US20120000662A1

US20120000662A1 - Viscosity differential fracturing for enhanced application of amendments to ground and groundwater

Info

Publication number: US20120000662A1
Application number: US13/152,150
Authority: US
Inventors: Michael J. Liskowitz; Steven C. Chen; John J. Liskowitz
Original assignee: Individual
Current assignee: Zebra Technical Services LLC
Priority date: 2010-06-02
Filing date: 2011-06-02
Publication date: 2012-01-05

Abstract

Viscosity Differential Fracturing uses pneumatic and hydraulic fracturing techniques and a viscosity differential to achieve greater networking, higher amendment loading rates and more controlled propagation. Pneumatic fracturing is applied first in order to create a dense network of small fractures. This is followed by a hydraulic component using a viscosity adjusted fluid. This material can be injected into these fractures at a significant flow rate and extend/expand these fractures while filling them with the fluid. The significant advantage of VDF versus traditional hydraulic fracturing is that the density of fractures created by the initial gas process leads to an overall greater density of fractures emplaced within the subsurface coupled with the ability to emplace a greater mass of material (e.g. proppants, sand, reactants).

Description

1. FIELD OF THE INVENTION

The present invention relates to a system and method of fracturing ground and geo-formations of many types, more specifically, a system and method for fracturing ground to enhance the application of amendments to remediate contaminants in ground or groundwater and also to improve and enhance ground permeability for subsurface extraction processes.

2. DESCRIPTION OF THE PRIOR ART

The most common accepted theories about inducing fractures in low-permeable deposits are based on simple geotechnical principles: (1) induced fractures form perpendicular to the direction of least principle stress (horizontally in over-consolidated sediments) (2) the overall profile of a fracture takes on a concave shape, depending on the degree of sediment over-consolidation, as fractures vent upward towards the surface with radial distance and (3) fractures' direction may be influenced by other paths of least resistance such as existing fractures or variations in geologic stratification in fine grained deposits and along bedding planes/joints of rock formations.
The mechanics associated with pneumatic fracturing are based on the introduction of gas at a pressure that exceeds the in situ stresses and at a volume or flow rate that exceeds the in situ permeability. This causes failure of the subsurface medium and the propagation of outward fractures perpendicular to the least principal stress. Due to the low viscosity of the fracturing gas (e.g. nitrogen), “leak-off” or penetration of gas into secondary micro-fracture networks, pore spaces and permeable lenses requires that large volumes of gas be emplaced to account for leak-off to continue the propagation of fractures. To take this one step further, research has shown that maximum fracture dimensions are attained within several seconds of pneumatic injection and do not change unless flow rate is altered. This rapid fracturing essentially shocks the matrix and forces the matrix to respond or behave in a brittle fashion.
In contrast, the fracture dimensions created by hydraulic fracturing have been found to be time dependent. The different behaviors of pneumatic vs. hydraulic fractures can be attributed to the much lower viscosity of gas compared to liquids used in hydraulic fracturing.
Applicants have surprisingly found that using controlled techniques with two or more fluids of varying viscosity during a fracturing event yield a more dense and influential fracturing pattern than using either low or high viscosity fluids alone. These techniques are particularly important at locations with difficult geologic ground conditions that are not amenable to typical injection processes or subsurface ground that possess a high degree of heterogeneity or complexity.

BRIEF SUMMARY OF THE INVENTION

The Viscosity Differential Fracturing (VDF) technique will incorporate the benefits of two technologies consisting of pneumatic and hydraulic processes, and a viscosity differential to achieve greater networking, higher amendment loading rates, and more controlled propagation. Applicants disclose a system and process whereby a multistep or hybrid approach is used to integrate the physical and dynamic properties of the media used to induce fractures within the subsurface.

DESCRIPTION OF THE DRAWINGS

The invention can be better understood by reference to the following drawings, wherein:

FIG. 1 illustrates a downhole tool and fracture network using the system and method disclosed herein.

FIG. 2 illustrates another downhole tool and fracture network using the system and method disclosed herein.

FIG. 3 illustrates a downhole tool and fracture network using the system and method disclosed herein.

FIG. 4 illustrates a pressure versus time curve for a typical pneumatic fracturing event.

