CA2707209A1 - Methods for maximum shock stimulation with minimum volume, minimum rate and controlled fracture growth - Google Patents

Abstract

A method for shock stimulating in shallow dry coal bed methane formations is disclosed. The method includes accessing a target formation with a conveyance string having a stimulation tool, accumulating a stimulation fluid to a threshold pressure within a bore of the conveyance string by blocking a port on the tool. The formation is shock fractured by shock releasing the stimulation fluid by opening the port on the tool to communicate with the target formation.
Substantially immediately thereafter, subsequent injection of the stimulation fluid to the target formation is minimized or discontinued to minimize formation damage.

Description

1 "METHODS FOR MAXIMUM SHOCK STIMULATION WITH MINIMUM

2 VOLUME, MINIMUM RATE AND CONTROLLED FRACTURE GROWTH"

3

4 FIELD OF THE INVENTION

The invention relates to methodology for shock stimulation of formation 6 and more particularly to methods of introducing fracturing fluids during shock 7 stimulation for minimizing fluid injection and controlling created fracture dimensions for 8 improving the production of hydrocarbons from the formation.

BACKGROUND OF THE INVENTION

11 Conventional fluid fracturing of subterranean formations comprises 12 positioning a tool in a cased wellbore traversing a formation to be fractured. The 13 tool straddles perforations in the cased wellbore. Fluid is pumped down a tubular 14 conduit from surface to the subterranean tool at a flow rate and pressure sufficient to hydraulically fracture the formation.

16 The exact nature of the resulting fractures is not fully known and will 17 vary for different formations. As set forth in US Patent 4,995,463 to Kramm et al., 18 issued in 1991, the fracture mechanics and fluid flow behavior in cleated, coal bed 19 methane (CBM) formations is substantially different that those in sandstone and the like which are more conventionally known for oil and gas operations.

21 A known method for hydraulically fracturing formations comprises 22 exposing the formation to gradually greater and greater hydraulic pressures where 23 at least one fracture is formed by pumping a fluid. The pumping continues until 1 either the extent of planned fracturing is achieved or proppant used to hold the 2 created fractures open bridge off in the fracture(s) or perforation(s). It is believed 3 that some formations are less effectively fractured using such known and common 4 processes.

In general, the compaction of a formation made up of any kind of 6 mineralogy (such as coal, sandstone, other, or a combination thereof), is related to 7 the overburden weight and force of the rock above it. Typically, at an overburden 8 rock gradient about 22 kPa/m in many geographical areas, the deeper below the 9 earth's surface of the formation, the more vertical force you have on the said formation. A portion of the vertical force will also transfer into a horizontal 11 component as well through a rock property called Poisson's ratio which relates 12 vertical strain to horizontal strain. Additional horizontal force(s) through regional 13 stress and/or strain are also possible from faulting, local mountain ranges or other 14 reasons. The various forces on a formation from various sources and directions will cause compaction which usually causes both a loss of permeability and porosity.

16 As a result, the general rule is the deeper the formation, the lower 17 permeability and porosity potential; the shallower the formation, the higher the 18 permeability and porosity potential. When formations have more porosity, the well 19 storage volume of hydrocarbons is increased for more asset value by reserves bookings. When formations have more permeability, the hydrocarbons in the 21 storage volume will flow at higher rates to the well to result in more cash flow by 22 hydrocarbon sales. Both cash flow and asset value of a well can be important in the 1 economics of recovering natural resources from the earth rather than leaving them 2 abandoned there for the life of the well. Industry prefers to drill wells in a region to 3 intersect a local area of a target formation that is present to maximize permeability 4 and porosity so that cash flow, assets and economics are high enough to allow recovery of hydrocarbons as opposed to abandon them in the earth.

6 CBM, as well as other naturally fractured or shear inducible 7 formations, can be particularly affected by compaction as the volume contained in 8 the natural fractures, otherwise known as cleats for CBM, is affected by the forces 9 that compact them. The more compaction on natural fractures, the less retained porosity and permeability that those natural fractures contain which directly affects 11 well economic evaluations. The natural fractures and cleats usually have a much 12 higher permeability and porosity than the bulk (otherwise known as matrix) 13 formation rock. In both the case of natural fractures or matrix formation rock, 14 increasing compaction forces can negatively affect permeability and porosity.

