CA2893552A1 - Treating oil sand tailings - Google Patents

Abstract

A method of treating oil sand tailings including passing the tailings through a pipe having a length, and producing treated tailings by adding an agglomerating polymer at multiple locations along the length of the pipe to disperse the polymer into the tailings.

Description

TREATING OIL SAND TAILINGS
BACKGROUND
Field of Disclosure [0001] The disclosure relates generally to the field of treating oil sand tailings.
Description of Related Art

[0002] This section is intended to introduce various aspects of the art, which may be associated with the present disclosure. This discussion is believed to assist in providing a framework to facilitate a better understanding of particular aspects of the present disclosure.
Accordingly, it should be understood that this section should be read in this light, and not necessarily as admissions of prior art.

[0003] Modern society is greatly dependent on the use of hydrocarbon resources for fuels and chemical feedstocks. Hydrocarbons are generally found in subsurface formations that can be termed "reservoirs". Removing hydrocarbons from the reservoirs depends on numerous physical properties of the subsurface formations, such as the permeability of the rock containing the hydrocarbons, the ability of the hydrocarbons to flow through the subsurface formations, and the proportion of hydrocarbons present, among other things.
Easily harvested sources of hydrocarbons are dwindling, leaving less accessible sources to satisfy future energy needs. As the costs of hydrocarbons increase, the less accessible sources become more economically attractive.

[0004] Recently, the harvesting of oil sand to remove heavy oil has become more economical. Hydrocarbon removal from oil sand may be performed by several techniques.
For example, a well can be drilled to an oil sand reservoir and steam, hot air, solvents, or a combination thereof, can be injected to release the hydrocarbons. The released hydrocarbons may be collected by wells and brought to the surface. In another technique, strip or surface mining may be performed to access the oil sand, which can be treated with water, steam or solvents to extract the heavy oil.

[0005] Extracting bitumen from mined oil sand produces tailings comprising solids, water, and small amounts of unrecovered bitumen. It is desirable to increase the solids content of these tailings to assist reclamation.

[0006] Certain oil sand extraction processes are described below to illustrate how certain oil sand tailings may be formed. However, these descriptions are by no means exhaustive of the ways in which oil sand tailings may be generated.

[0007] Oil sand extraction processes are used to liberate and separate bitumen from oil sand so that the bitumen can be further processed to produce synthetic crude oil or mixed with diluent to form "dilbit" and be transported to a refinery plant. Numerous oil sand extraction processes have been developed and commercialized, many of which involve the use of water as a processing medium. Where the oil sand is treated with water, the technique may be referred to as water-based extraction (WBE). WBE is a commonly used process to extract bitumen from mined oil sand. Other processes are non-aqueous solvent-based processes. An example of a solvent-based process is described in Canadian Patent Application No.
2,724,806 (Adeyinka et al, published June 30, 2011 and entitled "Process and Systems for Solvent Extraction of Bitumen from Oil Sands"), which is incorporated herein by reference.
Solvent may be used in both aqueous and non-aqueous processes.

[0008] One WBE process is the Clark hot water extraction process (the "Clark Process"). This process typically requires that mined oil sand be conditioned for extraction by being crushed to a desired lump size and then combined with hot (e.g. 95 C) water and perhaps other agents to form a conditioned slurry of water and crushed oil sands. In the Clark Process, an amount of sodium hydroxide (caustic) may be added to the slurry to increase the slurry pH, which enhances the liberation and separation of bitumen from the oil sand. Other WBE processes may use other temperatures and may include other conditioning agents, which are added to the oil sands slurry, or may operate without conditioning agents.
This slurry is first processed in a Primary Separation Cell (PSC), also known as a Primary Separation Vessel (PSV), to extract the bitumen from the slurry.

[0009] An overall bitumen extraction process is depicted in Fig. 1. The water and oil sand slurry (100) is separated into three major streams in the PSC (101):
bitumen froth (102), middlings (104) and PSC underflow (106). Further processing of each of these streams is explained below. Also shown in Fig. 1, is the solvent (108) added for froth treatment (110), bitumen (112), TSRU (tailings solvent recovery unit) tailings (114), flotation cells (116), recycle bitumen froth (118), flotation tailings (FT) (120), and an external tailings area (ETA) (122).

[0010] Regardless of the type of WBE process employed, the process will typically result in the production of a bitumen froth (102) that requires treatment with a solvent. For example, in the Clark Process, a bitumen froth stream comprises bitumen, solids, and water.
Certain processes use naphtha to dilute bitumen froth before separating the product bitumen by centrifugation. These processes are called naphtha froth treatment (NFT) processes. Other processes use a paraffinic solvent, and are called paraffinic froth treatment (PFT) processes, to produce pipelineable bitumen with low levels of solids and water. In the PFT
process, a paraffinic solvent (for example, a mixture of iso-pentane and n-pentane) is used to dilute the froth before separating the product, diluted bitumen, by gravity. A portion of the asphaltenes in the bitumen is also rejected by design in the PFT process and this rejection is used to achieve reduced solids and water levels. In both the NFT and the PFT
processes, the diluted tailings (comprising water, solids and some hydrocarbon) are separated from the diluted product bitumen.

