CA2716446A1 - Effective horizontal drilling through a hydrocarbon reservoir - Google Patents

Abstract

A method of effective horizontal drilling through a hydrocarbon reservoir within a subterranean formation, the method comprising: introducing liquefied petroleum gas fracturing fluid through a well into the hydrocarbon reservoir; and subjecting the liquefied petroleum gas fracturing fluid in the hydrocarbon reservoir to fracturing pressures to fracture the subterranean formation and form fractures extending through the hydrocarbon reservoir with an effective frac length greater than 200 meters measured from an injection point of the well.

Description

EFFECTIVE HORIZONTAL DRILLING THROUGH A HYDROCARBON RESERVOIR
TECHNICAL FIELD
[0001] This document relates to methods of effective horizontal drilling through a hydrocarbon reservoir within a subterranean formation.

BACKGROUND

[0002] Many oil reservoirs are found in subterranean formations as thin beds of hydrocarbons that extend a relatively long lateral distance. Because of the wide area covered by these beds, it has been found to be economical in some cases to drill a deviated or horizontal well through the oil reservoir. Referring to Figs. lA-B, an example of horizontal drilling through a hydrocarbon reservoir 10 is illustrated. As shown, multiple wells 11 may be drilled from the same bore or from individual parent wells 13. Horizontal wells drilled in this fashion can produce more oil than a vertical well drilled into the same reservoir.

[0003] Horizontal wells have other applications as well, such as producing fractured reservoirs, formations with water and gas coning problems, waterflooding, heavy oil reservoirs, gas reservoirs, and in Enhanced Oil Recovery (EOR) methods such as thermal and C02 flooding.

[0004] Despite the growth of horizontal well drilling, horizontal wells have numerous disadvantages compared to conventionally drilled wells. Firstly, horizontal wells cost much more than a vertical well. Some of this cost comes from unique technical requirements that may be required for drilling the particular reservoir, such as a need to case the well or provide a slotted liner. Secondly, in general only one zone at a time can be produced with a horizontal well. Thus, if the reservoir has multiple pay-zones, especially with large differences in vertical depth, or large differences in permeabilities, it is not easy to drain all the layers using a single horizontal well. Thirdly, horizontal wells have a relatively low success rate, with only 2 out of 3 drilled wells in the US achieving commercial success.
Given the higher startup cost, the low success rate creates extra initial risk for a project.
Fourthly, as shown in Figs. IA-B, multiple offshoot wells, such as wells 11A, may be required in order to fully access the oil in the reservoir. Such wells 11A
represent an extra I

cost in technology and expertise. Finally, horizontal drilling is complex and requires specialized tools and knowledge, which further add to the high cost and risk associated with horizontal and directional drilling.

[0005] In the conventional fracturing of wells, producing formations, new wells or low producing wells that have been taken out of production, a formation can be fractured to attempt to achieve higher production rates. Proppant and fracturing fluid are mixed in a blender and then pumped into a well that penetrates an oil or gas bearing formation. High pressure is applied to the well, the formation fractures and proppant carried by the fracturing fluid flows into the fractures. The proppant in the fractures holds the fractures open after pressure is relaxed and production is resumed.

[0006] Conventional fracturing fluids include water, frac oil, methanol, and others.
However, these fluids are difficult to recover from the formation, with 50 %
of such fluids typically remaining in a formation after fracturing. Referring to Figs. 3A-B, these fluids are also limited to a relatively short maximum effective frac length 12, irrespective of the length of the created fracture 14 actually formed. Effective frac length 12 refers to the extent of the created fracture 14 through which well fluids may be produced into the well 11.

[0007] Various alternative fluids have been disclosed for use as fracturing fluids, including liquefied petroleum gas (LPG), which has been advantageously used as a fracturing fluid to simplify the recovery and clean-up of frac fluids after a frac. Exemplary LPG frac systems are disclosed in W02007098606 and US 3,368,627. However, LPG
has not seen widespread commercial usage in the industry, and conventional frac fluids such as water and frac oils continue to see extensive use.

SUMMARY

[0008] A method of effective horizontal drilling through a hydrocarbon reservoir within a subterranean formation, the method comprising: introducing liquefied petroleum gas fracturing fluid through a well into the hydrocarbon reservoir; and subjecting the liquefied petroleum gas fracturing fluid in the hydrocarbon reservoir to fracturing pressures to fracture the subterranean formation and form fractures extending through the hydrocarbon reservoir with an effective frac length greater than 200 meters measured from an injection point of the well.

