METHOD FOR HYDRAULICALLY FRACTURING A SUBTERRANEAN RESERVOIR

Abstract

A method for hydraulically fracturing a subterranean reservoir. A fracturing fluid comprising a clay stabilizer is provided at an uphole temperature. The uphole temperature allows the fracturing fluid to be for provided at a downhole temperature in the reservoir greater than a cloud point of hydrocarbons in the reservoir. The fracturing fluid is injected into the reservoir at a controlled injection rate to propagate a fracture in the reservoir and mitigate vertical height growth of the fracture. Proppant is introduced into the fracturing fluid to provide a fracturing slurry. The fracturing slurry is injected into the reservoir at the controlled injection rate to prop the fracture.

Description

FIELD

The present disclosure relates to hydraulically fracturing a subterranean reservoir. More particularly, the present disclosure relates to a method for hydraulically fracturing a subterranean reservoir.

BACKGROUND

It is challenging to produce hydrocarbons from some reservoirs at economic rates. For example, poorly indurated clastic reservoirs with paraffinic crude oil having a low cloud point may be particularly challenging. Such a reservoir may include shale in thinly-laminated layers of varying thickness. The reservoir may include argillaceous swelling clays (e.g. kaolinite, montmorillonite, smectite, and illite) and silt, which may introduce fines into fluid flow within the reservoir.

The above reservoir features may for example be present in clastic reservoirs created in shallow offshore marine environments and may include thin laminae of sandstone and shale of varying thicknesses. Such reservoirs may have a variety of fine grained silty clay minerals interspersed between the sandstone grains.

These reservoirs can be found at shallow depths of burial of less than a thousand metres, which imparts only a limited overburden stress. The limited overburden stress may result in low pore pressure and low confining pressure within the reservoir rock matrix. The low pressure leads to poor induration of the reservoir and low confining stress.

The reservoir may contain mobilizable fines. Any agitation (e.g. drilling, completion, production) may cause the fines to mobilize. Mobilized fines may agglomerate and become lodged in pore throats of the reservoir, reducing permeability.

Hydrocarbons have variable chemical compositions. Crude oil may be paraffinic with a low wax crystallization temperatures (or “cloud point”), which increases the difficulty of producing the crude oil when the uphole temperature is close to or below the cloud point. In reservoirs at shallow depths of burial, the geothermal gradient is such that the reservoir temperature is low. When the temperature of the paraffinic crude oil is reduced to a point below the cloud point temperature, heavier molecular weight hydrocarbon components in the crude oil will crystallize to form solids which will reduce permeability within the reservoir rock matrix.

Current fracturing and production techniques sometimes provide sub-economic production rates, and low percentage reservoir recovery factors, when applied to some reservoirs. It is, therefore, desirable to provide an improved method for hydraulically fracturing a reservoir to produce hydrocarbons including crude oil.

SUMMARY

The geological characteristics of a reservoir such as exist in a poorly-indurated clastic reservoir may complicate production and recovery of hydrocarbons including crude oil from the reservoir. Similarly, the properties of recoverable crude oil in the reservoir may complicate recovery of hydrocarbons from the reservoir, for example oil with dissolved waxes and a cloud point near the reservoir temperature.

In a first aspect, the present disclosure provides a method of hydraulically fracturing a reservoir by injecting a fluid into the reservoir. Prior to injection, the fluid is heated to a selected temperature to mitigate wax deposition when the fluid is injected into the reservoir. The fluid is injected at a controlled rate to mitigate against excessive fracture growth in the vertical plane and promote fracture growth along the longitudinal plane. Without being bound by theory, the method may facilitate increasing fracture conductivity near a wellbore in a reservoir, increasing effective fracture length, and containing the fracture height. Production data shows improved hydrocarbon recovery when applying the method. During hydraulic fracturing, the fluid is injected into the reservoir at a sufficient pressure to propagate a fracture in the reservoir. The fracture may be a newly initiated fracture or a previously existing one and “propagating” includes both creating an artificially-induced hydraulic fracture and extending a previously-existing fracture.

In a further aspect, the method includes providing a fracturing fluid having a clay stabilizer at a selected uphole temperature. The uphole temperature is selected to provide a downhole temperature above the cloud point of crude oil in the reservoir. For example, where the cloud point is about 25° C., the downhole temperature may be selected to be about 50° C. However, because of heat loss during injection of fracturing fluid, the uphole temperature must be greater than the downhole temperature. For example, depending on depth, surface temperature, and reservoir temperature, the fracturing fluid may to be heated to an uphole temperature in excess of to 60° C. to result in a downhole frac-face temperature of 30 to 50° C.