[0011] Solvent is typically recovered from the diluted product bitumen component before the bitumen is delivered to a refining facility for further processing.

[0012] One PFT process will now be described further, although variations of the process exist. The PFT process may comprise at least three units: Froth Separation Unit (FSU), Solvent Recovery Unit (SRU) and Tailings Solvent Recovery Unit (TSRU).
Two FSUs may be used, as shown in Fig. 2.

[0013]
With reference to Fig. 2, mixing of solvent with the feed bitumen froth (200) is carried out counter-currently in two stages: FSU-1 and FSU-2, labeled as Froth Separation Unit 1 (202) and Froth Separation Unit 2 (204). The bitumen froth comprises bitumen, water, and solids. A typical composition of bitumen froth is about 60 wt. % bitumen, 30 wt. % water, and 10 wt. % solids. The paraffinic solvent is used to dilute the froth before separating the product bitumen by gravity. Examples of paraffinic solvents are pentane or hexane, either used alone or mixed with isomers of pentanes or hexanes, respectively. An example of a paraffinic solvent is a mixture of iso-pentane and n-pentane. In FSU-1 (202), the froth (200) is mixed with the solvent-rich oil stream (201) from the second stage (FSU-2) (204). The temperature of FSU-1 (202) is maintained at, for instance, about 60 C to about 80 C, or about 70 C, while the solvent to bitumen (SB) ratio may be from 1.4:1 to 2.2:1 by weight or may be controlled around 1.6:1 by weight for a 60:40 mixture of n-pentane: iso-pentane. The overhead from FSU-1 (202) is the diluted bitumen product (205) (also referred to as the hydrocarbon leg) and the bottom stream from FSU-1 (202) is the tailings (207) comprising water, solids (inorganics), asphaltenes, and some residual bitumen. The residual bitumen from this bottom stream is further extracted in FSU-2 (204) by contacting it with fresh solvent (209), for instance, in a 25 to 30:1 (w/w) SB ratio at, for instance, about 80 C to about 100 C, or about 90 C. Examples of operating pressures of FSU-1 and FSU-2 are about 550 kPag and 600 kPag, respectively. The solvent-rich oil (overhead) (201) from FSU-2 (204) is mixed with the fresh froth feed (200) as mentioned above. The bottom stream from FSU-2 (204) is the tailings (211) comprising solids, water, asphaltenes and residual solvent, which is to be recovered in the Tailings Solvent Recovery Unit (TSRU) (206) prior to the disposal of the tailings (213) in an ETA. The recovered solvent (218) from TSRU (206) is directed to the makeup solvent (209). Solvent from the diluted bitumen overhead stream (205) is recovered in the Solvent Recovery Unit (SRU) (208) and passed as solvent (217) to Solvent Storage (210). Bitumen (215) exiting the SRU (208) is also illustrated. The foregoing is only an example of a PFT process and the values are provided by way of example only.
An example of a PFT process is described in Canadian Patent No. 2,587,166 to Sury, which is incorporated herein by reference.

[0014] As depicted in Fig. 1, the PSC underflow (106) from the PSC (101) is sent to an External Tailings Area (ETA) (122). The PSC underflow (106) is a coarse stream and is typically used as a building material at the ETA to contain tailings ponds of tailings with lower solids content.

[0015] Paraffinic froth treatment (PFT) tailings (for example TSRU
tailings stream (213)) may comprise both coarse and fine particles and is sent for further treatment or disposed in an ETA.

[0016] As depicted in Fig. 1, from the PSC (101), the middlings stream (104), comprising bitumen and about 10-30 wt. % solids, or about 20-25 wt. % solids is withdrawn and sent to the flotation cells (116) to further recover bitumen. The middlings (104), comprising bitumen, solids and water are processed by bubbling air through the slurry and creating a bitumen froth (118), which is recycled back to the PSC (101). The flotation tailings (FT) (120) from the flotation cells (116), comprising mostly solids and water, are sent for further treatment or disposed in an ETA.

[0017] In ETA tailings ponds, a liquid suspension of oil sand fines in water with a solids content greater than 2 wt. %, but less than the solids content corresponding to the Liquid Limit are called Fluid Fine Tailings (FFT). FFT settle over time to produce Mature Fine Tailings (MFT), having above about 30 wt. % solids. Further densification to a solid state can be very slow.

[0018] It would be desirable to have an alternative or improved method of treating oil sand tailings.
SUMMARY

[0019] It is an object of the present disclosure to provide methods of treating oil sand tailings.

[0020] Disclosed is a method of treating oil sand tailings including passing the tailings through a pipe having a length, and producing treated tailings by adding an agglomerating polymer at multiple locations along the length of the pipe to disperse the polymer into the tailings.

[0021] The foregoing has broadly outlined the features of the present disclosure so that the detailed description that follows may be better understood.
Additional features will also be described herein.
BRIEF DESCRIPTION OF THE DRAWINGS

[0022] These and other features, aspects and advantages of the disclosure will become apparent from the following description, appending claims and the accompanying drawings, which are briefly described below.

