thus over a wide range of experimental conditions, a horizontal well with fluid influx resembles a horizontal pipe whose flowrate increases with distance downstream. A second investigation(2) studied the ability of a turbulent (water) flow to transport sand at low velocities above a stationary deposit. A threshold velocity for sand transport was observed and at at velocities just above the threshold, the flow resembled that which occurs in channels with stationary bottom deposits. Very fine particles, 0.01 mm in diameter, were uniformly distributed in the flow by the turbulence. In this case pressure gradients and sand transport rates could be predicted rather easily by treating the sand-liquid mixture as a pseudo-liquid. The transport rates for sands of diameter 0.2 and 0.1 mm could be predicted from the empirical Meyer-Peter equation(3) which is known to describe channel sediment transport. However this equation was completely unsatisfactory for very fine (0.01 mm) particles. At higher velocities, but with a stationary deposit still present, pressure gradients and solids throughputs could be predicted from a three layer model which was derived from the two layer model which is known to describe well the flow of slurries in deposit-free pipelines(4). The transition from the mechanistic layer model regime to the Meyer-Peter regime seemed to occur where dune formation in the stationary layers became predominant.

A Laboratory Evaluation of Suitable Operating Strategies For Enhanced Heavy Oil Recovery By Gas Injection

Abstract A majority of Saskatchewan's heavy oil reservoirs are thin and marginal, unsuited for thermal recovery methods. The immiscible CO2 or gas displacement process appears to be a very promising enhanced oil recovery technique for these heavy oil reservoirs. This process, if proven applicable, will access 90% of the initial-oil-in-place. Since an inexpensive source or CO2 is not available in Saskatchewan/Alberta, alternative gases containing CO2 can be used. This paper discusses results of a laboratory study carried out by Saskatchewan Research Council (SRC) to assess the suitability of a flue gas containing 85 mol% N2 and 15 mol% CO2, and to evaluate various operating strategies for heavy oil recovery. The test heavy oil (14 º API gravity) was collected from Senlac reservoir located in the Lloydminster area. The study investigated the effect on oil recovery of drive type (secondary vs. tertiary), injection mode (slug test vs. water- alternating-gas [WAG] flood), oil type (Senlac live oil vs. dead oil), and injection gas (flue gas vs. CO2). Results of one-dimensional linear coreflood tests (conducted at 28 ºC, 2.5–2.7 MPa) with Senlac oil-flue gas led to four major conclusions. (1) The secondary gas slug flood with live oil was the most suitable injection strategy for heavy oil recovery from among three different injection strategies (secondary slug, tertiary slug, and tertiary WAG) investigated because this flood had the highest displacement efficiency; (2) The tertiary WAG process recovered more oil than the tertiary slug process because the former predominantly improved mobility control; (3) Ultimate oil recovery was higher in runs conducted using live oilthan in those using dead oil. This is attributed to the relatively more favourable mobility of live oil and slightly higher operating pressure (2.7 MPa instead of 2.5 MPa) in live oil runs; (4) Flue gas appeared to be an effective flooding agent, since the oil recoveries were only 2 to 4 percentage points lower than those obtained with CO2, Comparable oil recoveries in flue gas runs were believed to be a combined result of two competing mechanisms -a free gas mechanism provided by N2 and a solubilization mechanism provided by CO2 in contrast to the solubilization mechanism (provided by CO2) which predominates in CO2 floods. Introduction In Canada, Alberta and Saskatchewan account for nearly all of the proven heavy oil resource. In Saskatchewan alone, l.5 billion m3 of proven and 3.4 billion m3 of probable heavy oil reserves exist,(2) over 62% of the total resource(1).. These reservoirs are, however, characterized by thin pay, shaly sand, heterogeneity, low roductivity, and bottomwater(3, 4). Of the province's proven initial heavy oil-in-place, 97% is contained in reservoirs less than 10 m pay zone, and 55% in reservoirs less than 5 m thick(5, 6). Primary and secondary methods combined recover only about 7% of the initial-oil-in-place (IOIP) of the proven resource(2). In comparison, such conventional techniques can access, on average, about 22% of the proven 0.43 billion m3 of medium oil. The remaining heavy and medium oil resources of Saskatchewan offer potential for exploitation by tertiary recovery techniques.