DETAILED DESCRIPTION

In the following detailed description, reference is made to the accompanying drawings that form a part hereof, and in which are shown by way of illustration specific embodiments or examples. These embodiments may be combined, other embodiments may be utilized, and structural, logical, and procedural changes may be made without departing from the spirit and scope of the present invention. The following detailed description is, therefore, not to be taken in a limiting sense, and the scope of the present invention is defined by the appended claims and their equivalents.
VDF is a multi-phase fracturing technique that integrates pneumatic and hydraulic components practiced in fracturing processes to generate a dense and large-aperture fracture network within the targeted zone that can accommodate a higher mass of injected material/amendment. As shown in FIG. 1, the pneumatic component relies on the compressibility and low viscosity of the fracturing gas 101 and the resultant kinetic energy to create a fracture network 102 emanating from the point of application 103. The large volume of the low-viscosity gas enables “leak-off” or penetration of gas into secondary micro-fractures and pore spaces 104. The hydraulic component introduces an incompressible high-viscosity fracturing fluid 105 to propagate, dilate and support large-aperture fractures 106 first initiated by the pneumatic component and to better interconnect them. The high viscosity of the hydraulic fracturing media (typically a proppant slurry with guar) promotes large-aperture fractures 106 due to minimal “leak-off” and a slower fracture propagation rate.
This new fracturing process offers unique benefits compared to pneumatic fracturing (PF) and hydraulic fracturing (HF) procedures. Conventional PF results in micro-fractures that limit the quantity of treatment chemicals that can be emplaced in the subsurface. These micro-fractures are also more likely to pinch close in certain ground types such as expansive clay under high moisture or applied vacuum conditions. Conventional HF is limited to creating one or a very few discrete fractures at a time and not an inter-connected network of fractures that is more effective in either enhancing the ground permeability or providing more contacts within the ground matrix in the case of in situ treatment. Viscosity Differential Fracturing takes advantage of the gas component 101 to initiate and create a fracture network 102, while the hydraulic component 105 acts to dilate and prop open the both primary and secondary fractures created by the initial gas injection process. The combined process takes advantage of the different characteristics of the two fracture fluids to result in an enhanced and inter-connected network 102 of large-aperture fractures capable of receiving large quantity of injectates such as in-situ remediation chemicals or sand proppant.
The specialized equipment used for the VDF process comprises three major components. A gas injection component centers around a pneumatic injection module equipped with a specialty high-pressure/high-flow regulator, injection control manifold, digital flowmeter, pressure and a transducer/data-logger monitoring system. The specialty regulator controls the applied gas pressure to the formation. The control manifold provides on-off precise control of gas flow. The flowmeter/pressure transducer system with data-logger measures and records the process pressure and flow rate.
A second component comprises a hydraulic injection system. It consists of a mobile mixing and injection plant. The plant includes a re-circulation batch tank resting on a load-cell weighing system, an automated dry material hopper/feed screw system, progressive cavity pump, digital flowmeter, a pressure transducer/data-logger monitoring system. The hopper/feed screw system conveys a prescribed quantity of proppant material into the batch tank. The fracturing fluid is created with addition of water with or without guar as a thickening agent. The progressive cavity or diaphragm pump delivers the fracturing fluid into the subsurface.
As shown in FIGS. 1 and 2, a third component is downhole injection tooling 107 201. It consists of an injection assembly comprised of a specialty nozzle 108 202 isolated by multiple pneumatic packers 109. This assembly is inserted into the borehole 110 via an appropriate length of injection piping and an injection wellhead above the surface. FIG. 3 is a multi-dimensional view of the fracture network partially illustrating the density of the network created at a point of application.
The components are interconnected by a series of pressure-rated hoses. The process starts by fracturing the formation first with delivering compressed nitrogen or gas into the injection interval via the injection assembly for 5 to 15 seconds. Once the gas injection ends, the batched hydraulic fracturing fluid is pumped into the formation via the injection assembly. The process terminates once the specific quantity of the fracturing fluid is emplaced.
Modification of the injection pressure and flow rates of the gas and hydraulic fluid is necessary to accommodate site conditions or application objectives. Additionally, the makeup of the fracturing fluid may be modified to achieve desired viscosity, grain size, or composition to control the distribution pattern. Delivery of the fluid within an interval maybe conducted in 2 or more stages. An initial stage may entail a smaller grain size solid to penetrate the smaller fractures such as secondary fractures or those at the distal end of the emplacement radius. The following stage may include larger grained material to fill the primary fractures or those closer to the borehole. In addition, by altering the flow of the emplaced media and the carrier fluids, “packing” of the fractures can occur.
Under the VDF approach, optional suspending or thickening agents are mixed with water at concentrations between 1 and 50 mg/L. The solution is then homogenized in a mixing tank. Once this is completed, specific quantities of non-reactive or reactive materials are introduced to the solution at concentrations between 0.1 and 30 lbs. per gallon, which correspond to a 1% and 80% solids mixture, respectively. Once sufficiently homogenized, the liquid is introduced under pressure utilizing the equipment discussed above into the gas induced network.
The VDF approach can be applied through temporary vertical, angled and horizontal bore holes, and permanently taste vertical, angled and horizontal wells. Pressure, flow rate, and fluid viscosity can be regulated at the surface to optimize permeability enhancements and minimize potential surfacing of the solution and maximize performance of the process.