In general, shallow formations have a higher tendency to have enough 16 permeability and porosity to be economic even to the point of not needing to be 17 hydraulically fractured for methane or other hydrocarbons to be conducted to the 18 well bore and produced from the wellhead. In many cases, perforating holes to 19 connect the reservoir and well bore sometimes followed by a small volume of acid is all that is required to reach economic rates to produce a well. The acid, if required, 21 dissolves the small amount of damage, otherwise known as skin, which impedes 22 flow of well according to Darcy's equation as known to those skilled in the art.

1 There are many scenarios where formations do not respond in an 2 acceptable fashion in terms of hydrocarbon production to perforating and acidizing 3 alone. As known to those skilled in the art, examples of some of these scenarios 4 can include under-pressured, or simply low pressured, formations not having enough pressure to adequately flow liquids, such as acid, brines or fracturing fluid 6 out of the formation and well bores which can cause a fluid or water block that 7 prevents hydrocarbons from flowing to the well from the formation.

8 Another example can be sub-irreducibly water saturated reservoirs 9 absorbing water, if present, to damage the formation and reduce permeability very drastically to drop the methane flow rates below economically viable rates.
One 11 instance in which this effect occurs is very close to the well due to drilling fluid and 12 cement damage causing a skin effect. If the well is fractured with water based 13 fluids, even water foams or water emulsions, the newly created fractures will result 14 with a skin effect also that is severe enough on the fracture face that there is not significant economic improvement over the removal of the skin that was originally 16 near the well.

17 Swelling clay mineralogy(s) in the formation can also absorb water in 18 acid or fracturing fluids that will partly or completely block hydrocarbon flow within 19 the formation by filling in the porosity thus reducing the permeability below economically viable rates, sometimes even to zero flow.

21 Another example are migrating clays and fines in the formation can 22 mobilize through injection of acid or fracturing fluids and accumulate to partly or 1 completely plug flow paths in the formation and thus reducing the permeability 2 below economically viable rates. Through density and/or viscosity as the liquids 3 flow back to the well, these blocks can accumulate in the proppant pack, natural 4 fractures or matrix pore throats.

Another example can include relative permeability reductions to the 6 conductivity of hydrocarbons to the well bore after the stimulation which can 7 increase the capillary pressure and flow back of the fracturing fluid from the 8 formation.

9 In the case of conventional fracturing with fluids, the interface between created intersecting cracks and hydraulic fractures can be impaired, preventing 11 significant flow of hydrocarbon into the hydraulic fracture from the formation and 12 thus the well. In the case of only perforating, the interface created between the 13 formation and well bore can be impaired, preventing significant flow of 14 hydrocarbons into the well from the formation.

In general, formations are accessed by drilling open hole(s), 16 cementing casing in the open hole(s) and perforating the well to create a 17 communication interface between the formation and the well, also known as skin, 18 which is the impediment of hydrocarbon flow according to Darcy's law. In the stage 19 of drilling of a well, a damaged area of varying thickness can be created as the drilling mud leaks into the formation before the drilling mud plugs the formation and 21 the drilled open hole interface. In the stage of cementing a well, there can be a 22 damaged interface of varying thickness as the cement displaces the mud, only to

5 1 leave cement filtrate in the formation and a cement interface between the formation 2 and the casing. In the case of perforating a well, there is a very thin interface of 3 damaged formation that impairs the flow of methane into a well bore.