[0023] Fig. 1 is a flow diagram of a prior art process for extracting bitumen from mined oil sand.

[0024] Fig. 2 is a flow diagram of a prior art paraffinic froth treatment process.

[0025] Fig. 3A is a schematic of a T-junction delivery system.

[0026] Fig. 3B is a schematic of a T-junction delivery system.

[0027] Fig. 3C is a schematic of a T-junction delivery system.

[0028] Fig. 4 is a flow chart of a method of treating oil sand tailings.

[0029] Fig. 5A is a schematic of a delivery system.

[0030] Fig. 5B is a schematic of a delivery system.

[0031] Fig. 5C is a schematic of a delivery system.

[0032] Fig. 6 is a flow chart of a method of delivering an agglomerating polymer to a flowing tailings stream.

. .

[0033] Fig. 7 is a flow chart of method of retrofitting a pipe for carrying a tailings stream with an agglomerating polymer injection system.

[0034] It should be noted that the figures are merely examples and no limitations on the scope of the present disclosure are intended thereby. Further, the figures are generally not drawn to scale, but are drafted for purposes of convenience and clarity in illustrating various aspects of the disclosure.
DETAILED DESCRIPTION

[0035] For the purpose of promoting an understanding of the principles of the disclosure, reference will now be made to the features illustrated in the drawings and specific language will be used to describe the same. It will nevertheless be understood that no limitation of the scope of the disclosure is thereby intended. Any alterations and further modifications, and any further applications of the principles of the disclosure as described herein are contemplated as would normally occur to one skilled in the art to which the disclosure relates. It will be apparent to those skilled in the relevant art that some features that are not relevant to the present disclosure may not be shown in the drawings for the sake of clarity.

[0036] At the outset, for ease of reference, certain terms used in this application and their meaning as used in this context are set forth below. To the extent a term used herein is not defined below, it should be given the broadest definition persons in the pertinent art have given that term as reflected in at least one printed publication or issued patent. Further, the present processes are not limited by the usage of the terms shown below, as all equivalents, synonyms, new developments and terms or processes that serve the same or a similar purpose are considered to be within the scope of the present disclosure.

[0037] Throughout this disclosure, where a range is used, any number between or inclusive of the range is implied.

[0038] A "hydrocarbon" is an organic compound that primarily includes the elements of hydrogen and carbon, although nitrogen, sulfur, oxygen, metals, or any number of other elements may be present in small amounts. Hydrocarbons generally refer to components found in heavy oil or in oil sand. However, the techniques described are not limited to heavy oils but may also be used with any number of other reservoirs to improve gravity drainage of liquids. Hydrocarbon compounds may be aliphatic or aromatic, and may be straight chained, branched, or partially or fully cyclic.

[0039] "Bitumen" is a naturally occurring heavy oil material. Generally, it is the hydrocarbon component found in oil sand. Bitumen can vary in composition depending upon the degree of loss of more volatile components. It can vary from a very viscous, tar-like, semi-solid material to solid forms. The hydrocarbon types found in bitumen can include aliphatics, aromatics, resins, and asphaltenes. A typical bitumen might be composed of:
19 weight (wt.) % aliphatics (which can range from 5 wt. % - 30 wt. %, or higher);
19 wt. % asphaltenes (which can range from 5 wt. % - 30 wt. %, or higher);
30 wt. % aromatics (which can range from 15 wt. % - 50 wt. %, or higher);
32 wt. % resins (which can range from 15 wt. % - 50 wt. %, or higher); and some amount of sulfur (which can range in excess of 7 wt. %).
In addition, bitumen can contain some water and nitrogen compounds ranging from less than 0.4 wt. % to in excess of 0.7 wt. %. The percentage of the hydrocarbon found in bitumen can vary. The term "heavy oil" includes bitumen as well as lighter materials that may be found in a sand or carbonate reservoir.

[0040] "Heavy oil" includes oils which are classified by the American Petroleum Institute ("API"), as heavy oils, extra heavy oils, or bitumens. The term "heavy oil" includes bitumen. Heavy oil may have a viscosity of about 1,000 centipoise (cP) or more, 10,000 cP or more, 100,000 cP or more, or 1,000,000 cP or more. In general, a heavy oil has an API gravity between 22.3 API (density of 920 kilograms per meter cubed (kg/m3) or 0.920 grams per centimeter cubed (g/cm3)) and 10.0 API (density of 1,000 kg/m3 or 1 g/cm3).
An extra heavy oil, in general, has an API gravity of less than 10.0 API (density greater than 1,000 kg/m3 or 1 g/cm3). For example, a source of heavy oil includes oil sand or bituminous sand, which is a combination of clay, sand, water and bitumen. The recovery of heavy oils is based on the viscosity decrease of fluids with increasing temperature or solvent concentration. Once the viscosity is reduced, the mobilization of fluid by steam, hot water flooding, or gravity is possible. The reduced viscosity makes the drainage or dissolution quicker and therefore directly contributes to the recovery rate.