Example 1

A full scale application of VDF was implemented at a facility in West Virginia. Over 44,000 lbs. of sand proppant were injected within an induced fracture network, increasing permeability and facilitating the extraction of contaminants via applied vacuum from a low permeable clay unit. This field-scale demonstration of VDF, confirmed the significant advantages of this new approach over conventional hydraulic or pneumatic fracturing alone. The fractures created by this process lead to a greater density of fractures within the subsurface. This allowed for emplacement of a greater mass of materials (proppants, sand, and/or treatment chemicals) facilitating increased permeability, treatment rates, and elimination of closure due to the applied vacuum.
Pneumatic fracturing was applied first in order to create a dense network of small fractures. This was followed by a hydraulic component consisting of water, guar, and sand to act as a proppant. Due to the PF, the guar/sand material can be injected into these fractures at a significant flowrate (about 5 to 25 gpm) and extend/expand these fractures while filling them with the proppant. The advantage of VDF versus traditional HF is that the density of fractures created by the initial gas process leads to an overall greater density of fractures emplaced within the subsurface coupled with the ability to emplace a greater mass of material (e.g. proppants, sand, or reactants).
The site geology consisted of soil and fill material underlain by a low permeable clay unit inter-bedded with seams of sand of varying grain size. Site geology was further detailed on a per boring basis as ground cores were collected from each location prior to fracture operations in order to determine the necessity of fracturing across the designated treatment depths in each location and to determine the site specific operational parameters (e.g. flow rates, injection pressures and fluid viscosity).
The equipment used for the VDF process comprised three components. On the gas side, a skid-mounted high pressure-high flow fracture module complete with an injection control manifold and a digital data logger that were used to monitor various operational parameters. Injection pressures were regulated with a high-pressure, high-flow injection manifold. The manifold system provided precise control of injection pressures combined with sufficient flows, which enabled the creation and/or enhancement of fractures within the subsurface. The duration of the gas injections typically ranged between 10 to 15 seconds.
An automated mixing and injection plant comprised the second component. A 350 gallon tank resting on load cells, combined with an automated hopper/feed screw system, allowed for accurate metering of sand/water/guar for each VDF event. The injection pump utilized by this Mixing Plant was a 6 stage Progressive Cavity Pump with a digital flowmeter and pressure transducer mounted inline to provide real-time data monitoring.
A third component was downhole injection tooling. It included an injection assembly comprised of a specialty nozzle isolated by multiple pneumatic packers. This assembly was inserted into the borehole via an appropriate length of injection piping and an injection wellhead above the surface.
Ground surface heave is used as a method to detect fracture initiation and propagation. Since ground is a deformable medium, the observed surface heave represents the lower limit of fracture aperture and radius. Ground surface heave measurements were recorded during each fracturing event using one or more surveying levels and heave rods. A heave rod was placed at a predetermined radial distance from the fracture well. During each fracture event, the rod was observed for the maximum amount of upward motion (surface heave) and residual or permanent heave. During fracturing operations, wireless tiltmeters were placed around the injection point at a pre-determined radius in order to collect real-time surface deformation data as the fracture events were taking place.
A total of 58 locations were successfully completed. Thirty-eight points targeted a clay unit situated between 26′ and 38′ below ground surface (bgs) and 20 points were targeted 15′ to 25′ bgs. In the deeper points, approximately 1,250 pounds of sand proppant were injected within each three-foot interval for a total of ˜20 tons of sand. A fracturing slurry consisting of 200 gallons of water and 20 lbs. of guar served as the fracturing and carrier fluid. The shallow injection points received approximately half this amount
Sand/guar injection pressures varied from below 5 psi to over 200 psi depending on local variations in formation as well as extent and effectiveness of the PF events. Flowrates during sand/guar injection events were maintained around 20 gpm.
Based upon surface heave, tiltmeter, and fracturing pressure data, a conservatively estimated radius of influence (“ROI”) of about 12 to 15 feet was achieved for the soil vapor extraction (“SVE”) wells using the VDF approach. Confirmation coring also confirmed a 12-15 foot ROI was achieved through visual observations of induced fractures filled with sand. Post-injection SVE testing revealed at least a 2-3 order of magnitude increase in subsurface flow rates when compared to pre-injection or baseline conditions.