4 In some circumstances, there are limited options to removing the effect of an interface or skin, by any chosen common conventional means. The

6 limitations can be for several factors or reasons as known to those skilled in the art

7 including, but not limited to: 1) the formation is above the base of ground water (has

8 fresh water aquifers below the formation) and thus there are restrictions to the

9 injection of foreign material. Government regulations often are involved in whether these formations can be stimulated, and if they can be stimulated, how they can be 11 stimulated. In some regions the restrictions are at 200 m or shallower, unless the 12 government has specifically made the limit deeper due to environmental, fresh 13 water existing deeper than 200 m or other reasons. 2) A first injection well A is 14 close to an adjacent second well B such that pressure generated during injection in well A will negatively affect well B. Well B might be a fresh water supply well or a 16 petroleum well that is either active or not active. 3) The cost of injecting into the 17 formation does not meet the economical criteria based on the achieved results. The 18 cost of injecting into a well contains both fixed service costs related to injection rate 19 and variable costs related to injection volume. 4) The formation is so shallow that there is concern that injection might reach the surface. 5) The injected volume 21 could cause fractures in the target formation that, rather than extending laterally 22 through the target formation, might grow up or down and communicate with another 1 formation (e.g. to an aquifer that is not to be stimulated nor made to communicate 2 with the well bore). 6) Concerns of ground impact due to the large area required by 3 the commonly large number of storage vessels and pump trucks.

4 In the context of shallow dry CBM, as is known to those skilled in the art, commercial and economical production of methane is only after stimulating such 6 formations by means of high rate nitrogen injection through coiled tubing.
In many 7 cases volumes of nitrogen used are 5,000 scm of nitrogen gas per formation and 8 pumped at rates of 1,000 scm/min to 1,500 scm/min. In many areas of oil and gas, 9 but particularly in the region where the field trials were done, there are environmental and surface access concerns as many of the wells are on farm land 11 that grows food. Some specific perceived concerns are the noise pollution, road 12 safety for domestic traffic, dust creation that wind carries off to live stock breathing it 13 in, and the crop that is forfeited because of the large area required by the storage 14 vessels and pump trucks. Some of the equipment used are storage vessels for liquid nitrogen, for which the higher total required volumes of gas require more 16 vessels of liquid nitrogen. Increased road traffic occurs as some nitrogen storage 17 vessels are so heavy that they need to be hauled to and from the well empty, and 18 smaller liquid nitrogen transport vessels are then required to make several round 19 trips to fill the empty storage vessels.

Accordingly, particularly in the area of the unique fracture mechanics 21 of CBM, there is still a need for economical fracturing techniques which maximize 1 effectiveness to the target formation while minimizing risk to adjacent formations or 2 environmental issues.

As stated above, for many formations, including shallow CBM, it has 6 been the conventional approach to use large volumes of injected nitrogen per 7 formation and high rates of injection. Concerns arising from such large injection 8 volumes include adjacent formation communication, undesirable fractures, 9 environmental issues, surface access issues, or other issues.

A shock stimulation apparatus and methodology was previously 11 disclosed in Canadian Patent 2,565,697, by Collins et al., and issued July 22, 2008.
12 The shock stimulation applies a shock of an initial volume of nitrogen and then 13 follows with large injection rates and volumes of nitrogen in accordance with 14 conventional wisdom. Due to the high friction to the flow of stimulation fluids in conveyance strings such as coiled tubing, conveyance of stimulation fluid to the 16 formation is otherwise severely restricted if not for accumulation and surge release 17 technique.

18 In a broad aspect of the present invention, a shock fracturing method 19 comprises isolating a target formation at a set of perforations in a cased well, accumulating a stimulation fluid (such as inert nitrogen gas) to a threshold pressure, 21 releasing the stimulation fluid to communicate with and shock fracture the formation, 22 and thereafter substantially discontinuing flow of the stimulation fluid to minimize 1 formation damage. As usual, the fracturing promotes subsequent hydrocarbon flow 2 through the interface between the formation and well bore while the methods of the 3 invention controlling the distance of stimulation from the well and into the formation.
4 One approach is to access the formation with coiled tubing extending downhole through the wellbore for conveying a tool to the formation, the tool having 6 an uphole seal and a downhole seal spaced uphole and downhole of the perforation 7 tunnel interfaces for isolation thereof; and blocking the coiled tubing at the tool for 8 accumulating the stimulation fluid at the threshold pressure in the coiled tubing; and 9 suddenly opening the bore of the conveyance string at the tool for releasing the stimulation fluid through a port in the tool to surge release into the perforation tunnel 11 interfaces.