Hydroprocessed vegetable oils for diesel fuel improvement

The Saskatchewan Research Council (SRC), in cooperation with Natural Resources Canada and Agriculture and Agri-Food Canada, investigated the use of conventional refinery technology to convert vegetable oils into a product resembling diesel fuel. SRC found that the use of a medium severity refinery hydroprocess yielded a product (‘super cetane’) in the diesel boiling range with a high cetane value (55–90). Preliminary engine testing by ORTECH has shown that the impact of the ‘super cetane’/diesel mixture (‘green diesel’) on engine emissions is similar to the impact cetane enhancement via a nitrate additive has when added to conventional diesel fuel. Advantages of hydroprocessing over esterification in the Canadian context include lower processing cost, compatibility with infrastructure, engines and fuel standards, and feed stock flexibility. Further research in the areas of process optimization, alternative feed stock selection, cold flow properties, and multi-cylinder emission testing is planned. In cooperation with a commercialization partner, Arbokem Inc., pilot testing of the hydroprocess was done and was proven successful. A fleet demonstration and evaluation is currently underway.

Oil, Water And Sand Flow Experiments In a Model H(Jlrizont~d Well

Abstract An experimental investigation has been conducted using a 52 mm laboratory test loop incorporating a section of pipe with longitudinal well slots. Single phase flows with radial and axial flow confirmed the validity of a one dimensional model in predicting pressure gradients for both laminar and turbulent flow. No additional turbulence resulting from the influx could be detected. Experiments using an oilfield sand of median diameter 0.22 mm and either produced water or an oil of viscosity 66 mPa.s showed that there was a threshold velocity for sand transport to occur. Stationary deposits of sand were present at velocities well above the threshold velocity. For sand transport in turbulent flow, the Meyer-Peter equation predicted transport rates as functions of water velocity fairly well at low velocities. The laminar flow pressure drop and sand transport results were quite different from the turbulent flow results. They were also different far the two oils; in neither case was a homogeneous flow model found to be appropriate. For flow with stationary sand deposit, radial influx appeared to reduce axial pressure gradients when the sand in the deposit was fluidized by the influx. Injection of water into the heavy oil containing sand showed that some of the sand was washed out of the oil by the water. The water appeared to migrate to form bubbles near the axis of the pipe, leaving the wall oil-wet. High water cuts and low pressure gradients resulted from water injection. Introduction Although horizontal well were first used more than 50 years ago, they were impractical before the recent developments in drilling and completion had taken place. The number of horizontal well in Saskatchewan has increased markedly, so that it appears they will become the standard production technique by the end of the century. In an attempt to contribute to the application of the method to the heavy oil reservoirs of Western Canada. a five-year multidisciplinary study of the reservoir engineering aspects of horizontal wells has been undertaken by the Saskatchewan Research Council. The project was initiated in 1990 with support from several producing companies and agencies of the governments of Canada. Alberta and Saskatchewan. The research reported herein Consists of a first attempt to examine the flow in a horizontal well in conditions likely to be of interest in reservoir modelling. In order for fluid to flow in a horizontal well there must be a pressure decrease in the downstream direction. If the velocity in the wellhore is very low this pressure gradient may be negligible compared to the pressure difference between tile reservoir and the well. However with thin reservoir and underlying water this may not be the case. The effect of the axial pressure gradient On production was predicted theoretically by Dikken (1990) using a homogeneous fluid model and assuming smooth pipe flow in the wellbore. The complication of multiphase wellbore now were recognized by Stone el al. (1989) who adapted the well-known steam water model RELAP5/MODI (Ranson et al 1982) to the case of flow in a horizontal well.

Quantification of Asphaltene Flocculation During Miscible CO2 Flooding in the Weyburn Reservoir