Example 2

VDF proppant injection was performed at a site in Livermore, Calif. in six boreholes that were later converted to deep dual-extraction well locations. The target treatment zone consists of unconsolidated clay, silt, and minor sand and gravel deposits. Depth to ground water is approximately 99 feet below ground surface (bgs.). Chlorinated solvents, mainly trichloroethylene (TCE), were detected in groundwater at 0.5 mg/liter.
Pneumatic fracturing was applied first to create a network of small aperture fractures. This was followed by a high flow-rate injection of a hydraulic fracturing fluid comprising a sand-guar-water mixture. The equipment used for the pneumatic fracturing included a skid-mounted fracture module equipped with a high-flow, high pressure specialty regulator, an electronically controlled and pneumatically activated control manifold, pressure transducer, inline flow meter, and a digital data-logger. Those skilled in the art will appreciate that pneumatic fracturing equipment can be adapted to be controlled by computer.
The second component comprised a portable automated slurry mixing/injection plant. The mixing/injection plant receives the sand proppant in bulk bags into a hopper. The proppant is then conveyed into a 500-gallon mixing tank and suspended in water as well as other additives such as guar gum, zero valent iron, or chemical oxidants. The content of the mixture is measured by three load-cells installed beneath the tank. The operator controls the quantity of the proppant and water entering the mixing tank at a digital control panel. A 6-stage progressive cavity pump capable of flow rates up to 70 gpm and pressure up to 500 psi serves as the injection pump on the mixing/injection plant; it is controlled by a digital variable frequency drive and monitored by a magnetic flux flow meter and pressure transducer mounted inline to provide real-time data.
During each fracture initiation, pressures in the discrete fracture interval were recorded by a pressure transducer located in-line within the conduit leading to the injection nozzle. These pressures were recorded by a data-logging system located on the injection module and accessed using a laptop computer for real-time display of the injection pressure. The pattern of a pressure-history curve (see FIG. 4) serves as an indicator of whether fracture initiation and propagation have occurred. This information allows the evaluation of two critical measurements: the fracture initiation pressure and the fracture maintenance pressure.
A typical PF event can be subdivided into three distinct stages: (1) Borehole Pressurization, (2) Fracture Initiation, and (3) Fracture Maintenance. These independent stages are illustrated in FIG. 4. It should be noted that the shape of the pressure-time history curve depends on a number of factors including in situ stress fields, geologic characteristics of the medium being fractured, depth of application, and the presence of man-made disturbances (boreholes, utilities, etc.) within the influence of fracturing.
The following section describes each stage as it relates to the PF mechanism as illustrated in FIG. 4. During the first stage identified as “Borehole Pressurization,” the pressure rapidly builds up as gas is injected into the target-sealed interval within the borehole. This stage is identified as curve segment A-B. This stage is relatively short and typically last 1-2 seconds—depending on the length of conduit (injection hose and piping) that needs to be pressurized. Once the pressure is built to a level that exceeds the in situ stress and overburden pressure within the borehole interval, the formation yields and fractures are initiated. Stage B in FIG. 4 represents the fracture initiation pressure. Following the formation fracture initiation stage, the pressure decreases rapidly and stabilizes at a plateau as the injection continues. This rapid decline in the borehole pressure is represented by segment B-C. During this time period, the injection gas flow rate usually maximizes or steadily increases as the fractures are propagated, thereby reducing the back pressure within the treatment zone to the injection. Segment C-D reflects the continual gas injection under a relatively constant injection pressure. As the injection pressure is terminated, the maintenance pressure declines rapidly from D-E.