12 In one embodiment of the invention as applied specifically for shallow 13 dry CBM formations, the formation is first shocked and then injection is minimized 14 thereafter with only minimal volume or substantially no follow-up injection of nitrogen. Contrary to the prior art approach of continued injection at high rates, 16 embodiments of the present invention minimize the post-shock volumes of nitrogen 17 which results in fewer nitrogen pumps, fewer nitrogen storage vessels, reduced 18 costs and maximum effect is gained with minimum or no risk to the target formation, 19 adjacent formations or the environment.

In another aspect of the invention, a method for unblocking the 21 perforation tunnel in subterranean formations penetrated by a wellbore comprising 22 isolating perforation tunnel interfaces in the subterranean formation, accumulating a 1 small amount of stimulation fluid (such as inert nitrogen gas) to a threshold pressure 2 while isolated from the perforation tunnel interface, and releasing the stimulation 3 fluid to communicate with the isolated perforation tunnels to promote hydrocarbon 4 flow through the interface between the formation and well while controlling the distance of stimulation into the formation .

6 In one preferred embodiment, after the initial release or shock of 7 stimulation fluid from the conveyance string or coiled tubing, the injection of 8 stimulation fluid into the coiled tubing, is discontinued after an additional 1500 scm 9 (standard cubic metres at 14 psia and 15 C) is pumped. In yet another preferred embodiment, the injection of stimulation fluid into the coiled tubing ceases after 11 release of the accumulated stimulation fluid.

14 Figure 1 illustrates a schematic of the pressure and flow rates of stimulation fluids during a shock treatment with immediate discontinuance of the 16 fracturing volumes;

17 Figure 2 illustrates a schematic of the pressure and flow rates of 18 stimulation fluids during a shock treatment with minimal flow of post-shock volumes 19 of stimulation fluids;

Figure 3A illustrates the production over time for a shallow CBM well 21 (perforation intervals of less than a depth of 200 m) according to a second example 1 well, stimulated using an embodiment of the present invention and compared to 2 neighboring wells within a one mile radius;

3 Figure 3B illustrates the production over time for a CBM well according 4 to a second example well and compared to neighboring wells within a one mile radius;

6 Figure 4A illustrates the production over time for a CBM well closely 7 adjacent to a nearby abandoned well according to a third example well, stimulated 8 using an embodiment of the present invention and compared to neighboring wells 9 within a one mile radius;

Figure 4B illustrates the production over time for the CBM well 11 according to Fig. 4A, and normalized by the number of formations that were treated;
12 and 13 Figure 4C illustrates the production over time for the CBM well 14 according to Fig. 4A, and normalized by the amount of nitrogen pumped into the well.

18 In fracturing or stimulation operations, a target formation is isolated for 19 receiving pressurized stimulation fluids. The target formation is typically traversed by a cased well, the casing having been perforated at the target formation, establishing 21 communication between the well and the formation. Gaseous fluids such as nitrogen, 22 are delivered downhole through the well to the formation at a rate which exceeds the 1 fluid loss into the formation. Thus tubing pressure and bottom hole pressure increase 2 where, typically, at a certain pressure, the formation fractures and fluid rates are 3 usually increased for a period to accommodate increased flow into the fractures. The 4 increased fluid rates and continued injection results in large volumes of stimulation fluid which results in the corresponding risk and costs set forth above.

6 For formations such as shallow coal bed methane (CBM), embodiments 7 of the present invention are employed to obviate the risks and costs of conventional 8 stimulation operations.

9 With reference to Fig. 1, instead of the high volume and high injection rates of the prior art, stimulation fluid is accumulated before release to the formation.
11 Fracturing fluid, such as gaseous nitrogen, is pumped down coiled tubing to a shock 12 tool for building or accumulating pressure to a pre-determined threshold pressure 13 which is usually tuned to the formation, including formation depth and lithology. The 14 shock tool has a fluid outlet which straddles by isolating seals so as to direct stimulation fluid, when released, from the outlet to the isolated formation between the 16 isolating seals. As shown in Fig. 1, the tubing pressure correspondingly rises as the 17 fluid is pumped into the closed coiled tubing. The bottomhole pressure between the 18 casing and the tool remains at formation pressure as the coil tubing pressure builds at 19 surface and at the tool.