The fracturing fluid is injected into a wellbore within the reservoir at a pressure sufficient to propagate a fracture in the reservoir. Proppant is combined with the fracturing fluid to provide a fracturing slurry for propping the fracture. The base fluid and fracturing slurry are injected at a selected rate, such as between 0.5 and 2.5 m³/min (for example about 1.5 m³/min), to mitigate vertical fracture height growth. After fracturing, the wellbore may be shut in for a selected period, such as between 8 and 30 hours (for example about 20 hours), to allow the fractures to heal. After the shut-in, hydrocarbons may be produced at a controlled flow-back rate to mitigate fines migration.

The fracturing fluid includes a base fluid and a clay stabilizing product, such as KCl, for example about 7% KCl. The base fluid may be aqueous and the fracturing fluid may include a gellant chemical additive to increase the viscosity of the fluid used for fracture stimulation to promote the suspension of the proppant. The proppant may have a mesh size of between 30/50 and 8/12, for example of about 16/30. The downhole concentration of proppant in the fracturing slurry may be between 600 and 1600 kg/m³, for example about 1,000 kg/m³, and may be ramped to its downhole concentration during propping. The fracturing fluid may include a wax crystal modifier such as Parachek 160™ Paraffin Inhibitor. The fracturing slurry may include a fines migration inhibitor, such as a chemical additive to the fracturing such as Sandwedge™ enhancer, which promotes the binding of fine grained solid materials, such as mobilized clay materials, to the rock matrix to restrict its movement.

In a further aspect, the present disclosure provides a method for hydraulically fracturing a subterranean reservoir. A fracturing fluid comprising a clay stabilizer is provided at an uphole temperature. The uphole temperature allows the fracturing fluid to be provided at a downhole temperature in the reservoir greater than a cloud point of hydrocarbons in the reservoir. The fracturing fluid is injected into the reservoir at a controlled injection rate to propagate a fracture in the reservoir and mitigate vertical height growth of the fracture. Proppant is introduced into the fracturing fluid to provide a fracturing slurry. The fracturing slurry is injected into the reservoir at the controlled injection rate to prop the fracture.

In a further aspect, the present disclosure provides method for hydraulically fracturing a subterranean reservoir. The method includes providing a fracturing fluid comprising a clay stabilizer, the fracturing fluid at an uphole temperature for providing a downhole temperature in the reservoir greater than a cloud point of hydrocarbons in the reservoir; injecting the fracturing fluid into the reservoir at a controlled injection rate to propagate a fracture in the reservoir and mitigate vertical height growth of the fracture; introducing a proppant into the fracturing fluid to provide a fracturing slurry; and injecting the fracturing slurry into the reservoir at the controlled injection rate to prop the fracture.

In an embodiment, the method includes selecting a reservoir with a pressure of between about 2 MPa and about 10 MPa. In an embodiment, the method includes selecting a reservoir has a pressure of about 7 MPa.

In an embodiment, the method includes selecting a reservoir with a true vertical depth of between about 500 m and about 1,200 m. In an embodiment, the method includes selecting a reservoir with a true vertical depth of about 800 m.

In an embodiment, the uphole temperature is about double the cloud point (in ° C.).

In an embodiment, the uphole temperature is between about 50° C. and about 70° C. In an embodiment, the uphole temperature is about 60° C.

In an embodiment, the controlled injection rate is selected with reference to a previous injection rate which resulted in a bottomhole net pressure drop attributable to vertical height growth. In an embodiment, the controlled injection rate is decreased relative to the previous injection rate. In an embodiment, the controlled injection rate is decreased iteratively to a value where no bottomhole net pressure drop attributable to vertical height growth is observed. In an embodiment, the controlled injection rate is decreased iteratively by steps of about 0.2 m³/min.

In an embodiment, the controlled injection rate is selected with reference to a previous injection rate which resulted in no bottomhole net pressure drop attributable to vertical height growth.

In an embodiment, the controlled injection rate is between about 0.5 m³/min and about 2.5 m³/min. In an embodiment, the controlled injection rate is about 1.5 m³/min.

In an embodiment, the method further includes, following injecting the fracturing slurry, shutting in the reservoir for a period of time to allow the fracture to heal. In an embodiment, the period of time is between about 8 and about 30 hours. In an embodiment, the period of time is about 20 hours.