[0041] "Fine particles" or "fines" are generally defined as those solids having a size of less than 44 microns ( m), that is, material that passes through a 325 mesh (44 micron).

[0042] "Coarse particles" are generally defined as those solids having a size of greater than 44 microns (pm).

[0043] The term "solvent" as used in the present disclosure should be understood to mean either a single solvent, or a combination of solvents.

[0044] The terms "approximately," "about," "substantially," and similar terms are intended to have a broad meaning in harmony with the common and accepted usage by those of ordinary skill in the art to which the subject matter of this disclosure pertains. It should be understood by those of skill in the art who review this disclosure that these terms are intended to allow a description of certain features described and claimed without restricting the scope of these features to the precise numeral ranges provided. Accordingly, these terms should be interpreted as indicating that insubstantial or inconsequential modifications or alterations of the subject matter described and are considered to be within the scope of the disclosure.

[0045] The articles "the", "a" and "an" are not necessarily limited to mean only one, but rather are inclusive and open ended so as to include, optionally, multiple such elements.

[0046] The term "paraffinic solvent" (also known as aliphatic) as used herein means solvents comprising normal paraffins, isoparaffins or blends thereof in amounts greater than 50 wt. %. Presence of other components such as olefins, aromatics or naphthenes may counteract the function of the paraffinic solvent and hence may be present in an amount of only 1 to 20 wt. % combined, for instance no more than 3 wt. %. The paraffinic solvent may be a C4 to C20 or C4 to C6 paraffinic hydrocarbon solvent or a combination of iso and normal components thereof. The paraffinic solvent may comprise pentane, iso-pentane, or a combination thereof. The paraffinic solvent may comprise about 60 wt. %
pentane and about 40 wt. % iso-pentane, with none or less than 20 wt. % of the counteracting components referred above.

[0047] An agglomerating polymer may be used to agglomerate solids in oil sand tailings, to facilitate solid-liquid separation. However, mixing of an agglomerating polymer with oil sand tailings can be challenging.

[0048] More broadly, mixing of a viscous material with a dense slurry can be challenging. Typically, mixing is assumed to occur if the dense slurry reaches a high enough Reynolds number. In reality, however, it has been discovered that this can prove insufficient, especially if the Reynolds number is not high enough to achieve mixing given the viscous forces as defined by the mixing viscous material, rather than by the dense slurry. As a result, inline flocculation mechanisms can under-achieve in the field of mixing. Much effort at improving contacting a flocculating polymer with a slurry has taken the form of enhanced mixing. Enhanced mixing can include static and dynamic mixers. In many cases, the increase in mixing energy also increases shear, which can have a negative effect of degrading shear-sensitive polymers.

[0049] Industry solutions to this problem have included introducing the viscous material, like a polymer, in a Venturi mixer. Computational Fluid Dynamics (CFD) modeling indicates flow mix and shear based on classical fluid dynamics. However, for larger pipes (for instance having diameters larger than 8 inches), even turbulent conditions that are typically sufficient for mixing can be insufficient for ensuring good contact between a polymer and a slurry. In addition, excess shear, typical of mixing, can result in destruction of flocs which are shear sensitive. These challenges may be aggravated by slurries that defy classical numerical modeling and which demand other solutions. T-injectors and Venturi mixers have proven inadequate, but are still recommended in the industry. More robust mixing can have some positive results, and static or dynamic mixers have been tried with some success, but these methods come with other challenges such as increased pressure drop, several moving parts, dependence on flowrates, etc. The oil sands industry has used an airline spigot or a jet injector system to introduce polymer into a pipe carrying oil sand tailings.

[0050]
Certain polymer injection point configurations have one (a T-junction) to nine introduction points, often in an annulus (i.e. arranged radially like numbers around a clock) in a Venturi mixer. Where insufficient mixing occurs, these nine points lead to a large "ribbon"
of viscous material flowing into the dense material. To achieve sufficient contact at a large scale, this ribbon should have a diameter comparable to that achieved at a smaller scale. This requires more injection points around the annulus (again, radially like numbers around a clock). However, the increase in injection points drives up the cost for piping and distribution of polymer. Such an arrangement is illustrated in Figs. 3A, 3B and 3C by way of, from top to bottom, a simplified side view, a side view, and a cross-section view. Line 301 carries slurry (illustrated as flow from left to right). Line 302 carries polymer (illustrated as flow from top to bottom). Lines 301 and 302 meet at one or more T locations (intersections at the pipe), but the T injection is at the same axis along the pipe. The polymer is injected at a single pressure because it is injected at a single point in the axis of the pipe.

[0051] To date, the emphasis relies on mixing rather than on dispersion. It has now been recognized that mixing itself is not the goal; it is the means to the goal of dispersing a polymer with the slurry.

[0052] It has now been recognized that by adding an agglomerating polymer at multiple locations along the length of a pipe carrying the tailings, the polymer can be dispersed into the tailings.