At the threshold pressure, the shock tool opens, and there is a sudden 21 release of the fracturing fluid from the fluid outlet to impact the formation. Substantially 22 immediately, the bottomhole pressure rises and the tubing pressure falls and 1 equilibrates to substantially the same pressure as the accumulated stimulation fluid 2 applying the full fracturing pressure to the formation and dissipates therein. It is 3 believed that a CBM formation is particularly favourably affected by a shock 4 application of the fracturing fluid. The predetermined fracturing pressure accumulated at the shock tool can be above the fracture gradient of the formation or above the 6 overburden weight of about 22 kPa/meter of depth or both. For example, fracturing 7 fluid pressure for a formation depth of about 600 meters could be initially set for about 8 21 MPa.

9 In another embodiment, with reference to Fig. 2, after the shock tool opens and there is a sudden release of the fracturing fluid, a further flow of stimulation 11 fluid is continued for a short period, adjusted to accommodate the formation.

12 Accordingly, as set forth in Fig. 1, after the initial release or shock of 13 stimulation fluid from the conveyance string or coiled tubing, the injection of 14 stimulation fluid into the coiled tubing, and accordingly into the formation, is discontinued substantially immediately. In the embodiment of Fig. 2, after the initial 16 release or shock of stimulation fluid, and a minimum additional or extra volume of 17 stimulation fluid is injected, for example, a further 600 to 1500 scm (standard cubic 18 metres at 14 psia and 15 C) can be pumped into the formation.

2 A non-producing first example well was stimulated using an embodiment 3 of the present invention. The resulting production was compared to three 4 neighbouring wells within a radius of one mile of the first example well.

The first example well was characterized by having 17 sets of 6 perforations in a shallow formation. The perforations intervals are illustrated in Table 1 7 as listed in the "Perforated Interval" column. Casing (114.3 mm, 14.14 kg/m, 8 casing) for the first example well was isolated below 623 m. Prior to the stimulation, 9 this first example well was not producing.

At the job site, all truck-mounted equipment was positioned and 11 connected in accordance with standard operating practice. A shock stimulation tool 12 according to CA Patent 2,565,697 was fit to coiled tubing and positioned adjacent 13 the formation for stimulation. The coiled tubing was pressure tested and had a 14 maximum working pressure set for the job.

Each set(s) of perforations were isolated in turn starting with the deepest 16 zone first, and subsequently moving shallower in the well. Each specified perforation 17 interval was isolated using zonal isolation cups. Surface equipment pumped nitrogen 18 gas into the coiled tubing, acting as a coiled tubing accumulator, being temporarily 19 blocked by the shock tool. For each selected and isolated perforation interval, the shock tool was fired, with the associated shock fracturing resulting, and according to 21 an embodiment of the invention, an extra but minimum volume of nitrogen was 22 pumped thereafter into the formation.

1 Table 1 lists the surface pump rate, the volume pumped until shock tool 2 firing and the extra volume pumped after the shock tool was fired. The fracture 3 initiation or breakdown pressure was also observed and reported.

4 Historically, the total nitrogen used per shallow CBM formation zone, including the release of the accumulated nitrogen using a shock tool and subsequent 6 extra volumes pumped thereafter, has been about 3500 to 5000 scm. As shown in 7 Table 1 below, Applicant instead used lesser total volumes (Vol to Firing +
Extra Vol) 8 of about 1700 to 3200 scm.