In an embodiment, the method further includes, following injecting the fracturing slurry, shutting in the reservoir for a period of time to allow the fracture to heal, and further includes, following the period of time, producing the fracturing fluid, hydrocarbons, or both, at a reduced production rate to mitigate fines migration. In an embodiment, the reduced production rate is at a pressure draw down to between about 70% and about 80% of a reservoir pressure following the period of time.

In an embodiment, the method further includes, following injecting the fracturing slurry, shutting in the reservoir for a period of time to allow the fracture to heal, and further includes, following the period of time, producing the fracturing fluid, hydrocarbons, or both, at a reduced production rate to mitigate fines migration, and the reduced production rate is between about 1.0 and about 2.0 m³/h.

In an embodiment, the proppant has a grain size of between about 8/12 mesh and about 30/50 mesh. In an embodiment, the proppant has a grain size equal to about 16/30 mesh.

In an embodiment, the clay stabilizer is KCl. In an embodiment, the KCl is at a concentration of between about 3% and about 9% in the fracturing fluid. In an embodiment, the KCl is at a concentration of about 7% in the fracturing fluid.

In an embodiment, the method further includes combining a wax crystal modifier with the fracturing fluid.

In an embodiment, the method further includes combining a fines migration inhibitor with the fracturing slurry.

In a further aspect, the present disclosure provides a method for hydraulically fracturing a subterranean reservoir having a true vertical depth of between about 500 m and about 1,200 m, and a pressure of between about 2 MPa and about 10 MPa. The method includes providing a fracturing fluid comprising a clay stabilizer, the fracturing fluid being at an uphole temperature for providing a downhole temperature greater than a cloud point of hydrocarbons in the reservoir; injecting the fracturing fluid into the reservoir at a controlled injection rate of between about 0.5 m³/min and about 2.5 m³/min to propagate a fracture in the reservoir while mitigating vertical height growth of the fracture; introducing a proppant with a grain size of between about 8/12 mesh and about 30/50 mesh into the fracturing fluid to provide a fracturing slurry; injecting the fracturing slurry into the reservoir at the controlled injection rate to prop the fracture; and shutting in the reservoir for between about 8 and about 30 hours to allow the fracture to heal.

In an embodiment, the method further includes producing the fracturing fluid, the hydrocarbons, or both, at a reduced drawdown rate of about between about 70% and about 80% of a reservoir pressure following the period of time to mitigate fines migration.

In an embodiment, the method further includes producing the fracturing fluid, the hydrocarbons, or both, at a reduced drawdown rate of between about 1.0 and about 2.0 m³/h.

BRIEF DESCRIPTION OF THE DRAWINGS

Embodiments of the present disclosure will now be described, by way of example only, with reference to the attached Figures.

FIG. 1 is a schematic of a reservoir being fractured;

FIG. 2 is a flow chart of an embodiment of the method;

FIG. 3 is a flow chart of an embodiment of the method; and

FIG. 4 is a simplified material balance plot of the oil rate (m³/day) against equivalent time for several wells.

DETAILED DESCRIPTION

Generally, the present disclosure provides a method of fracturing a reservoir to facilitate recovery of hydrocarbons including crude oil from the reservoir.

FIG. 1 is a schematic of a reservoir 10. The method includes providing a fluid in a wellbore 14 of the reservoir 10 at a sufficient pressure to propagate a fracture 16 in the reservoir 10. The fracture 16 may be a newly initiated fracture or a previously existing one and “propagating” includes both creating an artificially-induced fracture and extending a previously-existing fracture. The fluid may be a fracturing fluid to propagate the fracture 16 or a fracturing slurry to prop the fracture 16. The fluid is provided into the wellbore 14 through a tubing 18 at a selected temperature, which is above the cloud point of crude oil in the reservoir 10. The fluid is provided to the wellbore 14 at a controlled injection rate during propagation of the fracture 16, for example to about 1.5 m³/min. Without being bound by theory, the controlled injection rate may mitigate vertical growth of the fracture 16 and migration of fines into the wellbore 14.

The method has particular application where the reservoir 10 includes soft formation rock, swelling clays, fines, or a combination thereof. The reservoir 10 may be a shallow reservoir, for example have a depth of between about 500 m and about 1,200 m, for example about 800 m. The reservoir may be a low-pressure reservoir, for example have a pressure of between about 2 MPa and about 10 MPa, for example about 7 MPa, and may have depleted zones as low as about 2 MPa. For example, the reservoir may be a clastic reservoir created in a shallow offshore marine environment.