[0053]
Fig. 4 is a flow chart of a method of treating oil sand tailings. A method of treating oil sand tailings may comprise passing (402) the tailings through a pipe having a length, and producing (404) treated tailings by adding an agglomerating polymer at multiple locations along the length of the pipe to disperse the polymer into the tailings.

[0054] The pipe may be any suitable pipe. The diameter of the pipe may be between 2 inches and 36 inches, or between 3 inches and 24 inches, or between 6 inches and 16 inches, or greater than 8 inches. The length of the pipe may be between 50 m and 20 km, or between 500 m and 8 km, or less than 100 m, or greater than 1 km, or between 100 m and 1 km.

[0055] The method may comprise using a single pump to pump the polymer into the pipe using a network of injection tubes distributed along the length of the pipe. The network of injection tubes may comprise pressure gauges and flow regulators to adjust a flow rate of the polymer into the pipe. The network of injection tubes may comprise tubes of different diameter for regulating polymer flow, for instance to achieve proportional flow at the different pressures along the pipe. The network of injection tubes may comprise a static flow regulating system for regulating polymer flow, such as flow constrictors, valves, chokes. The injection points where the injection tubes meet the pipe may be spaced greater than 1 cm apart, or greater than 1 m apart, or greater than 10 m apart. A single pump may be used to split a flow of the polymer into a series of tubing to deliver polymer to multiple injection points along the pipe. Such an apparatus may be constructed off-site out of flexible tubing so that installation requires only the drilling of holes and placement of fittings into the holes.
Such an apparatus may also be fitted with pressure gauges and flow restrictors, if desired, to adjust the flowrate in each tube for achieving consistent flow throughout without adding more pumps. In this way, only one pump may be needed to adjust polymer dosage. Such an arrangement is illustrated in Figs. 5A, 5B and 5C by way of three side views.
Line 501 carries slurry (illustrated as left to right). Multiple tubes (illustrated as 502, 503, 504, 505, 506, 507, 508, 509, 510, 511, and 512) connect with line 501 to inject polymer, but at different axial locations along the line 501.

[0056] The network of injection tubes may comprise injection tubes of different diameters for regulating polymer flow. The network of injection tubes may comprise a static flow regulating system for regulating polymer flow, such as, but not limited to, flow constrictors, valves, or chokes.

[0057] The multiple locations may be greater than ten locations, or between 12 and 40 locations, or between 4 and 12 locations. The multiple locations may be greater than 10 cm apart from one another along the length of the pipe, or greater than 1 m apart, or greater than 3m apart. The multiple locations may be spaced along the length of the pipe at intervals greater than 2-20 times the diameter of the pipe.

[0058] The method may further comprise adjusting one or more rheological properties of one of both of the tailings and agglomerating polymer to bring their one or more rheological properties closer together, to assist in dispersing the polymer into the tailings. The adjustment of the rheological properties may be achieved by adding a component to the slurry to change a physical or chemical component of the slurry. For example, the slurry may be subjected to shear, heated, diluted, introduced to a viscosity reducer, etc.
in order to adjust the rheological properties. The one more rheological properties may comprise static yield stress, viscosity, or density.

[0059] The tailings and the agglomerating polymer together may have a Reynolds number below 10,000, or below 3000, or below 1000, or below 200, or above 1000, or between 1000 and 5000, wherein the Reynolds numbers is calculated as follows:
inertial forces of the tailings/ viscous forces of the agglomerating polymer, where the inertial forces of the tailings = density of tailings (kg/m3) *
velocity of the tailings (m/s) * diameter of the pipe (m), and where the viscous forces of the agglomerating polymer = dynamic viscosity of the agglomerating polymer (Pa.$).

[0060] In the above equation, the following abbreviations are used: kg (kilograms), m (meters), s (seconds), Pa.s (Pascal-seconds), and * (multiplication).

[0061] The tailings and agglomerating polymer flowing in the pipe may together have a Hedstrom number greater than 10, or greater than 1000, or greater than 1,000,000. The Hedstrom number is calculated as the ratio of the density * the square of the pipe Inner Diameter * yield strength of the fluid divided by the square of the dynamic viscosity, with units expressed in standard units (kg, m, seconds). The Hedstrom number and the Reynolds Number are together used to approximate a transition between laminar and turbulent flow for some Non-Newtonian fluids. If the Reynolds number is above this transition point, the flow is considered turbulent. The relationship is typically expressed in the form of Transition point =
A * ReB, where A and B vary based on the size of the Hedstrom number. As used herein, if the Hedstrom number is greater than 100,000, the transition Reynolds number is the square root of the Hedstrom Number. If the Hedstrom Number is less than 100,000, the transition Reynolds number is 80 times the Hedstrom Number taken to the 0.4 power. The Reynolds number may be within 5000 of the transition Reynolds number, or within an order of magnitude of the transition Reynolds number.

[0062] The method may be applied to Non-Newtonian fluids that flow near or below the transition to turbulent flow. The method may be applied to fluids with a Reynolds number that is less than twice the value of the transition point using the Hedstrom number.