9 Table 1: First Example Well - Stimulation information Perforation Interval Vol to Firing Extra Vol Surface Rate Breakdown m scm scm scm/min Pressure (MPa) 356.8 m to 357.2 m 1383 1842 1133 29.55 312.1 m to 312.6 m 1490 1536 1152 31.52 294.4 m to 294.9 m 1315 387 1045 29.02 287.9 m to 288.4 m 1327 1697 1145 27.37 246.6 m to 247.6 m 971 1290 1142 24.88 203.3 m to 204.3 m, 199 m to 199.9 m 1254 1433 1129 26.5 193.3 m to 194.3 m 1209 787 1067 26.38 175.2 m to 175.7 m 1370 1453 1157 26.35 163.7 m to 164.5 m 1348 843 1091 27.2 147.8 m to 148.3 m 1393 604 1065 27.6 134.2 m to 134.5 m 1413 1047 1091 28.3 122.3 m to 122.8 m 1250 754 1014 26.38 109.3 m to 109.8 m 1275 974 1107 26.68 103.5 m to 105 m 1244 1448 1151 25.13 98 m to 98.4 m 1311 1190 1135 27 11 Gas flow rates from the well after fracturing initially averaged 5.17X103 12 m3/day.

1 Neighbouring shallow CBM wells, within a radius of one mile, had an 2 initial average production of 1.99 X103 m3/day, 4.48 X103 m3/day, 5.12 X103 m3/day 3 and 6.65 X103 m3/day.

4 Accordingly, this example first well had better initial production than 75%
of the neighbouring wells, or 13.3% better than the average production while using 6 14.3 to 26.5% less nitrogen than historical treatments. This magnitude of nitrogen 7 savings can be in the order of 1/3 of the cost of the fracturing program.

8 The Energy Resources Conservation Board (ERCB) of Alberta, Canada 9 has issued Directive 027 which states that one must not conduct fracturing operations at depths less than 200 m unless they have fully assessed all potential impacts prior to 11 initiating a fracturing program. Such assessment ensures protection of water wells 12 and shallow aquifers. Further, it is expected that nitrogen pumping volume should be 13 restricted to 15,000 scm/m of coal unless prior ERCB approval is obtained.

14 Note that nine of the 17 perforations intervals were less than the 200m threshold. Applicant believes this program for this first example well met such 16 restrictions for shallow CBM formations, had an average nitrogen volume per meter of 17 coal of about % of the 15,000 scm maximum, and further obtained production from 18 otherwise inaccessible formation reserves, had a reduced surface footprint, and 19 reduced road traffic.

2 The second example well was characterized by having 22 sets of 3 perforations in shallow, dry Edmonton formation and Belly River formation coals as 4 shown in Table 2 in the "Perforated Interval" column. Casing (114.3 mm, 14.14 kg/m, J-55 casing) for the first well was isolated at total depth of 817 m. Prior to the 6 stimulation, the well was not producing.

7 At the job site, all truck-mounted equipment was positioned and 8 connected in accordance with standard operating practice. A shock stimulation tool 9 according to Assignee's CA Patent 2,565,697 was fit to coiled tubing and positioned adjacent the formation for stimulation. The coiled tubing was pressure tested and 11 had a maximum working pressure set for the job.

12 Each set(s) of perforations were isolated in turn starting with the deepest 13 zone first, and subsequently moving shallower in the well. Each specified perforation 14 interval was isolated using zonal isolation cups. Surface equipment pumped nitrogen gas into the coiled tubing, acting as a coiled tubing accumulator, being temporarily 16 blocked by the shock tool. For each selected and isolated perforation interval, the 17 shock tool was fired, with the associated shock fracturing resulting, and according to 18 an embodiment of the invention, an extra but minimum volume of nitrogen was 19 pumped thereafter into the formation.

Table 2 lists the surface pump rate, the volume pumped until shock tool 21 firing and the extra volume pumped after the zone fired. The initiation or breakdown 1 pressure was also observed and reported. These rates used were substantially lower 2 than the 1000 to 1500 scm/min industry common practise for shallow CBM
formations.