Crude oil in the reservoir 10 may have a low cloud point, and wax precipitation may result if the fluid is at a low temperature. Precipitation of wax within the reservoir 10 or the wellbore 14 may adversely impact crude oil inflow, well productivity, and hydrocarbon recovery. Without being bound by theory, the selected temperature of the fluid may mitigate precipitation of wax from the crude oil.

Fracturing Fluid Temperature

FIG. 2 is a flow chart of an embodiment of the method. A fracturing fluid at an uphole temperature is provided. The fracturing fluid at the uphole temperature may be provided for example by heating an aqueous base fluid then adding chemical additives, by adding chemicals to the base fluid to provide fracturing fluid and then heating, or by a combination thereof.

A pad of the fracturing fluid at the uphole temperature is injected into the reservoir 10 through the tubing 18 at a pressure exceeding the confining stress of the reservoir rock matrix, propagating the fracture 16. The fracturing fluid extends the depth of penetration of the fracture 16 into the reservoir 10 and increases an aperture of the fracture 16 to accommodate proppant. The proppant is then blended with the fracturing fluid, providing a fracturing slurry. The fracturing slurry is then injected into the reservoir 10 to prop the fracture 16.

The uphole temperature is selected to provide the fracturing fluid and the fracturing slurry into the fracture 16 at or above a selected downhole temperature. The downhole temperature is greater than the cloud point of hydrocarbons in the reservoir 10 to mitigate precipitation of wax from oil in the reservoir 10. Where the uphole temperature is below the reservoir temperature or below the surface temperature, or both, some heat will be lost during injection, and the uphole temperature must be greater than the downhole temperature. For example, in Western Canada, the geothermal gradient is typically estimated at about 3.25° C. per 100 m of true vertical depth, providing a reservoir temperature of about 26° C. at a true vertical depth of about 800 meters. Where the surface temperature is about 20° C., an uphole temperature of about 60° C. may provide a downhole temperature of between about 45° C. and about 50° C. at this depth. In an embodiment, the uphole temperature may be selected to be about double the cloud point of the hydrocarbons (in ° C.). For example, where the cloud point is 25° C., the uphole temperature may be selected to be about 50° C.

The uphole temperature may have a maximum value defined by any viscosity enhancing gels and enzymatic breakers in the fracturing fluid. For example, with some cross-linked borate gels and enzymatic breakers, the uphole temperature cannot exceed about 80° C., which may result in a downhole temperature of about 35° C. if the surface temperature is low (e.g. about −20° C.). In reservoirs with a true vertical depth of between about 500 m and about 1,200 m, an uphole temperature of about 60° C. will in most cases result in a downhole temperature sufficient to mitigate wax precipitation.

Heat loss during injection may be mitigated where injection is through the tubing 18 (as shown in FIG. 1) and not through an empty wellbore 14. The tubing 18 has a smaller circumferential area than the wellbore 14, mitigating heat loss, and the annulus around the tubing 18 may act as an insulator between the fluid and the reservoir 10.

In an embodiment, the fracturing fluid may be heated to the uphole temperature in a surface tank prior to introducing the proppant into the fracturing fluid in a blender to prepare the fracturing slurry. The proppant may be stored, and the blender may operate, at ambient temperatures, in which case the uphole temperature may be lowered during blending if the ambient temperature is low (e.g. during winter in Western Canada). This effect is particularly pronounced where greater downhole concentrations of proppant are added to the fracturing fluid.

Controlled Injection Rate

The fracturing fluid and the fracturing slurry are each injected into the reservoir 10 at a controlled injection rate. In previous methods of hydraulically fracturing reservoirs, the injection rate of fluids is sometimes selected to be as high as possible for the cross-sectional area of tubulars through which the fluids are injected. Selecting the maximum injection rate for the tubulars maximizes the amount of fluid that may be injected within a given time frame, or minimizes the time required to inject a given amount of fluid.

Vertical height growth of the fracture 16 into an overlying formation 20, an underlying formation 22, or both, may result in poor fracture conductivity within the reservoir 10, and may result in an increase in the tonnage required to propagate and prop the fracture 16. Vertical height growth into the formations 20, 22, or both, is more likely with a greater injection rate. Vertical height growth into the formations 20, 22, or both, may be detectable on a plot of observed bottomhole net pressure in the formation 10 against time as a sudden drop in net pressure, for example with a slope of −1 or less on a logarithmic plot. In addition, injection of fracturing fluid and fracturing slurry may cause increased mobilization of fines from the reservoir 10, with greater injection rates causing an increased degree of mobilization of fines.