[0063] The method may further comprise passing the treated tailings through a perforated plate or flow controlling device. The plate or flow controlling device would force a change in flow behavior within the pipe. This change in flow behavior can be used to introduce more mixing, greater contact of the slurry with the agglomerating polymer, or to turn the material and impart shear.

[0064] The tailings may stem from water-based extraction of bitumen from oil sand.
The tailings may comprise primary separation cell (PSC) tailings, middlings, flotation tailings, froth treatment tailings, TSRU tailings, fluid fine tailings (FFT), mature fine tailings (MFT), or a mixture thereof. MFT may be diluted with water prior to treating the tailings stream. This dilution may reduce the viscosity and/or solids content of the MFT in order to facilitate mixing of the multiple streams. The tailings stream may have a solids content between 10 wt. % and 65 wt. %. The tailings stream may have a ratio of sand to fine particles between 0.5 and 5, or between 0.01 and 10. The tailings stream may comprise bitumen in a quantity of less than 10 wt. %. The tailings may comprise water in an amount of greater than 20 wt. %, or greater than 50 wt. %, or greater than 80 wt. %.
100651 The tailings may stem from solvent-based extraction of bitumen from oil sand.
100661 The agglomerating polymer may be any suitable polymer and may be used to agglomerate solids within the tailings to assist dewatering. The agglomerating polymer may comprise a flocculating polymer. The flocculating polymer may comprise a polyacrylamide (PAM). The agglomerating polymer may comprises a cationic, anionic, nonionic or amphoteric polyacrylamide, a copolymer of acrylamide and diallyl dimethyl ammonium chloride, a copolymer of acrylamide and diallylaminoalkyl (meth)acrylates, a copolymer of acrylamide and dialkyldiaminoalkyl (meth)acrylamide, or a mixture thereof.
100671 The method may further comprise discharging the treated tailings stream to a dedicated disposal area (DDA). The method may further comprise collecting water from the DDA for recycling.
[0068] The method may further comprise conditioning or treating or both conditioning and treating the treated tailings with a tailings treating technology. The tailings treating technology may comprise thickening, centrifugation, or in-line flocculation.
The method may further comprise following the tailings treating technology with thin or thick lift drying.
[0069] The tailings may comprise an aluminate and a silicate added to form chemically-induced micro-agglomerates (CIMA). The aluminate may comprise sodium aluminate and the silicate may comprise colloidal silica. An example of using CIMA in tailings flocculation is described in Canadian Patent Application No.
2,767,510 (Lin), which is incorporated herein by reference.
[0070] The dispersing may be effected in the substantial absence of mixing means.
Mixing means refers to mixing means such as, for instance, static and dynamic mixers as described above, and does not relate to mixing that will occur simply by the polymer injection or flow in the pipe. Quantitatively, "substantial absence" may refer to where no more than 5%, or no more than 1% of the dispersion is due to mixing means.
[0071] As illustrated in Fig. 6, a method of delivering an agglomerating polymer to a flowing tailings stream may comprise providing an agglomerating polymer (602);
and pumping, using a single pump, the agglomerating polymer through a network of tubes and into the tailings stream at multiple injection points along a direction of travel of the tailings stream, to disperse the agglomerating polymer in the tailings stream (604).
The method may further comprise monitoring delivery of the agglomerating polymer and adjusting a flow rate of the agglomerating polymer for achieving desired dispersion.
[0072] As illustrated in Fig. 7, a method of retrofitting a pipe for carrying a tailings stream with an agglomerating polymer injection system may comprise forming holes in the pipe at multiple points along a length of the pipe (702); and attaching the agglomerating polymer injection system to the pipe to fluidly connect a source of agglomerating polymer to the pipe through the holes using a network of flexible tubing (704).
[0073] Table 1 is an illustration of calculations of a flowing primary line containing a non-Newtonian fluid which may be challenging to model. The material is to be thoroughly mixed with a viscous chemical flocculent. A traditional approach to this problem is to increase the flowrate to ensure the primary line is in the turbulent regime.
However, because the material is non-Newtonian, it is non-trivial to calculate the precise transition point to turbulence. In Table 1, the calculations are based on introducing the viscous fluid in either three spigot ports at a single junction around the circumference of the pipe (i.e. radially) or in 50 spigot ports along the length of the pipe. In one calculation, the material in Case #1 is turbulent in flow regime, but this turbulence may be insufficient to mix in the viscous polymer, as demonstrated by the second calculation of flow regime in Case #2.
In Case #1, a traditional definition of the Reynolds number was employed, that is, the ratio of viscous forces to inertial forces for the carrier primary fluid was used, which constitutes the great majority of the flowing medium. In Case #2, the calculation was made differently, that is, the ratio of the inertial forces of the carrier stream to the viscous forces of the smaller, viscous stream, was used. This is because the smaller stream must be torn apart by the energy in the carrier fluid and mixed into the larger stream. The fluid providing the energy to perform this action is the primary carrier fluid, while the viscosity of the smaller stream resists the action of mixing into the primary stream. Thus, a conventional calculation might suggest that the flow is turbulent and should mix as such, while the action at the interface of the fluids is more laminar in nature. The laminar flow regime requires diffusion as a major vector for mixing to occur, and the limitation on diffusion is described by the penetration of the materials into one another. Table 1 shows that three spigots arranged radially would result in a "ribbon" of viscous material flowing in the pipe after the injector with a radius of 1.4 cm. Such a thick material will be very challenging to mix by diffusion alone. The use of 50 spigots along the length of the pipe has the impact of reducing the effective radius of this "ribbon" of the resisting fluid to 3.5 mm, a much more manageable diffusion mixing challenge in a flowing stream.
[0074] Table 1.
Stream Parameter Parameter Units Case # 1 Case #1 Case # 2 Case # 2 D diameter inches 12 12 Q flow rate/hr m3/hr 1200 1200 Q flow rate m3/s 0.3333 0.3333 , 0.3333 0.3333 Oh diameter m 0.3048 0.3048 0.3048 0.3048 dynamic Primary Line viscosity or consistency mu Pa-s 0.13 0.0487 0.13 0.0487 kinetic viscosity mu/rho m2/s 9.3592E-05 3.5061E-05 9.3592E-05 , 3.5061E-05 A area m2 0.07297 0.07297 0.07297 0.07297 rho density kg!m3 1389 1389 1389 v velocity m/s 4.5683 4.5683 4.5683 4.5683 , Stream Parameter Parameter Units Case # 1 Case # 1 Case # 2 Case # 2 tau yield stress _ Pa 39 56 Re Q Dh/vA 14878 39714 14878 i density x yield x diameter2 He consistency 2 297790 3046929 297790 Transition Reynolds 13643 43639 13643 Flow Regime Turbulent Laminar Turbulent Laminar Safety Factor 994 -9% 994 dynamic viscosity or consistency mu Pa-s 1.16 1.16 1.16 1.16 Viscous Material kinetic of fluid viscosity mu/rho n12/s 0.00116 0.00116 0.00116 0.00116 flocculent ribbon rho density kg/m3 1000 1000 1000 tau yield stress Pa 27 27 27 Cross section radius (if 1 spigot) m 0.04912 0.04912 0.04912 0.04912 Cross section radius each m 0.01418 0.01418 0.003474 0.003474 Cross Section _ area m2 0.001895 0.001895 0.001895 0.001895 Number of Spigots 3 3 50 Polymer _ flowrate m3/hr 32 32 32 Full Polymer Stream flowrate m3/s 0.008889 0.008889 0.008889 0.008889 Total Flowrate after floc m3/s 0.3422 0.3422 0.3422 0.3422 Total Velocity in line after floc m/s 4.6902 4.6902 4.6902 4.6902 Total Velocity after floc 4.6902 4.6902 4.6902 4.6902 _ Re (ReDr) 1711.8 1711.8 1711.8 1711.8 .