The shape and magnitude of the pressure history curve can be affected by factors such as soil cohesion, depth, presence of leak-off points or preferential pathways, or presence of a confining layer within or above the formation.
During the fracturing events, pressure gauges were placed at select monitoring wells and adjacent injection borings, where available, to monitor pressure influence. Each pressure gauge was fitted with a maximum drag-arm indicator, which enabled field personnel to identify the maximum pressure influence at that location during each event. The data also assisted in determining which directions fractures may have propagated. In addition, the degree of pressure response can often help determine whether a monitoring point has been directly influenced (i.e., fractures propagate outward and intersect wells or boreholes) or indirectly influenced through localized groundwater displacement and/or mounding.
As in Example 1, ground surface heave was measured and recorded using a surveying level, heave rods, and wireless tiltmeters. Collected data can then be used to produce visual representations of surface deflection in all directions around the injection point. Note that surface heave either collected by a heave rod or surface tiltmeter system may not be representative of the actual formation/deformation occurring at the injection depth. Fracture formation magnitude and pattern may be affected by soil compression or variation in stratigraphy above the fracturing zone as well as the presence of a surface cover.
Pneumatic fracture initiation pressures ranged between 350 and 405 psi and maintenance pressures of at least about 50 psi and typically between about 200 to 370 psi, but not more than 500 psi. Nitrogen flow rate was at least about 250 standard cubic feet per minute and typically about 1,500 to about 2,400 standard cubic feet per minute, but not more than 2,400 standard cubic feet per minute, and with a general trending indicating less flow required to fracture the formation at shallower depths. Hydraulic injection pressures were at least 20 psi and typically between 80-190 psi, but not more than 500 psi. Approximately, 150 gallons of viscosity adjusted fluid was injected in each 3-foot interval, including about 825 lbs. of sand and 12 lbs. of guar. A total of about 48,585 lbs. of sand was injected in 6 injection points from ˜75 to 100 ft. bgs.
Soil coring in six (6) confirmatory boreholes was used to confirm the ROI of the VDF injection. The cores were collected with a 5-ft. long, 4-inch diameter split sampler in 5-ft. acetate liners. Ten (10) cores were sampled between 62 ft. and 112 ft. bgs. Seven (7) cores were sampled at each of the remaining 5 locations between the depths of 72 ft. and 107 ft. bgs. Traces of the sand proppant as well as rhodamine WT and fluorescein dyes were detected on the surface of several soil cores. The emplacement radial distance was 25 feet or more. This was confirmed by tiltmeter contours showing ground surface movement at distances 25 feet or greater.
It is to be understood that the above description is intended to be illustrative and not restrictive. For example, the above-described embodiments and variations may be used in combination with each other. Many other embodiments will be apparent to those of skill in the art upon reviewing the above description. The scope of the invention should, therefore, be determined with reference to the appended claims, along with the full scope of equivalents to which such claims are entitled. In the appended claims, the terms “including” and “in which” are used as the plain-English equivalents of the respective terms “comprising” and “wherein.”

Claims

1. A system for viscosity differential fracturing of ground comprising:

a pneumatic fracturing component; a hydraulic injection component, including a mixture of water and a suspending or thickening agent at a concentration between about 1 and about 50 mg/L, and a non-reactive or reactive material at a concentration between about 0.1 and 30 pounds per gallon; and downhole injection tooling.

2. The system of claim 1, wherein the pneumatic fracturing component includes a high-pressure/high-flow module, an injection control manifold module, a digital flowmeter module, a pressure monitoring module, and a transducer/data-logger monitoring module.