[0009] In various embodiments, there may be included any one or more of the following features: The hydrocarbon reservoir may be formed within a geologic formation and the geologic formation has been previously subject to horizontal drilling.
The hydrocarbon reservoir may have an average thickness of less than 100 meters measured parallel to vertical, where the average thickness is computed over a region defined by the actual extent of the fractures. The well may be a vertical well. The well may be a directionally drilled well. The well may be a horizontal well. The fractures may have an effective frac length greater than 300 meters. The fractures may have an effective frac length greater than 500 meters. The fractures may have an effective frac length greater than 1000 meters. Proppant may be supplied from a proppant supply source into the liquefied petroleum gas fracturing fluid prior to introducing the liquefied petroleum gas fracturing fluid into the well. The proppant supply source may be rated to hold 200 tonnes or more of proppant. The proppant supply source may be rated to hold 500 tonnes or more of proppant.
The proppant supply source may be rated to hold 1000 tonnes or more of proppant. The proppant supply source may comprise plural proppant supply sources. The plural proppant supply sources may be connected in parallel. Liquid may be added to proppant in the proppant supply source. The liquid may comprise liquefied petroleum gas. A
gelling agent may be supplied into the liquefied petroleum gas fracturing fluid for assisting carriage of proppant into the hydrocarbon reservoir. Fracturing may comprise shutting in the liquefied petroleum gas fracturing fluid in the well for an extended period of time sufficient to form the effective frac length. Shutting in may comprise shutting in for 24 hours or more. Shutting in may comprise shutting in for 48 hours or more. Shutting in may comprise shutting in for a week or more. The hydrocarbon reservoir may be contained at least in part within a sandstone formation. The hydrocarbon reservoir may be contained at least in part within a siltstone formation. The hydrocarbon reservoir may be contained at least in part within a shale formation.

[0010] These and other aspects of the device and method are set out in the claims, which are incorporated here by reference.

BRIEF DESCRIPTION OF THE FIGURES

[0011] Embodiments will now be described with reference to the figures, in which like reference characters denote like elements, by way of example, and in which:

[0012] Fig. IA is a top plan view illustrating the positioning of a plurality of horizontal wells drilled through a hydrocarbon reservoir.

[0013] Fig. lB is a side elevation view of the plurality of horizontal wells of Fig. 1A.

[0014] Fig. 2A is a top plan view illustrating a fracture pattern within a hydrocarbon reservoir from a vertical well.

[0015] Fig. 2B is a side elevation view of the fracture pattern of Fig. 2A.

[0016] Figs. 3A-B are schematics of a fracture created by conventional fracturing fluids such as oil or water.

[0017] Figs. 4A-B are schematics of a fracture created by fracturing with LPG.

[0018] Fig. 5 is a graph that illustrates the improvement in production achievable with LPG fracturing fluids.

[0019] Fig. 6 is a graph showing the improvement in production achieved with an LPG fracture treatment.

[0020] Fig. 7 is a graph illustrating the saturation curves for several liquids, including propane.

[0021] Figs. 8 and 9 are graphs that illustrate the differences in viscosity between various frac fluids.

[0022] Fig. 10 is a graph that illustrates the differences in surface tension between various frac fluids.

[0023] Fig. 11 is a side elevation view illustrating a fracture pattern within a hydrocarbon reservoir from a horizontal well.

[0024] Fig. 12 is a flow diagram of a method of effective horizontal drilling through a hydrocarbon reservoir within a subterranean formation.

