Patent Number: 060020636
Section: description

DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS The first stage of the process entails the identification of a suitable injection site and target stratum, identified in FIG. 1 as reference 2, and to determine the extent of the site. The preferred site and target stratum will have the following characteristics: a) The site will be free of significant quantities of hydrocarbons and other valuable minerals that could become the target for exploitation in the foreseeable future. PA0 b) The target stratum will have a minimum thickness of 4 meters and be at least 0.5.times.2.0 km in extent, or be connected hydraulically to permeable strata that have these dimensions. PA0 c) The minimum transmissivity of the target stratum will be 0.5 Darcy-meters (average permeability in Darcy units multiplied by the stratum thickness in meters). PA0 d) The direction of groundwater flow in the region around the stratum will be generally horizontal, i.e., deviating from the horizontal by no more than about 2.5 degrees. PA0 e) The target stratum will comprise granular, poorly-cemented or uncemented sandstone or highly fractured porous rock. The rock will have no significant large-scale tensile fracture strength (tensile resistance to hydraulic fracturing) and a compressibility of at least 1.times.10.sup.-6 kPa..sup.-1 PA0 f) The rock in the target stratum will not react chemically with the solid or liquid phases of the slurry to release any free gases or new noxious compounds, apart from the ordinary slow dissolution of minerals which takes place in aqueous systems. PA0 g) The stratum will have a minimum porosity of about 15% in the portions that have a permeability above 100 mD (milliDarcy). PA0 h) The stratum will not be intersected by any faults or other geological features that could give direct or easy access from the stratum to surface groundwater. PA0 i) The target stratum will be overlain by at least 1-2 meters, and preferably 10 meters of low permeability overburden strata with a maximum permeability of 10 mD, for example a ductile shale or clayey siltstone. The overburden will preferably consist of alternating permeable and impermeable stratum (less than about 10 milliDarcies). This capping stratum is typically a thick, ductile non-faulting shale to best provide hydraulic isolation and a stress barrier to upward fracture propagation. The overlying permeable zones absorb wastes if hydraulic isolation of the target is breached and also act as further fracture barriers. The alternating stratigraphy further serves as a barrier to contamination of overlying groundwater zones and directs flow laterally rather than vertically. PA0 a) The well depth will be a minimum of 250 m in regions of modest surface elevational differences (20 m or less) and 500 m in hilly terrain (20-200 m). PA0 b) The well will be isolated from all shallow groundwater sources by laterally continuous overburden strata that extend a minimum of about 10 km in all directions. These barrier strata will have a combined thickness of 50 m, counting only those strata that are at least 5 m thick and shall have an aggregate transmissivity to water no greater than 0.02 Darcy-meters. PA0 c) There will be at least one "security zone" consisting of a permeable layer above the target zone to bleed off any liquid that might migrate upwards and to blunt the upward propagation of fractures. The security zone should have a transmissivity of at least 1.0 Darcy-meters and be dominated by horizontal groundwater flow, unconnected to shallow potable water sources. Preferably, at least one such zone is within 100 meters of the target stratum, and is greater than about 2 meters thick on average. This zone also serves as a barrier to contamination of overlying groundwater zones. PA0 d) The groundwater in the target stratum, security zone and all other affected strata must not be a source of potable water, and must be shown to be hydraulically isolated from regional potable drinking water (no local faults through jointed rocks). This isolation can be demonstrated isotopically or through groundwater or lithostratigraphic studies. PA0 e) The overburden may include a sedimentary sequence that includes minerals such as clays or zeolites which have the capacity to absorb wastes such as heavy metals and organics. This aspect permits moving liquids and leachates to contact large amounts of clay minerals in shale, clayey silts and in the interstices of unconsolidated sandstones, for the absorption of heavy metals, organic molecules and other contaminants. PA0 a) The total slurry volume to be injected for each well or series of wells is a function of the projected interstitial volume of the target stratum. This is determined by assessing the size of the target stratum (both area and thickness), the approximate interstitial volume, and preferably also the mechanical compressivity of the stratum. PA0 b) The target flow rate ("injection rate") for the slurry is determined by the speed at which the target stratum is capable of absorbing the slurry while maintaining a steady state well bottom pressure. Ideally, this pressure is between 115% and 135% of the overburden stress. The well bottom pressure is measured by the pressure gauge 7 positioned at the well bottom. The optimal infectivity is determined as: injection rate/(Press.sub.inj -Press.sub.fmt), where Press.sub.inj =injection pressure and Press.sub.fmt =formation pressure. PA0 c) The duration of each injection and inter-injection episode is determined by the rate at which the slurry spreads within the target stratum and the rate at which the pressure at well-bottom dissipates. The spread of slurry within the target stratum is assessed primarily by the magnitude and decay rate of ground surface uplift in the region around the well, as determined by tiltmeters or other surface uplift indicators. Typically, maximum surface uplift during an injection episode will be limited to a maximum of about 5 cm or such other value as may be set by a regulatory body. Once this amount of uplift has occurred, the episode is halted until pressure decays to an acceptable level (i.e. less than 80% of overburden stress) and the deformation rate is small. PA0 d) The localization of the injected solids within the target stratum is determined by microseismic surveillance and, in the case of shallow (.ltoreq.800 m) disposal depths, measurement of surface uplift using tiltmeters or the like. Through known analysis techniques, the localization of the region of uplift provides an indication of the lateral spread of the embedment