The controlled injection rate is typically lower than the maximum injection rate that the cross-sectional area of the tubular 18 can accommodate. The controlled injection rate facilitates containment of the fracture height to within the reservoir 10 by mitigating vertical height growth of the fracture 16 into the formations 20, 22, or both. The controlled injection rate may also mitigate migration of fines into the fracture 16 during injection and from the reservoir 10 into the wellbore 14 during production.

The controlled injection rate is selected based on, for example, rock mechanics, net pay, overburden stress, pressure, depth, or a combination thereof, of the reservoir 10. The controlled injection rate for a given reservoir is initially selected with reference to a previous injection rate. The previous injection rate may for example be from a previous reservoir with similar rock mechanics, overburden stress, pressure, depth, or a combination thereof. The previous injection rate may for example be from a previous stage in a multi-stage fracturing job on a horizontal well (as shown in FIG. 1). The previous injection rate may for example be from another vertical well in the same or a similar reservoir in the case of application of the method to a vertical well.

Where the previous injection rate resulted in a drop in bottomhole net pressure attributed to vertical height growth, the controlled injection rate will be decreased relative to the previous injection rate, for example by about 0.2 m³/min. If drops in net pressure attributed to vertical height growth persist in the first or subsequent stages of a multi-stage fracturing job, the controlled injection rate is further iteratively lowered during further subsequent stages until no drop in net pressure attributed to vertical height growth is observed.

Methods for determining that vertical height growth has occurred other than observing pressure drops may also be applicable to the method.

General ranges for the controlled injection rate have become apparent from application of the method. In an embodiment, where the true vertical depth of the reservoir is about 800 m and the reservoir pressure is about 7 MPa, the controlled injection rate may be between about 0.5 and about 2.5 m³/min. In an embodiment, the controlled injection rate may be about 1.5 m³/min.

Shut-In

FIG. 3 is a flow chart of an embodiment of the method. After propagating the fracture 16, the wellbore 14 is shut-in for a period of time (the “shut-in period”). The shut-in period may provide time for the fracturing fluid to break and leak out of the fracture 16, allowing the fracture 16 to close on the proppant, healing the fracture 16 and leaving the proppant behind in the fracture 16 as a proppant pack. The shut-in period may also facilitate chemical reactions or other interactions between the fracturing fluid and the reservoir 10, or between the fracturing slurry and the reservoir 10, depending on the other additives of the fracturing fluid or fracturing slurry. The shut-in period may also facilitate dissipation of pressure, mitigating undesirably large flow during production following shut-in, which may cause increased migration of fines.

The shut-in period is selected based in part on the pressure and temperature of the reservoir 10. The greater the pressure, or temperature, or both, of the reservoir 10, the shorter the required shut-in time to allow chemical reactions or other interactions. In an embodiment, the shut-in period may be between about 8 and about 30 hours. In an embodiment, the shut-in period may be about 20 hours.

Reduced Production Rate

Following the shut-in period, fracturing fluid and hydrocarbons may be produced at a reduced production rate. For example, the flow back may be choked-off. Without being bound by theory, the reduced production rate may reduce fluid drag within the fracture 16, providing benefits such as mitigating fines migration and maintaining conductivity within the fracture 16. Maintaining conductivity within the fracture 16 may be a result of mitigated displacement of proppant from proppant packs within the fracture 16 during flow back of fracturing fluid. In addition, and also without being bound by theory, the reduced production rate may mitigate the effects of an initial flow shock during post-fracturing recovery of the fracturing fluid. In addition, and also without being bound by theory, the reduced production rate may also mitigate wax precipitation by mitigating a Joule-Thompson cooling effect at perforations in casing in the wellbore 14 during production of the hydrocarbons. In addition, and also without being bound by theory, the reduced production rate may also mitigate premature gas break-out.

The reduced production rate is selected based in part on static downhole pressure of the reservoir. In an embodiment, the reduced production rate is drawn down by between about 20% and about 30% from reservoir pressure, to between about 70% and about 80% of the reservoir pressure. In an embodiment, the degree of drawdown may be selected to result in a production rate of 1.0 to 2.0 m³/hour.