DETAILED DESCRIPTION

[00251 Immaterial modifications may be made to the embodiments described here without departing from what is covered by the claims. Figures are not drawn to scale.
[0026] LPG may include a variety of petroleum and natural gases existing in a liquid state at ambient temperatures and moderate pressures. In some cases, LPG
refers to a mixture of such fluids. These mixes are generally more affordable and easier to obtain than any one individual LPG, since they are hard to separate and purify individually. Unlike conventional hydrocarbon based fracturing fluids, common LPGs are tightly fractionated products resulting in a high degree of purity and very predictable performance. Exemplary LPGs include propane, butane, or various mixtures thereof. As well, exemplary LPGs also include isomers of propane and butane, such as iso-butane. Further LPG
examples include HD-5 propane, commercial butane, and n-butane. The LPG mixture may be controlled to gain the desired hydraulic fracturing and clean-up performance. LPG fluids used may also include minor amounts of pentane (such as i-pentane or n-pentane), higher weight hydrocarbons, and lower weight hydrocarbons such as ethane.
[0027] LPGs tend to produce excellent fracturing fluids. LPG is readily available, cost effective and is easily and safely handled on surface as a liquid under moderate pressure.
LPG is completely compatible with formations, such as oil or gas reservoirs, and formation fluids, and is highly soluble in formation hydrocarbons and eliminates phase trapping -resulting in increased well production. LPG may be readily viscosified to generate a fluid capable of efficient fracture creation and excellent proppant transport. After fracturing, LPG
may be recovered very rapidly, allowing savings on clean up costs. In some embodiments, LPG may be predominantly propane, butane, or a mixture of propane and butane.
In some embodiments, LPG may comprise more than 80%, 90%, or 95% propane, butane, or a mixture of propane and butane.
[0028] Referring to Fig. 12, a method is illustrated of effective horizontal drilling through a hydrocarbon reservoir 10 (shown in Fig. 2A) within a subterranean formation 16 (shown in Fig. 2A). Referring to Figs. 2A-B, in stage 100 (shown in Fig. 12), LPG fracturing fluid is introduced through well 18 into the hydrocarbon reservoir 10. In stage 102 (shown in Fig. 12), the liquefied petroleum gas fracturing fluid in the hydrocarbon reservoir 10 is subjected to fracturing pressures to fracture the subterranean formation 16 and form fractures 20 extending through the hydrocarbon reservoir 10 with an effective frac length 12 greater than 200 meters, for example greater than 300 meters, 500 meters, 1000 meters or more, measured from an injection point 22 of the well 18.
[0029] The methods disclosed herein provide an economical alternative to horizontal drilling and are capable of producing wells that are more productive than conventional vertical or non-horizontal wells. The method is referred to as effective horizontal drilling because it may be used as an economical alternative to horizontal drilling, for example in a situation where horizontal drilling would be more economical than conventional vertical drilling. For example, the hydrocarbon reservoir 10 that the method is carried out within may be formed within a geologic formation, and the geologic formation has been previously subject to horizontal drilling. Moreover, the hydrocarbon reservoir 10 may have an average thickness 24 of less than 100 meters measured parallel to vertical, where the average thickness 24 is computed over a region defined by the actual extent of the fractures 20. The hydrocarbon reservoir 10 may be a reservoir suitable for horizontal drilling, for example more suitable for horizontal drilling than conventional vertical drilling. The reservoir 10 may be formed as a vertically thin but laterally wide bed, such as a blanket or oil-rim reservoir that extends laterally a relatively long distance. In one embodiment, the reservoir 10 may extend a lateral distance longer than can be drawn from by a vertical well drilled and fractured in a conventional fashion with conventional fluids such as frac oils, water, or methanol. For example, the reservoir 10 may extend laterally longer than 200 meters, such as longer than 300 meters, from the well 18 drilled.
[0030] Referring to Figs. 4A-B, unlike other fluids, LPG frac fluids can be used to form fractures 20 (shown in Fig. 2B) with effective frac lengths 12 of 200 meters and greater. As discussed herein, the effective fracture length 12 refers to the length of the created fracture through which well fluids may be produced into the well 11.
The created fracture may be propped along its length 14. Figs. 3A-B and 4A-B contrast fractures formed during fracturing with conventional and LPG fluids, respectively. Conventional stimulation techniques incorporate the use of fluids such as oil, water, methanol, CO2, and N2 for example. Referring to Figs. 3A-B, with conventional fluids the effective fracture length 12 is much shorter than the created fracture length 14. Referring to Figs. 4A-B, on the other hand, the effective fracture length 12 is the same as the created fracture length 14. Referring to Fig.
10, the much shorter effective frac length 12 formed in Figs. 3A-B occurs at least partially as a result of the high surface tension of conventional fluids, such as water as shown, which creates liquid blocks in the pores of a formation. Because the conventional fluids are not easily removed from the formation, the liquid blocks effectively eliminate a large portion of fracture through which fluids may otherwise be produced. These liquid blocks also represent damage done to the formation, such as water damage.
[0031] Referring to Fig. 10, by contrast the extremely low surface tension of the LPG
eliminates or at least significantly reduces the formation of liquid blocks created by fluid trapping in the pores of the formation. This is contrasted with the high surface tension of water, which makes water less desirable as a conventional fluid. LPG is nearly half the density of water, and generates gas at approximately 272 m3 gas/m3 of liquid.
LPG
comprising butane and propane has a hydrostatic gradient at 5.1 kPa/m, which assists any post-treatment clean-up required. This hydrostatic head is approximately half the hydrostatic head of water, indicating that LPG is a naturally under balanced fluid. Thus, the low surface tension of LPG fluid allows LPG frac fluid to be cleaned up quickly and completely, and reduces the pressure needed to mobilize fracturing fluid for clean up. The LPG
may also clean up by vaporization with natural gas in the formation, or by dissolving into solution with formation oil, thus eliminating the relative permeability flow reduction seen with conventional fluids. The vaporization of LPG with natural gas and the extremely low viscosity of LPG permits rapid clean-up to be accomplished with minimal drawdown.
[0032] Referring to Figs. 8 and 9, the effective frac length extension achievable with LPG is also a result of the viscosity of LPG, which is significantly lower than the viscosity of water, frac oil, or methanol water, in ungelled states, further aiding in the removal of LPG
from a well and prevention of formation damage. Significantly, the viscosity of formation fluid such as the fluid from the Doe creek reservoir mixed with an equal amount of LPG is much closer to the viscosity of LPG than the viscosity of unmixed formation fluids, as shown. Thus as injected LPG mixes with formation fluids, the viscosity of the mixed fluid is likely to be closer to the lower viscosity of LPG than the formation fluid.
This thinning of the reservoir fluids also makes LPG excellent for use in tight oil reservoirs.
As well, the viscosity of a mixture of LPG and formation fluids is much lower than the viscosity of frac oil, even frac oil mixed with formation fluids. This reduction of viscosity is significant for cleanup, as reduced viscosity means less pressure is required to move fluid through the formation. Specifically, an order of magnitude reduction in viscosity results in an order of magnitude reduction in the pressure required to move the same volume of fluid through a porous media.
[0033] Referring to Fig. 7, the effective frac length extension is also aided by the reduced boiling point of LPG and the resulting mixture of LPG and formation fluids. Again, mixing of formation fluids such as the Doe creek oil with an equal amount of propane reduces the boiling point of the mixture to much closer to that of propane than of formation fluid. This reduction in boiling temperature and pressure means that the mixture will have reduced viscosity at lower temperatures and pressures, aiding in cleanup and removal. The indicates the critical point of propane, and hence the critical temperature as well. The critical temperature is understood as the temperature beyond which the fluid exists as a gas, regardless of pressure.
[0034] Referring to Fig. 5, a plot of the beneficial increase in production possible with a longer effective frac length is shown. Plots 26 and 27 illustrate theoretical post-stimulation production from the same well after a fracture job in which effective frac lengths of 25% (conventional frac fluids) and 100% (LPG frac fluids), respectively, are formed. The difference in the area under plots 26 and 27, illustrates that a larger proportional effective frac length results in a larger amount of subsequent hydrocarbon production.
For discussion, areas 28, 30, and 32 are understood to illustrate the difference in revenue-producing fluid production achieved with the two fracture treatments, the areas 28, 30, and 32 being defined by the dotted boundary lines 34 and 36. The calculations from the graph assume $4.00/mcf (mcf = 1000 cubic feet of gas). Area 28 shows an incremental revenue of $57k (calculated as 12 days x 34 e3m3/day = 408e3m3 or $57k) from zero flaring and rapid clean-up of LPG frac to a sales line. Area 28 is drawn from the X-axis of the graph because the initial production of fluids after the conventional treatment up to boundary line 34 are flared, resulting in a revenue loss of $72k (12 days x $6k = $72k). Thus, area 28 illustrates the ability to capture initial flush production of LPG due to less flaring with fast frac fluid recovery.