zone, and as well provides reconstruction of the fracture behavior in terms of geometry (dip, orientation, aspect ratio) and deformation (volumetric and shear formation). Microseismic surveillance assesses by means of known techniques the horizontal and vertical positioning of the zone. PA0 Maximum slurry injection rate: 1.1-2.0 times fracture extension rate PA0 Daily slurry injection volume: 700-1500 m.sup.3 /day PA0 Waste injection volume: 50-225 m.sup.3 /day PA0 Av. slurry concentration: 5-30% sand by volume PA0 Av. slurry density: 1000-1300 kg/m.sup.3 PA0 Max. slurry density: 1375 kg/m.sup.3 PA0 Injection Pressures 1.1 to 1.5 times the fracture extension pressure PA0 injection episodes: 24 hour injection/interinjection cycle, including 4-14 hours/day injection episode PA0 injection cycle: 5 day injection cycle, 2 days shut-in or 11 day injection cycle followed by 3 day shut-in. PA0 Maximum slurry injection rate: 1.1-2.0 times fracture extension rate PA0 Daily slurry injection volume: 700-1000 m.sup.3 /day PA0 Waste injection volume: 50-100 m.sup.3 /day PA0 Av. slurry concentration: .about.15% slop by volume PA0 Av. slurry density: 1000-1200 kg/m.sup.3 PA0 Max. slurry density: 1250 kg/m.sup.3 PA0 Injection Pressures 1.1 to 1.5 times the fracture extension pressure PA0 injection episodes: 24 hour injection/interinjection cycle, including 4-14 hours/day injection episode PA0 injection cycle: 5 day injection cycle, 2 days shut-in. Additional requirements are imposed for the selection of target strata and preparation of the injection well where it is desired to dispose of wastes that will produce mildly or substantially toxic liquids (as opposed to merely salty or noxious), whether such liquids comprise the injection fluid itself or leachate resulting from interaction between the solid wastes and the carrier liquid. These additional requirements are, at a minimum: The horizontal stratification and high permeability of the target stratum ensures that long term pressures do not build up, that emplaced solids remain close to the injection well and that the carrier liquids dissipate uneventfully in the stratum. The porosity, lack of large-scale cohesion and and low fracture resistance mean that fracture initiation and extension take place repeatedly without blockages or excessive treatment pressures. The injection well is prepared by drilling into the target stratum, as described in detail below. A waste-bearing slurry is prepared, with solid wastes being suspended in the slurry in particulate form. The maximum particle size of suspended wastes is about 5 mm with no more than 15% of the particles being larger than 2.5 mm. The most desirable range of mean grain size of the slurry is between 2 .mu.m and 1000 .mu.m. The solids concentration should be a maximum of 40% by volume for fine grained materials (less than 150 .mu.m particles) or 20% for courser materials (150 .mu.m-500 .mu.m). Granular waste streams with substantial proportions greater than 1000 .mu.m will be specially analyzed to ensure that the concentration of large particles is sufficiently low as not to block perforation openings during injection. Slurry design parameters include: the amount of non-dissolved solid material in the slurry; PA1 the liquid phase viscosity (which will affect the injection rate and underground pressure bleed-off); PA1 colloidal material content (clay and polymer content); PA1 non-aqueous liquids content (e.g. oils and other immiscible liquids); PA1 content of cementitious agents (Portland (tm) cement, lime, etc.); and PA1 additives used to enhance or alter the rheology of the slurry, such as polymers, thickeners, gels or emulsifiers. PA1 finely ground gypsum, limestone or lime PA1 Ground FGD (flue gas desulphurization) sludge, which serves as permeability blocking agent PA1 ground shale, clay or other finely divided material PA1 synthetic non-biodegradable polymer agents PA1 Portland (tm) cement or other commercial cements or pozzolanic cementitious agent PA1 fly ash or finely ground combustion clinker. PA1 during pre-flush to facilitate fracture injection; PA1 during fracture screen-out conditions, when the wellbottom and head pressures unexpectedly surge. PA1 a) optimization of SFI process in terms of length of injection cycles, slurry composition, daily injection volumes and injection rates and pressures; PA1 b) maximizing hydraulic isolation and containment of the injected wastes; PA1 c) providing diagnostic information to evaluate formation stress state and flow response, well integrity, formation containment and response, in situ waste distribution, formation storage capacity and formation infectivity during the injection process; PA1 d) personnel safety during injection procedures; PA1 e) evaluation of the target stratum mechanical and flow responses to the injection process; and PA1 f) determination of the distribution of the injected material within the target stratum. PA1 slurry density measuring means 80; PA1 pump pressure measuring means 82; PA1 means 84 to measure water input into the system; PA1 means 86 to measure injection rates; PA1 a control data logger 88 linked to all of the measuring means to record and store the data in real time. A digital display 90 is provided in the data logger. The monitoring system is also linked to and receives data from the pressure gauges 7 and 10 at the well bottom and surface. Cementitious agents are added to slurries that include wastes of intermediate or high toxicity, such as PCB-contaminated soil, radioactive wastes, and heavy metals or arsenic compounds. The use of cementitious agents reduces the permeability of solid waste materials within the target zone. Thus, after the carrier liquid bleeds off, a solid waste body results that has a permeability substantially lower than that of the surrounding rock, with a consequent hydraulic isolation of the target waste body and a reduced leachate generation rate. Cementitious agents may include: The injection conditions, including the slurry composition are optimized for the particular injection conditions by determining slurry additives (including viscosifiers, surfactants and adsorbing agents), slurry viscosity, slurry waste concentrations and slurry specific gravity, as well as other SFI variables, as functions of the following considerations: Composition of waste material (e.g.. Mud/sand/slop/water ratios). An optimum mix is required to avoid excess injection pressures, formation blockage, injectivity maintenance, wellbore integrity and pump wear. The specific rations depend on many factors, many of which are identified below. The minimum