4 Table 2: Second Example Well - Stimulation information Vol to Firing Extra Vol Surface Rate Breakdown Perf Interval (m) scm scm scm/min Pressure (MPa) 791.7 m to 792.2 m 1907 534 615 42.0 786.3 m to 786.8 m 1259 1427 1018 32.0 514.6 m to 515.1 m 1068 750 789 38.5 488 m to 488.5 m 1165 871 775 33.5 483.7 m to 484.2 m 1044 771 789 30.7 471 m to 472 m 308 3205 1162 10.0 453.7 m to 454.2 m 1132 1626 752 36.2 426 m to 427.5 m 995 3789 976 22.0 416mto418m, 414 m to 416 m 1537 9456 1234 26.2 410.5 m to 411 m 699 1798 1098 18.8 392.1 m to 393.1 m 639 3376 1128 18.3 387 m to 388 m, 383.5 m to 385 m 680 6578 1210 18.5 375.9 m to 376.4 m, 373.9 m to 374.9 m, 371.4 m to 371.9 m 705 6559 1190 19.6 362.7 m to 363.2 m 793 2211 1079 23.2 332 m to 332.5 m 799 1256 693 24.1 319.4 m to 320.9 m 784 4456 1167 20.3 282.2 m to 282.7 m 861 528 701 27.7 277.1 m to 277.6 m 828 1064 790 23.7 6 Gas production from neighbouring wells within a one mile radius of the 7 second example well are given in Figs. 3A and 3B. Gas flow rates from the second 8 example well after fracturing initially averaged 8.0 X103 m3/day during the first 2 9 months. All shallow CBM wells within a radius of one mile had initial average production (for the first 2 months in X103 m3/day) of 3.3, 4.6, 4.6, 6.2, 7.3, 7.5, 9.0, 11 10.3, and 13.3. This example well had better initial production than 67% of the wells 1 within a one mile radius, or 8.8% better than the average production while injecting a 2 total (for all intervals stimulated with nitrogen) of 67,400 scm of nitrogen gas where the 3 typical industry standard ranges would have been from about 55,000 to 110,000 scm.
4 The average nitrogen surface injection rate utilized was 4.6% to 36.5% lower than the typical industry standard for shallow, dry CBM in the area, and the lowest rate utilized 6 was 38.5% to 59% lower. In addition, this example well had a reduced surface 7 footprint and reduced road traffic due to requiring less nitrogen pump capacity than 8 standard practises in the area on shallow, dry coal.

THIRD EXAMPLE WELL

11 The third example well was characterized by having 13 sets of 12 perforations in shallow, dry Edmonton formation and Bearpaw formation coals as 13 shown in Table 3 in the "Perforated Interval" column. The casing (114.3 mm, 14.14 14 kg/m, J-55 casing) was had a total depth of 353 m. Prior to the stimulation, the well was not producing.

16 In the immediate area was an abandoned well 36 m away where there 17 was concern of communication to which an appropriate engineering design was done.
18 Very low total volumes of nitrogen were applied to avoid breakthrough to the 19 abandoned well. Illustrative of the risks includes the ERCB Directive 027 which restricts fracturing wells adjacent water wells and requires a minimum horizontal offset 21 of 200 m.

1 At the job site, all truck-mounted equipment was positioned and 2 connected in accordance with standard operating practice. The 83 mm, 8.037 kg/m, 3 QT-700 coiled tubing was pressure tested to 50 MPa and had a maximum working 4 pressure of 42 MPa for the job. The stimulation was pumped down coiled tubing utilizing zonal isolation cups and shock tool in the casing.

6 Each set(s) of perforations were isolated in turn starting with the deepest 7 zone first, and subsequently moving shallower in the well. Nitrogen gas was 8 introduced to the coiled tubing accumulator. Table 3 lists the surface pump rate, the 9 volume pumped until shock tool firing and the extra volume pumped after the shock tool fired. The breakdown pressure was also observed and reported. These rates 11 used were extremely low compared to the 1000 to 1500 scm/min industry common 12 practise for shallow CBM formations. Figs. 4A, 4B and 4C illustrate the resulting 13 production form the third example well post-stimulation.