Fracturing Fluid and Fracturing Slurry

The fracturing slurry includes the fracturing fluid and the proppant. The fracturing fluid includes a clay stabilizer chemical additive in an aqueous base fluid as further described below. The fracturing fluid may also include a viscosity enhancer to suspend the proppant, with reagents to increase viscosity, and to break the viscosity, included as appropriate. For example, the fracturing fluid may include a buffer, a surfactant, and a linear polymer gel, which are added to the fracturing fluid after heating to the uphole temperature. Cross-linking agents and breaker may be added to the fracturing fluid prior to introduction of the proppant into the fracturing fluid. Alternatively, the cross-linking agents and a breaker may be added to the fracturing fluid when the proppant is introduced into the fracturing fluid to provide the fracturing slurry. The viscosity of the fracturing fluid will be selected to carry the proppant being used. The controlled injection rate may be selected based on the viscosity as indicated in the following table:

Controlled injection rate
(m3/min) Viscosity (cP)
0.5      400
1.0      350
1.5      300
2.0      250
2.5      200

A sieve size of the proppant may be selected to provide the coarsest size that the fracture 16 will accommodate. For example, a 16/30 mesh proppant may be the coarsest size that can be used, but in some embodiments, proppant with a coarser sieve size may be used, for example about 8/12 mesh. Alternatively, a proppant with a finer sieve size may be used, for example about 30/50 mesh. The sieve size for a given reservoir may be determined by field testing prior to application of the method. The sieve size will be selected based on the permeability of the reservoir, a selected target fracture conductivity, and the estimated fracture width. For example, if the permeability of the reservoir is about 0.001 mD, then a finer sieve size, for example about 20/40 mesh or 30/50 mesh, may be appropriate. Similarly, if the permeability is 50+mD, a greater sieve size, such as 12/20 mesh or 8/12 mesh, may be appropriate. Without being bound by theory, the coarser proppant or greater downhole concentration may provide larger fracture conductivity, improve the near wellbore conductivity, and mitigate proppant embedment.

The proppant downhole concentration in the fracturing slurry may be between about 600 and about 1600 kg/m³, for example about 1,000 kg/m³. The appropriate proppant downhole concentration for a given reservoir may be determined by field testing prior to application of the method. The proppant may be added to the fracturing fluid in stages with progressively increasing downhole concentrations (a “sand ramp”), for example ramping up to a proppant downhole concentration of about 1,000 kg/m³. The proppant downhole concentration may be selected based on the permeability of the reservoir and a target fracture conductivity. If increased fracture conductivity is desired where a coarser proppant sieve size would have been more appropriate, the proppant downhole concentration may be increased to compensate.

Clay Stabilizer

The fracturing fluid includes a clay stabilizer. The clay stabilizer mitigates ionic shock between swelling clays in the reservoir and fracturing fluid or fracturing slurry. A greater downhole temperature increases the rate of ionic exchange between the swelling clays and the fracturing fluid or fracturing slurry. Similarly, the shut-in period provides a longer period of time for ionic exchange to occur.

In an embodiment, the clay stabilizer is KCl. In an embodiment, the KCl is present in the fracturing fluid at between about 3% and about 9% (v). In an embodiment, the KCl is present in the fracturing fluid at about 7% (v).

In an embodiment, the clay stabilizer is added to the base fluid prior to addition of other additives to prepare the fracturing fluid, and prior to heating of the base fluid or fracturing fluid to the uphole temperature. The type and concentration of clay stabilizer is selected based on the percentage of swelling clays present in the reservoir. This embodiment may be applied where, for example, the clay stabilizer is KCl.

In an embodiment, the clay stabilizer is a quaternary ammonium salt, for example Clayfix™ clay-treating chemical, Halliburton ClayStay, Trican CC-3, Ironhorse IHCS-1B, or Calfrac DWP-913.

In an embodiment, the clay stabilizer is added to the base fluid after heating of the base fluid and at the same time as other chemical additives, for example within a blender. This embodiment may be applied where, for example, the clay stabilizer is a quaternary ammonium salt.

Other Additives

In an embodiment, the fracturing fluid and fracturing slurry include a wax crystal modifier. Where the hydrocarbons include dissolved waxes, wax precipitation may occur when the temperature of the hydrocarbons drops below their cloud point. This may occur during early flowback following shut-in where there is cooling near the wellbore 14 due to pressure reduction during production. The wax crystal modifier inhibits agglomeration and precipitation of waxes, mitigating plugging of the reservoir 10, the wellbore 14, and the tubular 18. In an embodiment, the wax crystal modifier is added to the fracturing fluid prior to injection of the pad. In an embodiment, the wax crystal modifier may be Parachek 160™ paraffin inhibitor. Other examples of wax crystal modifiers include Chemsery PX500, Chemsery AX255, and Baker Hughes Parasorb.