water to waste rations is approximately 4:1 and the minimum sand to viscous fluid rations is approximately 0.5:1. Daily slurry injection volumes. Typically, upper slurry volume limits of 800-2000 m.sup.3 and solids volume limits of 200-300 m.sup.3 per day per injection well are used to insure that no well or formation damage occurs. Higher volumes are permissible only if geological parameters can be shown to be adequate so that the larger volumes do not lead to formation injectivity impairment, blockage, excessive pressurization or unacceptably slow pressure decay rates. Maximum sand grain size during injection. The maximum grain size is controlled by two factors: the opening diameter of the perforations in the case wellbore and the concentration of the large particles. The limit required is that the ration of the perforation opening diameter, D.sub.perf, to the diameter of the largest grains, D.sub.max, be 5 or less, and that there be no more than about 15% of the granular solid portion of the slurry in the diamter ration range of about 5-10. Unless the perforations are specifically designed accordingly, the maximum grain size should be less than about 0.5 mm. Fines/clay content during injection. Excessive amounts of fine-grained material can lead to an unacceptable formation blockage, resulting in excessively high treatment pressures during waste injection. Accordingly, the percentage of clay materials (grain size of less than about 2 microns) is limited to about 10% by volume of the total or, if the clays are not geochemically active, to an amount that does not lead to an excessive slurry viscosity. However, a greater clay content may be allowed if the formation geological characteristics are shown to be adequate to avoid injectivity impairment, slow pressure decay or excessive treatment pressures. Hydrocarbon content of the sand or viscosity of the muds and slops. The hydrocarbon content limit is related to the viscosity of the hydrocarbon. For example, if the viscous fluids to be disposed contain more that 10% by volume of viscous crude oil, having an oil viscosity greater than 1000 cp, the slurry is diluted with make-up water to comprise a maximum of about 10% oil content by volume. Different limits apply for low viscosity oils and emulsified waste materials. The geological characteristics of the target stratum also is a factor. A courser-grained stratum having a mean grain diamter of greater than about 150 microns will accommodate without formation impairment a higher oil content than will a finer-grained stratum. Formation grain size and stress state. SFI is most effective and secure in strata where there are no large pre-existing tectonic stresses that could lead to wellbore impairment or formation shearing during the injection treatment. Specifically, the ration of the major and minor principal stresses should be less than about 3.0. Formation geology. SFI is conducted in target zones comprising sandstones, limestones, chalk or diatomite. As already discussed, the most favorable target stratum is a permeable uncemented sandstone overlain by a sequence of impermeable shales and permeable beds. These geological characteristics dictate aspects of the slurry design, including grain size and slurry content. Heterogeneous effective stress and permeability distribution in the formation. Geological and rock mechanics studies must demonstrate that the stress state is acceptable and that there are not likely to be highly heterogeneous stress distributions that could he detrimental; to SFI activity. Accordingly, the permeability characteristics of the target zone must also be demonstrated not to be excessively heterogeneous in the lateral or vertical directions. The slurry density, waste concentrations and rheology must minimize the development of long term formation stress and pressure gradients in the target zone. Repeated loading and unloading of rock stresses. SFI generates substantial load changes with each cycle. The purpose of pressure and deformation monitoring is partially to ensure that these do not become so large as to lead to wellbore or formation impairment. The slurry density, waste concentrations and rheology must minimize the development of long term formation stress and pressure gradients in the target zone. Wellbore cement quality. Before a pre-existing well is adapted for SFI use, the cement between the casing and the rock must be shown to be of a sufficient quality to assure that upward inter-formation leakage is unlikely to occur. The slurry density and waste concentrations and compositions must be designed in order to minimize cement cracking and deterioration of the casing cement bond and deterioration of the formation cement bond. Preferably, a cement bond log is performed and examined. If a new dedicated SFI well is prepared, a specific approach to cementation is taken using a cement formulation with low shrinkage and a good bond potential. Wellbore completions quality (casing, perfing etc.). The SFI wellbore must pass pressure tests demonstrating that it can withstand pressures higher than the maximum to be encountered during slurry injection operations. The design of the perforations should be in accordance with the guidelines stated above relating to grain size, with the perforations having a diameter about five times the diameter of the largest grain size that will pass the waste screening process. Perforations may be fully phased and the length and location of the perforated interval will be dictated by the geological parameters of the target zone so as to minimize the risk of wellbore impairment and to maximize access to high permeability rock in the formation. The slurry density and waste concentration and composition must be designed to minimize blockage of the perforations, plugging of the injection tubing, plugging of the well across the injection interval and to minimize back flow of waste material during interinjection shut down periods. In one version, the slurry can incorporate a high percentage of shale chips and clays, approximately 50%-90% of the solids portion by volume, in order to reduce the risk of poor-quality leachate generation within the target stratum. With this approach, once the waste material is compacted at depth, the solidified material possess a reduced permeability with a high adsorptive capacity. This method is particularly useful for disposing of low or intermediate-level radioactive wastes or other hazardous wastes. The slurry mixture may be tested prior to injection for the reduction in its permeability. The tests may comprise quantitative analysis using high-pressure