3. The system of claim 1, wherein the hydraulic injection component includes a mobile mixing and injection plant further comprising a re-circulation batch tank with a load-cell weighing module, an automated dry material hopper/feed screw module, a progressive cavity pump, a digital flowmeter module, a pressure monitoring module, and a transducer/data-logger monitoring module.

4. The system of claim 1, wherein the suspending or thickening agent comprises guar.

5. The system of claim 1, wherein the non-reactive or reactive material comprises an about 1% to about 80% solids mixture.

6. The system of claim 1, wherein the downhole injection tooling includes an injection assembly further comprising a plurality of pneumatic packers and a pipe including a plurality of slots.

7. The system of claim 1, wherein the downhole injection tooling includes an injection assembly further comprising a nozzle including a plurality of openings.

8. The system of claim 1, wherein the downhole injection tooling includes an injection assembly further comprising a spring-loaded nozzle.

9. The system of claim 1, wherein the system creates a dense fracture network with a radius of influence of at least about 12 feet and with at least about 2 orders of magnitude increase in subsurface flow rates.

10. A system for viscosity differential fracturing of ground comprising:

a pneumatic fracturing component, including a high-pressure/high-flow module, an injection control manifold module, a digital flowmeter module, a pressure monitoring module, and a transducer/data-logger monitoring module; a hydraulic injection component, including a mobile mixing and injection plant further comprising a re-circulation batch tank with a load-cell weighing module, an automated dry material hopper/feed screw module, a progressive cavity pump, a digital flowmeter module, a pressure monitoring module, and a transducer/data-logger monitoring module; and

downhole injection tooling, including an injection assembly further comprising a plurality of pneumatic packers and a pipe including a plurality of slots, wherein the system creates a dense fracture network with a radius of influence of about 12 to 15 feet and with about 2 to about 3 order of magnitude increase in subsurface flow rates.

11. A system for viscosity differential fracturing of ground comprising:

downhole injection tooling, including an injection assembly further comprising a spring-loaded nozzle, wherein the system creates a dense fracture network with a radius of influence of about 12 to 15 feet and with about 2 to about 3 order of magnitude increase in subsurface flow rates.

12. A method of using a system for viscosity differential fracturing of ground comprising the steps of:

pneumatic fracturing for about 5 to about 15 seconds using a low-viscosity fluid; and hydraulic fracturing using a fluid of greater viscosity than the low-viscosity fluid.

13. The method of claim 12, wherein the pneumatic fracturing step comprises the use of gas.

14. The method of claim 13, wherein the pneumatic fracturing step comprises the use of nitrogen gas.

15. The method of claim 14, wherein the initial nitrogen gas pressure is between about 350 to about 405 pounds per square inch.

16. The method of claim 14, wherein the maintenance nitrogen gas pressure is at least about 50 pounds per square inch, but not more than about 500 per square inch.

17. The method of claim 16, wherein the maintenance nitrogen gas pressure is between about 200 to about 370 pounds per square inch.

18. The method of claim 14, wherein the initial nitrogen gas flow rate is at least about 250 standard cubic feet per minute, but not more than 2,400 standard cubic feet per minute.

19. The method of claim 18, wherein the initial nitrogen gas flow rate is between about 1,500 to about 2,400 standard cubic feet per minute.

20. The method of claim 12, wherein the hydraulic fracturing step comprises the use of water.

21. The method of claim 12, wherein the hydraulic fracturing step comprises the use of a proppant slurry of water, guar, and sand.

22. The method of claim 21, wherein the proppant slurry pressure is at least about 20 pounds per square inch, but not more than 500 pounds per square inch.

23. The method of claim 22, wherein the proppant slurry pressure is between about 80 to about 190 pounds per square inch.

24. The method of claim 21, wherein the proppant can be injected at a flowrate of at least about 5 gallons per minute, but not more than about 25 gallons per minute.

25. The method of claim 12, wherein the method comprises cycling between the pneumatic fracturing step and the hydraulic fracturing step through at least one cycle.

26. The method of claim 25, wherein the method comprises cycling between the pneumatic fracturing step and the hydraulic fracturing step for a plurality of cycles.

27. The method of claim 25, wherein the cycling step is electronically programmable by a computer program.

28. The method of claim 26, wherein the cycling step is electronically controlled by a computer program.