Patent Application
20130014951
The present disclosure relates to applying treatment fluid to a rock matrix in a subterranean formation. Chemical treatments are often applied to subterranean formations by injecting the chemical treatment fluid through a wellbore in the formation. For example, conventional chemical treatments include acid stimulation treatments, scale inhibitor treatments, heat treatments, consolidation treatments, and others. Such chemical treatments are used to enhance resource production from the formation, to strengthen the structure of the formation, or to otherwise condition the formation for various types of activities.
The present disclosure relates to applying treatment fluid to a rock matrix in a subterranean formation. In a general aspect, discontinuities are formed in the rock matrix, and the discontinuities conduct the treatment fluid in the rock matrix.
In one aspect, a method of performing a chemical treatment of a rock matrix includes receiving an injection fluid in a wellbore in a subterranean formation. The subterranean formation includes a rock matrix about the wellbore. Shear bands are induced in the rock matrix by communicating the injection fluid from the wellbore into the rock matrix. A chemical treatment fluid is communicated through the shear bands into the matrix. The injection fluid and the chemical treatment fluid may be the same fluid. The chemical treatment fluid is conducted from the wellbore primarily by a portion of the rock matrix that forms a wall of the wellbore, primarily by a subset of the shear bands that intersect the wall of the wellbore, or primarily by a combination of them. The rock matrix may be exposed to the wellbore either directly as with an open hole exposure to the wellbore or via fluid transmitting penetrations of a (tubular) lining of the wellbore.
Implementations of these and other aspects may include one or more of the following features. A leak-off rate of the injection fluid increases the pore pressure of the rock matrix surrounding the wellbore. Increased pore pressure causes dilatancy, lower effective stress, reduced stress anisotropy, and lower consolidation strength in the rock matrix surrounding the well bore. A leak-off rate of the injection fluid in the rock matrix prevents initiation of a dominant fracture at the wellbore wall. The injection fluid is the chemical treatment fluid. Or, the injection fluid and the chemical treatment fluid may be two different fluids. The chemical treatment fluid is received in the wellbore and communicated through the shear bands after the injection fluid is communicated into the rock matrix. The shear bands are induced substantially uniformly in the rock matrix about a longitudinal section of the wellbore. The rock matrix includes a soft rock formation having a Young's Modulus less than two million. The chemical treatment includes an acid stimulation treatment, a solvent treatment, a formation stabilizing treatment, a consolidation treatment, or a scale inhibitor treatment.
In one aspect, a chemical treatment method for treating a rock matrix about a subterranean wellbore includes communicating a first fluid from the wellbore into an interval of the rock matrix about the wellbore. The first fluid is communicated into the interval under a condition that forms shear bands in the interval. A chemical treatment fluid is communicated uniformly into the interval. The chemical treatment fluid is conducted from the wellbore primarily by a portion of the rock matrix that forms a wall of the wellbore, primarily by a subset of the shear bands that intersect the wall of the wellbore, or primarily by a combination of them.
Implementations of these and other aspects may include one or more of the following features. The condition that forms shear bands in the interval can be a pressure condition, an injection rate condition, or both. The chemical treatment fluid is communicated to the wall of the wellbore by perforations through a wellbore liner. Inducing the shear bands in the rock matrix effectively increases the bulk permeability of the rock matrix near the wellbore. The first fluid is a thin injection fluid that contains substantially no solids and forms substantially no filter cakes. The interval is a first interval. A proppant-laden fluid may be injected into the first interval. A diverter material may be used to limit injection into the first interval. The first fluid is communicated into a second, different interval of the rock matrix at a pressure and rate that forms shear bands in the second interval. The chemical treatment fluid is conducted into the second interval through the shear bands in the second interval.
In one aspect, a chemical treatment system for applying a chemical treatment to a rock matrix includes a conduit system in a wellbore. The chemical treatment system includes a fluid supply system in communication with the conduit system. The fluid supply system includes a thin injection fluid and a chemical treatment fluid. The chemical treatment system includes a port system in fluid communication with the conduit system. The port system is operable to receive the injection fluid and the chemical treatment fluid from the conduit system. The port system is operable to communicate the injection fluid into the rock matrix at an injection pressure and rate that induces shear bands in the rock matrix about the wellbore. The port system is operable to communicate the chemical treatment fluid into the rock matrix primarily through a portion of the rock matrix that forms a wall of the wellbore, primarily through a subset of the shear bands that intersect the wall of the wellbore, or primarily through a combination of them.