uniaxial and/or triaxial compressibility cells with creep testing and fluid flow rate testing methods. To test the ultimate permeability of a particular cementitious slurry, a sample of the mixed slurry is placed in a test chamber and subjected to the overburden stress, pore pressure and temperature it will experience at depth. Compaction is allowed to occur by making provision for the drainage of expelled pore liquid, simulating the densification process at depth. These conditions are maintained on the test sample for a period of no less than two weeks, at which time an axial permeability test is carried out in the same manner. The axial permeability test consists of determining the flow velocity through the test sample when a water pressure difference is imposed between the top and bottom of the compacted cementitious solid material. To be effective as a means of isolating the wastes from surrounding groundwater flow, the permeability should be no more than 1% of the average permeability of the target strata. The slurry is also formulated to ensure rapid bleed-off of pressure during injection, so that fracturing does not propagate far, either vertically or horizontally. The typical injection well 68 is similar to a conventional oil well, but with a larger diameter to accommodate a lining comprising a substantially full-length concrete production casing 3 and, where appropriate, a cemented surface casing 4. The well will not deviate from the vertical by substantially more than about 45 degrees. The lower portion of the well casing, comprising a length of at least 3 meters, is perforated. The well is prepared using controlled drilling practices (rather than conventional boring). During drilling, a high rate of mud circulation is employed to reduce filter cake buildup and to keep the bore clean. A heavy grade casing is employed for the surface and production drill strings. Conveniently, the casing surface is roughened by sandblasting or the like prior to insertion, to enhance concrete bonding. An epoxy/sand coated casing may also be employed. After drilling, the well bore is cleaned by flushing with conditioned mud to remove drill cuttings and filter cake from the bore. Conveniently, the mud flush can employ about double the usual quantity of mud, followed by about 5 m.sup.3 of scavenger slurry immediately prior to cementing. A low shrinkage, pliable and expandable cement should be used for cementing the well, in order that the repeated and sequential applications of pressure during the SFI process does not fracture or crack the concrete layer. A concrete lining extend from about the well bottom to at least above the 10 lowermost casing joints (assuming the use of conventional 10 m length casing units). In the cementing process, casing scrapers and centralizers are used to achieve a better cement bond with the casing. As well, the casing should be rotated and reciprocated vertically during cementing. The cement may be prepared using a continuous batch mixing method to achieve a generally constant cement weight. The cement should not bear weight for a period of time following cementing. When the concrete has cured, the casing and lining are perforated by means of low impact perforation techniques or cutting or slotting techniques. The perforation interval should not exceed 10 meters in order to sustain high injection pressures and rates. The perforation density is preferably about 20 holes/meter and covers between at least about 90.degree. to 120.degree. phasing (and preferably is fully phased) to ensure good radial distribution around the well. An open-bottom injection tubing string 5 is lowered into the hole and there retained within a metal casing-packer 6 in such a manner that the lower part of the tubing string protrudes no more than 3 meters below the packer and at least 1meter above the uppermost perforation. During installation of the tubing string, a hole-bottom electronic pressure gauge 7 is installed to measure pressure of the fluid within the tubing near the bottom of the hole. The gauge is submersible, and may comprise a strain gauge, vibrating wire or vibrating strip-type gauge, capable of measuring bottom-hole pressure from 7-70 Mpa. The gauge is installed in a stainless steel saddle 8 welded to the tubing string 0.5 to 3 meters above the top of the packer. The sensor provides an electronic signal to the surface through a multiconductor, high-pressure cable 9 strapped to the outside of the tubing and installed along with it. The gauge is employed to measure fluid pressure of the slurry during and after the injection. A second electronic pressure sensor or continuous pressure recording device 10 is installed within the annular space between the casing and the tubing at the wellhead. The slurry may be formed either in advance and trucked to the site in the pumping truck 12, or prepared on site. The density of the slurry is monitored either at the pumping truck exit line 14 or at the exit line from the slurry formation apparatus. Where the slurry is mixed on site, the quantities of waste solids, aqueous carrier, additive solids and waste liquids entering the slurry are monitored. Prior to slurry injection, it is desirable to conduct pressure fall-off and step-rate injectivity tests within the injection well in order to assess the formation flow behavior (formation permeability and transmissivity), formation geomechanical behavior (compressibility, fracture behavior, stress state), and potential slurry injectivity into the reservoir. The information obtained from this procedure is used both to optimize the injection protocol and during the slurry injection procedure to determine if anomalies are occurring. In particular, these tests assess whether the formation is suitable for long term (greater than about 2 months) and generally continuous (greater than 4 hours/day) injection. FIG. 4 illustrates a typical desirable pressure fall-off curve analysis, wherein the X-axis represents bottom-hole pressure and the Y-axis represents time, with the resulting curve representing pressure fall-off over time. An extrapolated formation pressure level is shown for comparison. The step-rate test also permits the determination of the required fracture extension rate and fracture extension pressure required for carrying out the SFI method. An example of a step-rate test is shown in FIG. 5, wherein the fracture-opening pressure is shown as a constant, with the bottom-hole pressure increasing in response to increasing injection rates. Slurry is injected into the well in a series of one or more injection episodes of between