Stream Parameter Parameter Units Case # 1 Case #
1 Case # 2 Case # 2 Flow Regime Laminar Laminar Laminar Laminar [0075] It should be understood that numerous changes, modifications, and alternatives to the preceding disclosure can be made without departing from the scope of the disclosure.
The preceding description, therefore, is not meant to limit the scope of the disclosure. Rather, the scope of the disclosure is to be determined only by the appended claims and their equivalents. It is also contemplated that structures and features in the present examples can be altered, rearranged, substituted, deleted, duplicated, combined, or added to each other.

Claims (45)

CLAIMS:

1. A method of treating oil sand tailings, the method comprising:
a) passing the oil sand tailings through a pipe having a length; and b) producing treated tailings by adding an agglomerating polymer at multiple locations along the length of the pipe to disperse the polymer in the oil sand tailings.

2. The method of claim 1, wherein b) comprises using a single pump to pump the polymer into the pipe using a network of injection tubes.

3. The method of claim 2, wherein the network of injection tubes comprises pressure gauges and flow regulators to adjust a flow rate of the polymer into the pipe.

4. The method of claim 2, wherein the network of injection tubes comprises injection tubes of different diameters for regulating polymer flow.

5. The method of claim 2, wherein the network of injection tubes comprises a static flow regulating system for regulating polymer flow.

6. The method of claim 5, wherein the static flow regulating system comprises flow constrictors, valves, or chokes.

7. The method of any one of claims 1 to 6, wherein the multiple locations comprise greater than ten locations.

8. The method of any one of claims 1 to 7, wherein the multiple locations are greater than one meter apart from one another along the length of the pipe.

9. The method of any one of claims 1 to 8, further comprising adjusting one or more rheological properties of one of both of the oil sand tailings and agglomerating polymer to bring their one or more rheological properties closer together, to assist in dispersing the polymer in the oil sand tailings.

10. The method of claim 9, wherein the one more rheological properties comprise static yield stress, viscosity, or density.