The wax crystal modifier may be particularly useful where the surface temperature, the reservoir temperature, or both, are low. In addition, providing the fracturing fluid at the downhole temperature provides a temporary increase in temperature, and inhibition of wax precipitation is correspondingly temporary. Addition of the wax crystal modifier to the fracturing fluid may provide inhibition of wax precipitation for a greater period of time than providing the fracturing fluid at the downhole temperature but without wax crystal modifier.

In an embodiment, the fracturing slurry includes a fines migration inhibitor. The fines migration inhibitor may mitigate flow of fines from the reservoir 10 into the wellbore 14 and the tubular 18. In an embodiment, the fines migration inhibitor may be added to the fracturing slurry after the proppant is blended with the fracturing fluid. In an embodiment, the fines migration inhibitor is Sandwedge™ enhancer. Sandwedge™ enhancer forms chemical bonds with grains of proppant, providing a coating that increases attractive forces between the grains and repels reservoir fines from the grains. Formation of bonds between the fines migration inhibitor and the proppant may be facilitated by the shut-in period. Other examples of fines migration inhibitors include Coal-Stay additive, ST115 Sand Stimulation Additive, and SiberProp™ partially cured sand (which would replace the proppant). The fines migration inhibitor may be particularly useful where the controlled injection rate, the flowback rate, or both, are high.

Representative Applications

FIG. 4 is a simplified material balance plot of the oil rate (m³/day) against equivalent time (days; calculated by dividing the cumulative oil production at a point in time by the oil rate at the point in time). Three trend lines are present on the plot, each illustrating a “transient flow period” with a ½ slope. The linear ½-slope trend line during the transient flow period allows ranking of wells based on flow rate, permitting quantitative comparison of oil rates achieved following stimulation of different wells; higher oil flow rate values along the linear ½-slope trend line indicate greater well performance. The transient flow period typically begins from two to four months after the onset of production. A “bounded flow period” beginning after the transient flow period with a unit-slope, and continuing until the economic limit of production, occurs at a later point in time. The bounded flow period typically occurs after the financial success or failure of the fracturing stimulation treatment has been determined.

FIG. 4 includes three representative data sets (circles, triangles, and squares). The well in the first data set (circles) was fractured with ambient temperature fracturing fluid and without a controlled injection rate. The well in the second data set (triangles) was fractured with fracturing fluid above the cloud point but without a controlled injection rate. The well in the third data set (squares) was fractured applying the method herein described. Further details of each data set are summarized in the following table:

	First Data Set	Second Data Set	Third Data Set
	(circles)	(triangles)	(squares)
True Vertical Depth	694.9	692	699
(m)
Initial Reservoir	6.2	6.2	6.2
Pressure (MPa)
Injection Pressure	25.4	34.1	26
(MPa)
Injection Rate	2.5	2.5	1.5
(m3/min)
Controlled Injection	No	No	Yes
Rate
Fluid Heated Above	No	Yes	Yes
Cloud Point
Proppant Sieve Size	16/30	16/30	16/30
Clay Stabilizer	Industry	Industry	7% KCl
	Quaternary	Quaternary
	Ammonium	Ammonium
	Salt	Salt
Wax Crystal	No	No	Industry
Modifier			wax crystal
			modifier
Fines Migration	No	No	Industry fines
Inhibitor			migration
			inhibitor

Heating the fracturing fluid to provide a downhole temperature above the cloud point, but without the controlled injection rate, resulted in an improvement in well performance as compared to injecting fracturing fluid at ambient temperature without the controlled injection rate. Heating the fracturing fluid and applying a controlled injection rate resulted in further improvement of well performance as compared to heating the fracturing fluid to provide a downhole temperature above the cloud point, but without applying the controlled injection rate.

Examples Only

In the preceding description, for purposes of explanation, numerous details are set forth in order to provide a thorough understanding of the embodiments. However, it will be apparent to one skilled in the art that these specific details are not required.

The above-described embodiments are intended to be examples only. Alterations, modifications and variations can be effected to the particular embodiments by those of skill in the art without departing from the scope, which is defined solely by the claims appended hereto.

Claims

1. A method for hydraulically fracturing a subterranean reservoir comprising:

providing a fracturing fluid comprising a clay stabilizer, the fracturing fluid at an uphole temperature for providing a downhole temperature in the reservoir greater than a cloud point of hydrocarbons in the reservoir;

injecting the fracturing fluid into the reservoir at a controlled injection rate to propagate a fracture in the reservoir and mitigate vertical height growth of the fracture;

introducing a proppant into the fracturing fluid to provide a fracturing slurry; and

injecting the fracturing slurry into the reservoir at the controlled injection rate to prop the fracture.