about 3-30 hours each. The injection pressure of the slurry is sufficient to overcome the parting pressure of the formation. The natural pressure in the porous strata will be far less than the water pressure in the slurry, proving a strong natural gradient that draws the water away, leaving the solids component behind. The individual injection episodes are separated by interinjection periods of between 5 and 100 hours, and preferably between 8 and 14 hours, depending on the response of the stratum. Each injection episode is initiated by pumping solids-free liquid through the system at a pressure sufficient to initiate fracturing of the target stratum. Typically, the flow rate during this stage will be about 1.5 m.sup.3 /min. Solids are gradually introduced to the flowing mixture, and the target solids content is built up over 15-20 minutes. At the end of each injection episode, the solids content of the slurry is gradually diminished, the well is flushed with clear liquid and the well is shut in under pressure (i.e., while pumping). The wellhead and well bottom pressures are recorded at this stage and periodically thereafter throughout the interinjection episode. The interinjection shut in period is preferably between 10 and 72 hours. The shut in period permits the stress and localized pressure fields generated during the injection period to redistribute and dissipate. In one preferred regime, the SFI process commences with an initial injection of carrier liquid (typically water) at a high rate to initiate hydraulic fracturing within the target formation. The formation pressure will as a result fall to a stable injection level as a result of bleed-off. A slurry is gradually introduced into the carrier until the selected target concentration is reached, to achieve SFI at an injection pressure (Press.sub.inj) of between 1.05-1.4 times the overburden pressure, depending on the site and slurry properties. The injection episode is then carried on for between about 4 to 14 hours. Pressure variations of between 5-10% may occur in this period. During this period, an increased formation pressure results in the vicinity of the injection well. At the termination of the injection episode, the slurry is gradually replaced with a clear carrier liquid, with about 5-40 m.sup.3 being flushed through the system. The well is then shut-in during an interinjection period, resulting in a sharp drop in formation pressure. During this period, liquid flow within the formation typically consists largely of porous medium flow rather than the fracture flow which characterizes the injection episode. The entire process is repeated 12-24 hours later. Preferably, the entire injection/interinjection cycle is approximately 24 hours duration, resulting in a convenient daily cycle time. The daily injection cycle may be repeated about 5-10 times, followed by a prolonged interinjection period of about 2-3 days, following which the injection cycle may be repeated a further 5-10 times, and so forth until the calculated storage volume is generally fully saturated. This strategy permits a long term (2 months or more) injection regime. The cyclical injection episodes facilitate fracture re-initiation and propagation. FIG. 6 is a graph illustrating a typical 24 hour SFI cycle, with the vertical axis comprising bottom-hole pressure and the horizontal axis signifying time. A successful SFI strategy will result in the wastes being deposited progressively outwardly from the injection well, while maintaining hydraulic isolation. Where the SFI method is used for the disposal of viscous fluids such as oily wastes, municipal sludges, or industrial wastes, the slurry is injected into an appropriate target stratum in such a manner that the formation flow behavior (i.e. permeability and transmissivity) is not significantly impaired and permeability blockage is minimized. This minimizes fractures that tend to propagate out of the target stratum and breach hydraulic isolation. Mathematical analysis of the pressure and surface deformation data may be conducted to determine the orientation and distribution of the injected slurry. This analysis assists in evaluating containment of the material within the disposal formation. The injection well and the region surrounding the well are monitored by means of surface and subsurface techniques to optimize infectivity and to track formation response to the injected solids. Appropriate monitoring permits optimization of: the total slurry volume to be injected; the injectivity rate; the slurry density and composition; the duration of the injection and inter-injection episodes and the total period of use of the injection well. These factors are determined as follows: The pressure responses of the formation during and after injection are analyzed to give the formation parameters, including permeability, transmissivity and radius of the altered zone. These parameters are tracked over time to ensure that the formation is responding in an optimal manner, if the formation is not responding well, direct alterations of the injection strategy may be made, including alteration of injection rates and periods. The slurry formulation may also be changed to increase the pressure decay rate. In general, if formation blockage or excessive pressurization appear to be occurring, the content of slops and mud will be diminished in favour of sand and water and the volume and duration of the clear water pre-treatment and post-flush will be increased. Waste pod monitoring data are also analyzed to provide a quantitative assessment of the hydraulic isolation of the waste pod within the formation during and after SFI, as well as wellbore integrity. For example, surface deformation data are analyzed to determine the shape and location of the solids injected zone at depth. The zone is determined to be unacceptable and hydraulic isolation is in question, then slurry formulation changes are instituted or the formation around the well is deemed full. The analysis can also be based on formation pressure data analysis and geophysical tracer logging data analysis. Geophysical logging techniques are used periodically to evaluate hydraulic isolation of the disposal formation during SFI operations. Experience has shown that near-wellbore formation flow and stress state changes occur readily during SFI operations. Radioactive tracer log and temperature log data collected concurrently provide a quantitative assessment of the hydrologic isolation of the formation and near well containment of the waste body. Additionally, pressure characteristics within monitoring wells in the region