[0035] Area 30 shows an incremental revenue increase of $400k over 3 years (incremental rate/production from 100% effective fracture length accelerated recovery 20%
increase rate over 3 years resulting in a NPV10 of $ 400k, NPV= net present value), corresponding to the time it takes production in plot 26 to decrease to zero at line 36. Finally, area 32 shows incremental reserves from the plot 27, corresponding to the time it takes from line 36 until production in plot 27 decreases to zero. Of note, the downward spikes 38 in plot 26 refer to expected costs of $25k each for two coil tubing well interventions required as a result of well loading. Taken together, these revenue differences result in increased production profits at almost every stage of post-stimulation.
[0036] Referring to Fig. 6, a graph illustrating production from a well (74-13W6 Doe Creek Oil Well) treated with an LPG fracture treatment is provided. Time between initial production and stimulation (line 40), represents 23 years of production, while time between stimulation (line 40) and the time the graph was made (line 42) represents 5 months of production. The stimulation carried out at line 40 was a 16 tonne LPG
stimulation.
Extrapolated plot 44 represents expected production plotted until the time that production is expected to cease (line 46). The incremental reserves expected to be produced between stimulation (line 40) and no further production (line 46) represent a net revenue of $2.3 million (16 % Incremental Reserves : $283k - $243k = $39k BOE, while $39k BOE
x $60 =
$2.3 million, BOE = Barrel Oil Equivalent).
[0037] Referring to Fig. 2B, the composition of the LPG frac fluid may include non-LPG components as desired or needed. A stream of LPG may be sent to well 18 from LPG
supply source 56 through lines 50 and 52. The stream of LPG frac fluid may pass through a frac pressure pump 54 in the process, required to achieve the desired frac pressures. Proppant may be supplied from one or more proppant supply source 48 into the liquefied petroleum gas fracturing fluid prior to introducing the liquefied petroleum gas fracturing fluid into the well 18, for example prior to the frac pressure pump 54. Proppant supply sources 48 may supply proppant through lines 58.