Table 3: Third Example Well - Stimulation information Vol to Firing Extra Vol Surface Rate Breakdown Pressure Perf Interval (m) (scm) (scm) scm/min (MPa) 314.9 m to 315.2 m, 311.7 m to 312.6 m 443 1167 300 18.0 305.4 m to 305.7 m 541 371 300 22.0 297.5 m to 298 m 389 621 300 15.8 289.8 m to 291 m 453 561 300 18.4 231.3 m to 231.8 m 470 542 300 19.1 224.6 m to 225.8 m 455 552 300 18.5 207.3 m to 207.8 m, 205.8 m to 207 m 450 557 300 18.3 192.7 m to 194.6 m 458 555 300 18.6 176.7 m to 177.5 m, 172.8 m to 175.9 m 455 553 300 18.5 162.6 m to 163.1 m 441 566 300 17.9 2 Gas production from all shallow, dry coal wells within a one mile radius 3 of the example well is given in Figure 4B, which has filtered out the wells with deep, 4 dry coals that are commingled and normalized the production to the number of target formations in the well. Gas flow rates from the example well after fracturing initially 6 averaged 1.03 X103 m3/day during the first 6 months. For the first 6 months, all 7 comparison wells had an average production of 0.97, 1.86 and 2.15 X103 m3/day.
8 This third example well had better initial production than 33% of the comparison wells, 9 or 38% worse than the average production while injecting a total of 10,600 scm of nitrogen gas (78% less volume on average) where the comparison wells received 11 from 60,155 scm, 46,480 scm and 40,620 scm of nitrogen gas. If the comparison well 12 production was normalized on the example well injection volume of nitrogen of 10,600 13 scm as in Figure 4C, the average production during the first 6 months would be 0.27, 14 0.40 and 0.41 X103 m3/day. When normalized on nitrogen injection volume, the example well is better than 100% of the offset wells and has 186% better average 16 production. The average nitrogen surface injection rate utilized was 70% to 80%
17 lower than the typical industry standard for shallow, dry CBM in the area.

18 Note that three of the 13 perforations intervals were less than the 200m 19 threshold. Further, there were no issues with communication with the nearby well 36 m away. In addition, this third example well was successfully treated and within the 21 guidelines for shallow wells affected by government regulations, treated without 22 communication to nearby wells affected by government regulations, reduced surface 1 footprint and reduced road traffic due to requiring less nitrogen pump capacity and 2 less total volume than the nearby comparison wells.

Claims (6)

THE EMBODIMENTS OF THE INVENTION FOR WHICH AN
EXCLUSIVE PROPERTY OR PRIVILEGE IS CLAIMED ARE DEFINED AS
FOLLOWS:

1. A shock fracturing method comprising:

isolating a target formation at a set of perforations in a cased well;
injecting a stimulation fluid;

accumulating the stimulation fluid to a threshold pressure;

releasing the stimulation fluid at the threshold pressure to communicate with and shock the formation; and thereafter, substantially discontinuing flow of the stimulation fluid to minimize formation damage.

2. The method of claim 1 wherein discontinuing flow of the stimulation fluid occurs after about an additional 1500 standard cubic meters of stimulation fluid is injected.

3. The method of claim 1 wherein discontinuing flow of the stimulation fluid further comprises ceasing injection of the stimulation fluid substantially immediately after releasing of the accumulated stimulation fluid.

4. A method for unblocking perforations in subterranean formations penetrated by a wellbore comprising:

isolating perforation tunnel interfaces in the subterranean formation;
accumulating a small amount of stimulation fluid to a threshold pressure while isolated from the perforation tunnel interfaces; and releasing the stimulation fluid at the threshold pressure to communicate with the isolated perforation tunnels to promote hydrocarbon flow through an interface between the formation and wellbore while controlling a distance of stimulation into the formation.

5. A method for shock fracturing in a target formation having perforation tunnel interfaces in shallow dry coal bed methane formations comprises the steps of:

accessing the target formation with a conveyance string for conveying a stimulation tool having an uphole seal and a downhole seal axially spaced apart for isolation of the perforation tunnel interfaces;

blocking the tool at the target formation for accumulating a stimulation fluid within a bore of the conveyance string to a threshold pressure;

opening the tool at the threshold pressure for releasing the accumulated stimulation fluid through a port in the tool to surge release the stimulation fluid from the bore of the conveyance string into the perforation tunnel interfaces for communication with and fracturing of the target formation;

minimizing subsequent injection of stimulation fluid into the perforation tunnel interfaces for minimizing damage to the target formation, adjacent formations and the environment.

6. The method of claim 5 wherein minimizing subsequent injection of stimulation fluid further comprises discontinuing substantially immediately the injection of stimulation fluid.