around the injection well may be taken into account. An injection episode should be terminated if the well-bottom pressure within a remote monitoring well (more than 50 m distance) climbs by about 25% of its original pressure. As well, any particular information that is available regarding the structure and seismic characteristics of the target stratum may be taken into account. For example, unexpected microseismic activity or anomalous pressure response in an adjacent monitoring well can result in a modification of one or more the parameters set out above. An injection strategy suitable for use with predominantly particulate waste streams is as follows: The fracture pressure and extension values are determined by the step-wise injection tests and pressure fall-off tests described above. Slop may be injected during the procedure to facilitate the sand injection, to avoid frac tip screen-outs, wellbore sanding and other clogging problems. Slop may be injected at the following stages: For the latter slop injection procedure, a slug of slop (approx. 10 m.sup.3) is injected at the rate of 10-15 m.sup.3 /hr., until the wellbottom pressure recovers to normal. During this procedure, the sand concentration in the slurry is reduced. The maximum slop injection should not exceed about 60 m.sup.3 /day. An SFI strategy for disposal of predominantly viscous liquids is as follows: In this regime, sand may be introduced into the slurry to facilitate the slop injection, by minimizing injection pressure surge effects, avoidance of formation and wellbore plugging and other problems. Typically, sand and slop are injected in a series of alternating stages. For example, a slop slurry stage incorporating 30 m.sup.3 slop material may be alternated with 20 m.sup.3 sand material mixed with sufficient water to generate a suitable slurry. These two stages may be alternated until the daily slop injection target is reached. The injection cycle may be concluded with a 20-50 m.sup.3 sand-based slurry injection, followed by a clear flush of approximately 50 m.sup.3 water. An example of a typical injection protocol developed for a site in East-Central Alberta is: Target Stratum Description: 14 m. thick, 30% porosity depleted sandstone reservoir; compressibility of 10 kPa or higher; flat-lying (horizontal) of great lateral extent (&gt;1 km in all directions). Description of overlying strata: directly overlain by 100 m alternating shales and clayey silts; permeability less than 10 mD, except for several thin stringers (1-3 m) of permeability &gt;100 mD, for lateral bleed-off of any vertically migrating fluid; from 100 m above the target to 250 m above the target, a continuous bed of ductile shale (horizontal) of extremely low permeability. Slurry Composition: The carrier phase is waste water (weak brine) produced along with oil from an adjacent oil filed (70%-80% of slurry volume). The solid waste is fine-grained sand with a small fraction of clay (&lt;1-2%) contaminated with heavy oil (15-30% of slurry volume). Also, the slurry may include 0-25% of "slops", i.e., ground surface wastes, including soil, sand or water mixed with spilled oil. Injection Pressure: Measured at hole bottom, no greater than 140% of overburden stress. Injection Rate: from 1.1 to 1.8 m.sup.3 /min. of slurry. Total Slurry Volume: Max 800 m.sup.3 in a 24 hour period. Total for well--100,000 m.sup.3 of 20% solids content for a total of 20,000 m.sup.3 of sand. Average Injection Duration: 10 hours Average Interinjection Period: 14hours Maximum Surface Uplift: less than 1 mm for each episode. Monitoring strategy: Four pressure monitoring wells in a square, each well being 150 m from the injections well; 12 tilt meters arranged in a first circle of 8 placed at 150 m radius around the injection well and a second circle of 4 at 300 m radius from the injection well. Annular casing pressure, tubing wellhead pressure and tubing well bottom pressure recorded during injection and interinjection episodes. Injection volumes, rates and solids contents measured and recorded. In most applications, additional variables should be monitored and recorded, in particular slurry density, pressure, volume and composition. The pressure data from the injection and monitoring wells are used, together with step-rate injection test data, to evaluate the waste emplacement process. In general, the process is accompanied by a suite of monitoring procedures conducted before, during and after the injection process, as follows: i) Monitoring the slurry injection and emplacement by means of measurements of wellbottom hole pressure ("BHP") within the injection wells to assess formation pressure response to the waste injection, as well as permitting pressure fall-off tests and assessment of SFI and formation mechanics. The BHP sensors should have a minimum 0.1% full scope accuracy, very low hysteresis and thermal zero-shift and high resolution (approx. 0.025% FRO). These tests are typically conducted at 5 minute intervals during both interinjection and injection episodes. Further, a 5-60 second scan rate may be used for the first 60 minutes after the daily shut-in. ii) Monitoring BHP within observation wells displaced from the injection wells within about 400 meters to provide assessment of formation pressure gradients and SFI mechanics. The observation well BHP sensors should have the same characteristics as the injection well BHP sensor, and the minimum scan rate is typically 15 minutes. Observation well BHP monitoring is typically conducted in projects involving greater than 3000 m.sup.3 /month or 10,000 m.sup.3 /year. iii) Step rate injection tests ("SRT") conducted within the injection well, to assess fracture extension rate and formation pressure response, as well as closure stress gradient and waste containment within the formation. A baseline SRT is performed prior to the start of the SFI process and is repeated after every 3000-5000 m.sup.3 of wastes have been injected, or at the end of the project. iv) Fluid level measurements within the offset monitoring wells to assess distribution of pressure gradients within the waste emplacement zone and to provide a measurement of waste containment. Baseline levels are established at the start of the SFI process and the test is repeated daily during SFI injection. v) Tracer logs within the injection well, to determine the extent of hydraulic isolation of the formation and wellbore during the injection process and an assessment of fracture orientation within the target formation. A preliminary baseline is established, and the test is repeated after every 3000-5000 m.sup.3 