[0038] Because of the massive length of fractures desired, the fracturing technology used may be designed to provide what by conventional standards may be characterized as a massive amount of proppant and pressure. Thus, the proppant supply source 58 may be rated to hold 200, 500, 1000 or more tonnes of proppant. As well, plural proppant supply sources 58 may be connected in parallel, for example as shown with two sources 58.
Proppant supply source 58 may be any suitable supply source, such as an open-topped hopper or pressure vessel. Liquid such as LPG may also be supplied to proppant in the proppant supply source 58, for example through an inlet (not shown) connected to receive LPG from the LPG supply source 56. Liquid such as frac oil may also be used as the liquid added to the proppant, at least in minor amounts relative to the amount of LPG in the LPG frac fluid supplied to the well 18. Supply source 58 may be adapted to transfer proppant into the stream of LPG frac fluid without requiring pressurization of a proppant reservoir (not shown) for receiving proppant. Such a supply source 58 may incorporate a positive displacement pump such as a progressing cavity pump.
[0039] A gelling agent may be supplied, for example from gellant supply source through line 62, into the liquefied petroleum gas fracturing fluid for assisting carriage of proppant into the hydrocarbon reservoir 10. The gelling agent may be any gelling agent suitable for gelling the LPG frac fluid, and may be required to carry a sufficient amount of proppant. Other chemicals such as activators and breakers may be added.
[0040] In addition to the components discussed, other components not shown may be present, like an inert gas supply system for purging components in the system of flammable fluids and pressurizing tanks. Components such as a flare stack, sales line, and LPG
recycling unit may be connected to the system for dealing with recovered fluids.
[0041] Fracturing may further comprises shutting in the liquefied petroleum gas fracturing fluid in the well 18 for an extended period of time, such as 24 hours, 48 hours, or more, sufficient to form the effective frac length 12. In addition the extended period may be longer, such as a week or more. The extended period of time may allow the LPG
to mix with formation fluids, such as oil and natural gas, as the LPG sits in the reservoir and travels along the created fractures. The extended shut-in time may be determined in order to optimize the mixing of the fracturing fluid with the reservoir gas to form the longest effective frac lengths possible.
[0042] The shutting-in period may comprise more than one period combined, for example if the period was broken up into two periods due to the addition of extra fracturing fluid at the halfway point. Under conventional fracturing procedures, the hydrocarbon fracturing fluid may be shut-in, but only for minor periods of time, and usually only until the fracturing itself has been completed. The extending of the shutting-in period disclosed herein following the fracture treatment enhances the subsequent clean-up of the fluid due to the mixing of the fracturing fluid with the reservoir gas, and may extend the effective frac length 12. Mixing of the fracturing fluid with reservoir gas may also result in vaporization of the fracturing fluid, providing improved fluid recovery properties from that of the fracturing fluid alone. Further, allowing this mixing to occur results in improved clean up capabilities as a result of lowered properties of viscosity and density from that of the fracturing fluid alone. The mixing of the fracturing fluid with the reservoir gas also results in the mixture having properties that significantly reduce the capillary pressure of the mixture from that of the fracturing fluid alone. This further prevents the liquid block situation discussed above, and improves the resulting production from the formation into the well.
[0043] The hydrocarbon reservoir 10 may be contained at least in part within one or more of a sandstone formation, a siltstone formation, and a shale formation.
Such formations may be tight reservoirs, and may be formed in thin, laterally extensive beds of porous material that are excellent locations for hydrocarbons to accumulate in beds.
Such reservoir beds may be economically drilled with horizontal wells. However, the methods disclosed herein may be used to exploit the hydrocarbons contained in such reservoirs in a manner that is even more economical than horizontal drilling.
[0044] Referring to Fig. 2B, the well 18 may be a vertical well as shown. A
vertical well is understood as being any well that deviates 20 degrees or less from vertical. From a practical standpoint, all vertically drilled wells will deviate naturally to some extent. The portion of the well 18 that directly penetrates hydrocarbon reservoir 10 may also be a directionally drilled well, such as the horizontal well 18A shown in Fig. 11.
A directionally drilled well is understood to be any well that is actively steered in order to form a deviated well bore, while a horizontal well is understood as being any well that deviates more than 70 degrees from vertical.