11. The method of any one of claims 1 to 10, wherein the oil sand tailings and the agglomerating polymer together have a Reynolds number less than 10,000, wherein the Reynolds numbers is calculated as follows:
inertial forces of the oil sand tailings/ viscous forces of the agglomerating polymer, where the inertial forces of the oil sand tailings = density of oil sand tailings (kg/m3) *
velocity of the oil sand tailings (m/s) * diameter of the pipe (m), and where the viscous forces of the agglomerating polymer = dynamic viscosity of the agglomerating polymer (Pa.cndot.s).

12. The method of claim 11, wherein the Reynolds number is within 5000 of a transition Reynolds number.

13. The method of claim 11, wherein the Reynolds number is within an order of magnitude of a transition Reynolds number.

14. The method of any one of claims 1 to 13, further comprising passing the treated tailings through a perforated plate.

15. The method of any one of claims 1 to 14, wherein the oil sand tailings stem from water-based extraction of bitumen from oil sand.

16. The method of any one of claims 1 to 14, wherein the oil sand tailings comprise primary separation cell (PSC) tailings.

17. The method of any one of claims 1 to 14, wherein the oil sand tailings comprise middlings.

18. The method of any one of claims 1 to 14, wherein the oil sand tailings comprise flotation tailings.

19. The method of any one of claims 1 to 14, wherein the oil sand tailings comprise froth treatment tailings.

20. The method of any one of claims 1 to 14, wherein the oil sand tailings comprise tailings solvent recovery unit (TSRU) tailings.

21. The method of any one of claims 1 to 14, wherein the oil sand tailings comprise fluid fine tailings (FFT).

22. The method of any one of claims 1 to 14, wherein the oil sand tailings comprise mature fine tailings (MFT).

23. The method of claim 22, further comprising diluting the MFT with water prior to treating the tailings.

24. The method of any one of claims 1 to 14, wherein the oil sand tailings stem from solvent-based extraction of bitumen from oil sand.

25. The method of any one of claims 1 to 24, wherein the agglomerating polymer comprises a flocculating polymer.

26. The method of claim 25, wherein the flocculating polymer comprises a polyacrylamide (PAM).

27. The method of any one of claims 1 to 24, wherein the agglomerating polymer comprises a cationic, anionic, nonionic or amphoteric polyacrylamide, a copolymer of acrylamide and diallyl dimethyl ammonium chloride, a copolymer of acrylamide and diallylaminoalkyl (meth)acrylates, a copolymer of acrylamide and dialkyldiaminoalkyl (meth)acrylamide, or a mixture thereof.

28. The method of any one of claims 1 to 26, further comprising discharging the treated tailings to a dedicated disposal area (DDA).

29. The method of claim 28, further comprising collecting water from the DDA for recycling.

30. The method of any one of claims 1 to 29, further comprising conditioning or treating or both conditioning and treating the treated tailings with a tailings treating technology.

31. The method of claim 30, wherein the tailings treating technology comprises thickening, centrifugation, or in-line flocculation.

32. The method of claim 30 or 31, further comprising following the tailings treating technology with thin or thick lift drying.

33. The method of any one of claims 1 to 32, wherein the oil sand tailings comprise an aluminate and a silicate added to form chemically-induced micro-agglomerates (CIMA).

34. The method of claim 33, wherein the aluminate comprises sodium aluminate and the silicate comprises colloidal silica.

35. The method of any one of claims 1 to 34, wherein the dispersing of b) is effected in the substantial absence of mixing means.

36. The method of any one of claims 1 to 35, wherein the pipe has a diameter of greater than 8 inches.

37. The method of any one of claims 1 to 36, wherein the oil sand tailings and the agglomerating polymer together have a Hedstrom number of greater than 10.

38. The method of any one of claims 1 to 14, wherein the oil sand tailings comprise 10 to 65 wt. % solids, greater than 20 wt.% water, and less than 10 wt. % bitumen.

39. The method of any one of claims 1 to 14 and 38, wherein the oil sand tailings comprise a sand to fines weight ratio of 0.5 : 1 to 5 : 1.

40. The method of any one of claims 1 to 39, wherein the network of injection tubes comprises flexible tubing.

41. A method of delivering an agglomerating polymer to a flowing tailings stream, the method comprising:
a) providing an agglomerating polymer; and b) pumping, using a single pump, the agglomerating polymer through a network of tubes and into the tailings stream at multiple injection points along a direction of travel of the tailings stream, to disperse the agglomerating polymer in the tailings stream.

42. The method of claim 41, wherein the network of tubes comprises flexible tubing.

43. The method of claim 41 or 42, wherein the multiple injections points comprise greater than ten locations.

44. The method of any one of claims 41 to 43, further comprising monitoring delivery of the agglomerating polymer and adjusting a flow rate of the agglomerating polymer for achieving desired dispersion.

45. A method of retrofitting a pipe for carrying a tailings stream with an agglomerating polymer injection system, the method comprising:
a) forming holes in the pipe at multiple points along a length of the pipe;
and b) attaching the agglomerating polymer injection system to the pipe to fluidly connect a source of agglomerating polymer to the pipe through the holes using a network of flexible tubing.