of wastes or at the end of the project. vi) monitoring of surface tiltmeter data generated in the region about the wellhead; to assess the fracture orientation and azimuth, as well as permitting a reconstruction of fracture geometry, horizontal and vertical dimensions and spread of the waste body within the target formation and the rate of change of same, and deformation within the formation, as well as a further assessment of the SFI mechanics. A baseline is established, and tests are repeated every 30 minutes throughout the project duration. Normally, 2-3 data sets per month are analyzed. vii) Injection parameter monitoring (real time recording of injection pressures at wellhead and wellbottom, casing pressure, injection rate, injection volumes and slurry density) to permit a correlation of formation response with the SFI operating parameters. Monitoring is performed continuously, with a minimum scan rate of 1 second. Data is recorded to disk about every 5 minutes. viii) Material sampling of the slurry is conduced regularly and frequently to accommodate various local regulatory requirements. Typically, this occurs weekly, with analysis performed monthly. The monitoring strategy in any given regime is determined in part by the volume and type of waste to be disposed, the geological characteristics of the target stratum, the condition and completion of the wellbore, and the monitoring objectives, including any regulatory requirements. Alterations in large-scale permeability, excessive pressure build-up, abnormal fracture pressure, too-rapid pressure decay or other anomalous reservoir responses are identified and analyzed to decide if these present problems for the continuation of the injection process in a particular well. For example, if the monitoring wells display sudden pressure responses, this would indicate that a discrete fracture plane is interacting with the remote wells, thereby suggesting that the fracture bleed-off is being impaired by permeability blockage. If this is the case, or if other anomalous responses are noted, the slurry design and the injection strategy are altered to rectify the problem and remain within the realm of rapid bleed-off and near-wellbore solids emplacement. Injection procedures may be adjusted appropriately in the event that well-bottom pressure is decaying too slowly, if it appears that solids are being transported out of the target stratum, if the monitoring wells show anomalous pressure responses, or if other monitoring reveals substantive formation containment impairment. For example, slow strain relaxation and pressure decay may be due to excessive fines in the slurry, too large a volume injected within each episode or too short an interval between injection episodes. The response of the reservoir stratum and overlying rock to the slurry injection may be assessed by way of the surface deformation data, in combination with the previously-determined capacity of the reservoir. The reservoir response may be determined from this data as follows: a) The tiltmeter response data over the time period of interest (i.e. 1 hr. to several days) is examined to ensure against anomalous noise signals in the data base. b) The magnitude and direction of the surface tilt responses provide input to a computer programmed to analyze the tiltmeter data. c) The analysis provides an estimate of the size and shape of the zone of solids emplaced at depth over the time period analyzed. A variety of monitoring tools may be used in addition to surface deformation measurement to assess the mechanical formation response to the injection. Changing formation response can result in changing and multiple flow regimes, that in turn may require alteration to the SFI strategy and regime. Typical changes that may be monitored by the methods described herein include changes in formation compressibility and stress state, rate of dynamic fracture propagation and orientation (dip, azimuth), dynamic in situ pressures and stress gradient formations and stress dissipation, formation mechanical deformation and yielding, overburden straining and bending, and asymmetric distribution of waste material around the injection well. Confirmation that the injection process is proceeding properly is obtained by insuring that there is a rough balance between the solids volume input and the volume of deformation, by comparing known input to the results of the mathematical analysis. The surface uplift data allow discrimination between vertical and horizontal fracture orientations by virtue of the magnitude and direction of the tilt vectors from an array of 10-20 tiltmeters positioned around the injection well. This indicates whether vertical or horizontal material transport away from the wellbore may be occurring. In general, the tilt response for long-term injection wells should be dominated by horizontal fracturing components. The tilt data can be analyzed in terms of total deformation to give limits on the extent of the deformation in the reservoir, and by this means the approximate radial and preferably vertical extent of the emplacement zone can be assessed. Also, the tilt or deformation data can be used directly to demonstrate that the ground surface deformations are small and meet limits which might be set by regulatory guidelines. The time-dependent decay of surface tilt changes and internal pressures provides direct evidence of the speed by which the reservoir and the overlying rocks are responding to the volumetric and pressure changes induced by the injection activity. If deformations continue slowly for many days after an injection episode, combined with a slow pressure decay rate, it is proof that the reservoir is approaching capacity, that permeability has become blocked, or that injectate has migrated to a zone of low fluid transmissivity. Conversely, rapid decay and cessation of deformation is evidence that the reservoir is responding as expected with efficient bleed-off and solids localization near the wellbore. These measures over time are used directly to adjust the slurry design and the injection strategy to achieve the best possible reservoir response to the injection. Mathematical analysis of the pressure and tilt data allows for reconstruction of the size and distribution of the injected material. The method may also include microseismic monitoring of the surrounding region to assess the injection process. Such monitoring involves detecting and analyzing small seismic disturbances associated with rock deformation that accompanies the slurry injection. Microseismic monitoring is used in conjunction with the surface