[0045] Horizontal well 18A is illustrated as being used to carry out the fracture from injection point 22. Thus, a directionally drilled well may be used to penetrate the hydrocarbon reservoir 10 in order to carry out the fracture techniques disclosed herein.
Directional drilling may be used with the methods disclosed because it may be more economical or even required in some cases to use directional drilling to reach the hydrocarbon reservoir 10. For example, directional drilling may be required if the hydrocarbon reservoir 10 is located under a mountain, or off shore. As well, directional drilling may be economical if multiple wells are drilled from the same surface location and are directed to penetrate a reservoir 10 at different locations. The portion of a directionally drilled well that penetrates the reservoir 10 may do so in a vertical fashion in some cases.
[0046] The methods disclosed herein may be more economical than a conventional horizontal drilling of a reservoir 10 because these methods may obviate the need to drill a directional or horizontal well through the reservoir 10. Thus, under the methods disclosed a reservoir 10 may simply be penetrated a sufficient distance before fracturing, rather than the relatively extensive distance a horizontal well would be expected to penetrate the same reservoir 10. The well 18 drilled may in fact only penetrate a small portion of the reservoir 10, and after performing the methods disclosed herein, may draw formation fluids from a sufficient portion, such as the entirety, of the larger reservoir 10.
[0047] Conventional fracturing technology may form fractures with effective frac lengths of up to 100 in. However, because 100 in is considered to be the inherent limit of effective frac length possible with conventional frac fluids such as frac oils or water, fracturing technology has been practically confined to situations where achievement of a 100m draw from a well is acceptable. For situations where a longer draw was required, conventional knowledge may mandate a horizontal well to be drilled. In this manner, horizontal drilling has arisen as a more economical alternative for certain types of reservoirs, such as blanket reservoirs.
[0048] Thus, the methods disclosed herein represent a paradigm shift in well fracturing. The methods disclosed herein allow wells to be drilled and treated with a massive frac, in order to increase the ability of the well to draw fluids from the largest radial distance possible into the well. Because of the massive size of the fracturing operation, and the use of LPG, fractures 20 are created with a much longer effective frac length 12 than those previously capable of formation. This increases the volume of a hydrocarbon reservoir 10 from which hydrocarbons may be drawn from into a well 18, and thus increases the viability of vertical wells in situations that may otherwise be more economical for horizontal drilling applications. This may be more economical than conventional horizontal drilling, even in long and thin reservoirs.
[0049] The LPG fracturing processes disclosed herein should be implemented with design considerations to mitigate and eliminate the potential risks, such as by compliance with the Enform Document: Pumping of Flammable Fluids Industry Recommended Practice (IRP), Volume 8-2002, and NFPA 58 "Liquefied Petroleum Gas Code".
[0050] These methods may be used on sub-normally saturated and under-pressured reservoirs, including gas, oil and water wells, to eliminate altered saturations and relative permeability effects, accelerate clean-up, realize full frac length, and improve long-term production. Further, these methods may be used on reservoirs that exhibit high capillary pressures with conventional fluids to eliminate phase trapping. These methods may also be used on low permeability reservoirs, which normally require long effective frac lengths to sustain economic production, to accelerate clean-up, realize full frac length quicker, and improve production. These methods may also be used on recompletions with recovery through existing facilities, in order to recover all LPG fluid to sales gas -thus reducing clean-up costs, avoiding conventional fluid recovery and handling costs, and eliminating flaring.
[0051] Multiple frac treatments may be completed without the need for immediate frac clean-up between treatments, as the extended shut-in simplifies and speeds the clean-up without detriment to formation. These methods may also be used in exploration, as the pumping of a completely reservoir compatible fluid provides excellent stimulation plus rapid cleanup and evaluation, which gives a fast turnaround and zero-damage evaluation in potentially unknown reservoir and reservoir fluid characteristics.
[0052] The methods disclosed herein may incorporate the initial stage of drilling the well 18, for example drilling a vertical well. Other steps not mentioned may be included in the method, such as injection of a pad of LPG frac fluid or an acid spearhead as examples.
[0053] In the claims, the word "comprising" is used in its inclusive sense and does not exclude other elements being present. The indefinite article "a" before a claim feature does not exclude more than one of the feature being present. Each one of the individual features described here may be used in one or more embodiments and is not, by virtue only of being described here, to be construed as essential to all embodiments as defined by the claims.