Abstract In a CO2 miscible displacement process, asphaltenes from the oil can flocculate in the presence of CO2 and can cause numerous production problems with a detrimental effect on oil recovery. A five-year multiclient research project was initiated in 1988 to evaluate the suitability of CO2 as an enhanced oil recovery (EOR) agent for a southeast Saskatchewan reservoir, Weyburn. The initial asphaltene content of the oils collected from the Weyburn pool was about 5% and suggested the possibility of formation plugging and wettability alteration during a CO2 injection. A laboratory study using a prototype high pressure PVT cell was undertaken to quantify asphaltene flocculation during a CO2 miscible flood in the Weyburn field. A photo metric technique was developed to determine the asphaltene content of the flashed CO2-saturated test oils. The effect on the asphaltene flocculation of operating pressure, CO2 oil contact; time, CO2 concentration, gas contaminants such as N2 and CH4' in CO2, and the presence of formation brine was investigated for; three different oil samples (approximately 29 ºAPI) collected from the pool. Results of the study indicated that asphaltene began to flocculate at about 42 mol% CO2 concentration. After this onset, there was a linear increase in asphaltene flocculation with CO2 concentration. The asphaltene flocculation pattern seemed to be, relatively insensitive to the operating pressure in the pressure range studied. The normalized asphaltene flocculation data showed a negligible effect of brine and contaminants in CO2 tested. For the experiments conducted in the single-phase region) the effect of CO2 oil contact time on asphaltene flocculation during the 4–19 day period was negligibly small. However, the mixing time required to achieve equilibrium in the two-phase' region was significant. Introduction The majority of the Saskatchewan light and medium oil (LMO) reservoirs have reached their economic limit of production under current technology (primary and secondary recovery methods)(1). Miscible flooding with carbon dioxide is shown to be a promising enhanced oil recovery (EOR) technique for southeast Saskatchewan reservoirs (2). Recent research suggests that near miscible (or extremely low interfacial tension) CO2 flooding can result in highly efficient displacement(2). A study(4) undertaken by Saskatchewan Energy and Mines has shown that the successful development of the miscible (or near-miscible) displacement process using CO2 and hydrocarbon gases can lead to a significant increase in Saskatchewan LMO reserves and substantially extend the production life of these pools. Crude oil normally consists of a conglomeration of waxes, resins, asphaltenes, and other semisolid materials. Because of their different physical and chemical characteristics, and when subjected to slight changes in equilibrium conditions, paraffins, resins and asphaltenes often precipitate. One of the problems confronting researchers and field operators is asphaltene deposition during a CO2 miscible flood. This concern with asphaltene deposition and problems arising from it during CO2 miscible flooding was one aspect of a comprehensive five-year multiclient research project(5). It was started in 1988 at the Saskatchewan Research Council (SRC) to evaluate the suitability of CO2 as an EOR agent for a southeast Saskatchewan reservoir, Weyburn.

Phase Behaviour And Scaled Model Studies of Prototype Saskatchewan Heavy Oils With Carbon Dioxide

Abstract Non-thermal enhanced oil recovery (EOR) techniques show good potential for recovering oils from the thin and shaly heavy oil reservoirs of Saskatchewan. Among the non-thermal processes, immiscible carbon dioxide injection holds the most promise of accessing these reservoirs. This technique, however, is much less developed than thermal methods. The process, if proven applicable to Saskatchewan reservoirs between three and seven metres thick, will access approximately 90% of the total oil-in-place. Considering the above, a multi-client experimental research program was initiated at the Saskatchewan Research Council. The objective of this research program is to evaluate various solvents in the context of the heavy oil resource and to investigate displacement mechanisms associated with immiscible gas injection processes. This paper is divided into two sections. The first deals with the characterization of a Kindersley area heavy oil The characterization includes analysis of stock-tank oil with and without additives, recombined reservoir fluid, and reservoir fluid plus carbon dioxide. The second section describes a scaled physical model and two displacement experiments conducted using a Lloydminster area heavy oil. The laboratory phase behavior data were generated to show the effect of pressure and temperature on carbon dioxide solubility, oil density and viscosity, compressibility, and swelling factors. The addition of 73.1 sm3/m3 of carbon dioxide at 7 MPa reduced the viscosity of the reservoir fluid at 25.5 °C from 819 mPa •s to 45 mPa •s, an eighteen-fold reduction. The same reduction in viscosity by thermal methods would require healing the sample to approximately 80 °C. The above oil under similar conditions, increased in density from 963.0 kg/m3 to 974.3 kg/m3 and swelled approximately 15%. Two scaled model experiments (secondary displacements) were conducted using a 10-cycle water-alternating-gas (WAG) process with a WAG ratio of 4: 1. In each run, the total mass of carbon dioxide injected was1.41 g •mole (0.53 PV at 2.5 MPa, 0.30 PV at 4. 1 MPa). These displacements indicated the immiscible carbon dioxide WAG process to be partially sensitive to the operating pressure in the range of study. More important is the relative volume of carbon dioxide, at experimental conditions, which dictates overall performance. Introduction Carbon dioxide flooding to be the primary non-thermal recovery process that hold promise of allowing access to the typically thin reservoirs in which most of Saskatchewan's heavy oil is found. Thermal methods are often inefficient and uneconomical because of excessive vertical heat losses, due to thin pay zones, and steam-scavenging by bottom water zones. Carbon dioxide may behave as a miscible or immiscible fluid when contacted with oil at reservoir conditions. For petroleum reservoirs, Holm(1) defines miscibility as that physical condition between two or more fluids that will permit them to mix in all proportions without the existence of an interface. If two or more fluid phases form after some amount of one fluid is added to others, the fluids are considered immiscible and an interfacial tension exists between the phases. Therefore, miscible displacement may not be applicable to all reservoir fluids.