deformation and uplift data to determine the approximate dimensions horizontally and vertically of the solids emplacement zone. The locations of microseismic events are plotted three-dimensionally over time, and resulting identification of the microseismic emission field identifies the size and growth rate of the solids emplacement zone. If large amounts of microseismic activity are observed high above or far away from the perforation locations in the well, the nature of the signals is analyzed along with the surface uplift response to the injection, to ensure that solids are not migrating out of the injection zone. If the microseismic emissions continue beyond the time of active injection by several hours or days, this is taken as evidence that pressures are not decaying sufficiently rapidly or have entered a zone of lower permeability. The data from microseismic monitoring are combined with other measures (tilt, volume, rate, pressures) to permit the injection process to be controlled and optimized continuously. The monitoring data may be used to perform the following: The nature and extent of monitoring is a function of the volume of waste to be injected, the geological characteristics of the target stratum, the nature of the waste material, the wellbore characteristics, and the monitoring objectives (e.g., regulatory, personnel safety, etc.). The monitoring data are analyzed to carry out the operations described above with a computer linked to the monitoring instruments described above and programmed to perform the following operations: ##STR1## These operations permit the rapid assessment of events within the reservoir, and permit the dimensions of the solids containment area to be evaluated. This in turn permits the user to demonstrate that the solids are being appropriately contained within the target stratum. Post-injection monitoring is carried out to ensure that the solid wastes are generally contained within the target stratum. The surface deformation and microseismic monitoring described above is carried out subsequent to the injection, typically for a period of several days. If the site has been properly selected and the injection properly carried out, the post-injection monitoring should disclose stable underground conditions. If surface or subsurface instability continues after the injection terminates (allowing for a period of approximately one week for stabilization to be achieved), this is evidence that the solids are potentially migrating,out of the target zone. Surface deformation and microseismic analysis as described above is also deployed in the post-injection period to determine on a periodic basis the positioning of the solids emplacement zone, to ensure that this zone is not expanding beyond set limits and is not potentially communicating with potable water. Referring to FIGS. 2 and 3, the slurry formation and injection apparatus comprises in general terms a feed hopper 30, mixing-averaging apparatus 32 and injection pump apparatus 34. A conveyor 36 transports waste material from the hopper to the mixing-averaging apparatus and comprises a rotatably-driven auger 37 housed within an elongate chamber 38. A water supply tank 39, linked by pipe 40 to the mixing-averaging apparatus, provides a steady high-pressure (approx. 200 psi) source of water for the creation of the slurry. A pipe 48 transports the slurry from the mixing-averaging apparatus to the pump 34. The feed hopper 30 comprises waste-receiving means and is utilized for wastes that consist of oil or sludge-bearing sand, or the like. For certain other, more fluid types of wastes, the hopper may be dispensed with and the wastes deposited directly into the mixing-averaging apparatus. The hopper is designed to receive a load of between 8 and 20 cubic meters of sand. The mixing-averaging apparatus comprises a particle sizing means to screen out oversized particles, consisting of a reciprocally-driven multilevel screen deck 50 onto which wastes are deposited from the conveyor 36. The individual screens within the deck are adjustable and removable to optimize slurry composition for particular injection conditions. A water sprayer 52 is positioned to direct a high-pressure stream of water at the wastes as they exit the conveyor 36. The sprayers are linked to the pipe 40. The screen deck is comprised of three levels of screens, each having a variable matrix size. Waste material is dumped onto the uppermost screen deck 58 either directly or from the conveyor 36. The action of the spray jet and the shaking of the screens serves to remove particles having a size greater than 0.25 to 1 cm. and foreign objects in the waste stream. These oversized particles are either crushed by a stand-alone crusher 60, to be fed back into the waste stream, or are collected and disposed of by other means, not shown. The screened wastes fall from the screen deck into a slurry averaging and mixing tank 61 that supports therein dual rotatably driven mixing screw augers 62 and 63. Additives and agents may be added directly into the tank 61, if required. A pipe 64 leads from the base of the slurry averaging tank into the booster pump apparatus 34, which pressurizes the slurry and discharges it under pressure through a discharge pipe 66 into the well 68. The various components of the system are driven by conventional variable speed hydraulic motors 70. These in turn are linked to a control means 72 which permits control over the inputs into the slurry-production means and over the slurry design. The control means, shown schematically in FIG. 3, receives input from a real-time monitoring system that monitors, records and visually displays the injection parameters of slurry density, injection rate, surface injection pressures, injected volumes and slurry solids concentration. The monitoring system consists of: The control means is adapted to maintain an even slurry density and delivery rate and pressure. The means by which this is achieved comprise generally conventional feedback means. The apparatus further includes a computer operatively linked to the surface uplift indicators and, optionally, to the micro seismographs described above, and programmed to assess the localization and movement of the solids embedment zone in the manner described above. Although the present invention has been described by way of preferred embodiments, it will readily be seen by those skilled in the art to which this invention pertains that numerous departures, variations, etc. of the invention may be made, without departing from the spirit and scope of the invention, as defined in the following Claims.