Claims (25)

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

1. A method of effective horizontal drilling through a hydrocarbon reservoir within a subterranean formation, the method comprising:
introducing liquefied petroleum gas fracturing fluid through a well into the hydrocarbon reservoir; and subjecting the liquefied petroleum gas fracturing fluid in the hydrocarbon reservoir to fracturing pressures to fracture the subterranean formation and form fractures extending through the hydrocarbon reservoir with an effective frac length greater than 200 meters measured from an injection point of the well.

2. The method of claim 1 in which the hydrocarbon reservoir is formed within a geologic formation and the geologic formation has been previously subject to horizontal drilling.

3. The method of claim 2 in which the hydrocarbon reservoir has an average thickness of less than 100 meters measured parallel to vertical, where the average thickness is computed over a region defined by the actual extent of the fractures.

4. The method of claim 1, 2, or 3 in which the well is a vertical well.

5. The method of claim 1, 2, or 3 in which the well is a directionally drilled well.

6. The method of claim 5 in which the well is a horizontal well.

7. The method of any one of claim 1-6 in which the fractures have an effective frac length greater than 300 meters.

8. The method of claim 7 in which the fractures have an effective frac length greater than 500 meters.

9. The method of claim 8 in which the fractures have an effective frac length greater than 1000 meters.

10. The method of any one of claim 1- 9 further comprising supplying proppant from a proppant supply source into the liquefied petroleum gas fracturing fluid prior to introducing the liquefied petroleum gas fracturing fluid into the well.

11. The method of claim 10 in which the proppant supply source is rated to hold 200 tonnes or more of proppant.

12. The method of claim 11 in which the proppant supply source is rated to hold 500 tonnes or more of proppant.

13. The method of claim 12 in which the proppant supply source is rated to hold 1000 tonnes or more of proppant.

14. The method of any one of claim 11 - 13 in which the proppant supply source comprises plural proppant supply sources.

15. The method of claim 14 in which the plural proppant supply sources are connected in parallel.

16. The method of any one of claim 11 - 15 further comprising adding liquid to proppant in the proppant supply source.

17. The method of claim 16 in which the liquid comprises liquefied petroleum gas.

18. The method of any one of claim 11-17 further comprising supplying a gelling agent into the liquefied petroleum gas fracturing fluid for assisting carriage of proppant into the hydrocarbon reservoir.

19. The method of any one of claim 1-18 in which fracturing further comprises shutting in the liquefied petroleum gas fracturing fluid in the well for an extended period of time sufficient to form the effective frac length.

20. The method of claim 19 in which shutting in comprises shutting in for 24 hours or more.

21. The method of claim 20 in which shutting in comprises shutting in for 48 hours or more.

22. The method of claim 21 in which shutting in comprises shutting in for a week or more.

23. The method of any one of claim 1-22 in which the hydrocarbon reservoir is contained at least in part within a sandstone formation.

24. The method of any one of claim 1-23 in which the hydrocarbon reservoir is contained at least in part within a siltstone formation.

25. The method of any one of claim 1-24 in which the hydrocarbon reservoir is contained at least in part within a shale formation.