2. The method of claim 1 further comprising selecting a reservoir with a pressure of between about 2 MPa and about 10 MPa.

3. The method of claim 2 further comprising selecting a reservoir with a pressure of about 7 MPa.

4. The method of claim 1 further comprising selecting a reservoir with a true vertical depth of between about 500 m and about 1,200 m.

5. The method of claim 4 further comprising selecting a reservoir with a true vertical depth of about 800 m.

6. The method of claim 1 wherein the uphole temperature is about double the cloud point (in ° C.).

7. The method of claim 1 wherein the uphole temperature is between about 50° C. and about 70° C.

8. The method of claim 7 wherein the uphole temperature is about 60° C.

9. The method of claim 1 wherein the controlled injection rate is selected with reference to a previous injection rate which resulted in a bottomhole net pressure drop attributable to vertical height growth.

10. The method of claim 9 wherein the controlled injection rate is decreased relative to the previous injection rate.

11. The method of claim 10 wherein the controlled injection rate is decreased iteratively to a value where no bottomhole net pressure drop attributable to vertical height growth is observed.

12. The method of claim 11 wherein the controlled injection rate is decreased iteratively by steps of about 0.2 m3/min.

13. The method of claim 1 wherein the controlled injection rate is selected with reference to a previous injection rate which resulted in no pressure drop attributable to vertical height growth.

14. The method of claim 1 wherein the controlled injection rate is between about 0.5 m3/min and about 2.5 m3/min.

15. The method of claim 14 wherein the controlled injection rate is about 1.5 m3/min.

16. The method of claim 1 further comprising shutting in the reservoir for a period of time to allow the fracture to heal.

17. The method of claim 16 wherein the period of time ends when a downhole pressure of about the downhole pressure prior to fracturing is observed.

18. The method of claim 16 wherein the period of time is between about 8 and about 30 hours.

19. The method of claim 18 wherein the period of time is about 20 hours.

20. The method of claim 16 further comprising, following the period of time, producing the fracturing fluid, hydrocarbons, or both, at a reduced production rate to mitigate fines migration.

21. The method of claim 20 wherein the reduced production rate is at a pressure draw down to between about 70% and about 80% of a reservoir pressure following the period of time.

22. The method of claim 20 wherein the reduced production rate is between about 1.0 and about 2.0 m3/h.

23. The method of claim 1 wherein the proppant has a grain size of between about 8/12 mesh and about 30/50 mesh.

24. The method of claim 23 wherein the proppant has a grain size equal to about 16/30 mesh.

25. The method of claim 1 wherein the clay stabilizer is KCl.

26. The method of claim 25 wherein the KCl is at a concentration of between about 3% and about 9% in the fracturing fluid.

27. The method of claim 26 wherein the KCl is at a concentration of about 7% in the fracturing fluid.

28. The method of claim 1 further comprising combining a wax crystal modifier with the fracturing fluid.

29. The method of claim 1 further comprising combining a fines migration inhibitor with the fracturing slurry.

30. A method for hydraulically fracturing a subterranean reservoir having a true vertical depth of between about 500 m and about 1,200 m, and a pressure of between about 2 MPa and about 10 MPa, the method comprising:

providing a fracturing fluid comprising a clay stabilizer, the fracturing fluid being at an uphole temperature for providing a downhole temperature greater than a cloud point of hydrocarbons in the reservoir;

injecting the fracturing fluid into the reservoir at a controlled injection rate of between about 0.5 m3/min and about 2.5 m3/min to propagate a fracture in the reservoir while mitigating vertical height growth of the fracture;

introducing a proppant with a grain size of between about 8/12 mesh and about 30/50 mesh into the fracturing fluid to provide a fracturing slurry;

injecting the fracturing slurry into the reservoir at the controlled injection rate to prop the fracture; and

shutting in the reservoir for between about 8 and about 30 hours to allow the fracture to heal.

31. The method of claim 30 further comprising producing the fracturing fluid, the hydrocarbons, or both, at a reduced drawdown rate of about between about 70% and about 80% of a reservoir pressure following the period of time to mitigate fines migration.

32. The method of claim 30 further comprising producing the fracturing fluid, the hydrocarbons, or both, at a reduced drawdown rate of between about 1.0 and about 2.0 m3/h.