Implementations of these and other aspects may include one or more of the following features. The fluid supply system resides at a well system surface. The fluid supply system includes a single fluid composition that includes both the injection fluid and the chemical treatment fluid. The fluid supply system includes a first fluid composition that is the thin injection fluid, and the fluid supply system includes a second, different fluid composition that is the chemical treatment fluid. The conduit system includes an injection tubular or a production string, and the port system includes one or more inflow control devices. The conduit system includes a wellbore casing, and the port system includes one or more perforations in the wellbore casing. The chemical treatment fluid is communicated to the wall of the wellbore by perforations through a wellbore liner.
The details of one or more implementations of the subject matter described in this specification are set forth in the accompanying drawings and the description below. Other features, aspects, and advantages of the subject matter will become apparent from the description, the drawings, and the claims.
Like reference symbols in the various drawings indicate like elements.
The subterranean formation 101 includes the rock matrix 106 about the wellbore 103. In some implementations, a chemical treatment is applied substantially uniformly to the rock matrix 106. For example, the chemical treatment can be applied by injecting a treatment fluid into the rock matrix 106 through the wellbore 103. The treatment fluid can be injected into a soft rock formation about the wellbore 103 to uniformly permeate an interval of the formation and form shear discontinuities in the rock. The treatment fluid can be a thin, low viscosity fluid that has a high leak-off rate in the rock. The treatment fluid can be injected at or above a fracture pressure and rate or rock matrix parting pressure and rate so as to induce shear bands without forming a dominant fracture (e.g., a bi-wing fracture) at the wellbore wall. The shear bands can conduct the chemical treatment fluid from the wellbore into the rock matrix, and in some cases, thereby achieve more uniform placement of the chemical treatment fluid in the rock matrix.
The formation can include a soft, highly plastic rock that does not have a dominant stress contrast at the wellbore. The mechanical properties of the rock along with the fluid properties of the chemical treatment fluid may induce shear bands in the rock formation about the wellbore without initiating or propagating a dominant fracture at the wellbore wall on injection of the treatment. As such, the injection can from a complex network of interconnected shear bands in the rock matrix, which may act as a conduit for communicating treatment fluids uniformly throughout the rock matrix adjacent to the wellbore. For example, by creating shear bands in the rock matrix, the chemical treatment can, in some cases, more uniformly permeate the near wellbore rock matrix.
In some instances, fluids containing adjunct materials (e.g., sand, gravel, proppant material, diverter material, permeability modifier, etc.) may also be injected, for example, in addition to the thin injection fluid that forms the shear bands. The particulate or diverter materials can be placed, for example, at an interface between the wellbore and the rock matrix to modify the flow path of the treatment fluid. Such diverter material can be used to enhance the uniform placement of the treatment fluid, for example, in other intervals of the rock formation.
The wellbore 103 shown in
The pump trucks 114 may include mobile vehicles, immobile installations, skids, hoses, tubes, fluid tanks or reservoirs, pumps, valves, and/or other suitable structures and equipment. The pump trucks 114 supply treatment fluid 108 from a fluid supply 118. The pump trucks can communicate with the control trucks 112, for example, by a communication link 113. The fluid supply system can include a tank, reservoir, connections to external fluid supplies, and/or other suitable structures and equipment. The pump trucks 114 are coupled to the work string 104 to communicate the treatment fluid 108 into the wellbore 103.
The working string 104 may include coiled tubing, sectioned pipe, and/or other structures that communicate fluid through the wellbore 103. The working string 104 can include flow control devices, bypass valves, ports, and or other tools or well devices that control a flow of fluid from the interior of the working string 104 into the rock matrix 106. For example, the working string 104 may include ports that abut the wellbore wall to communicate the treatment fluid 108 directly into the rock matrix 106, and/or the working string 104 may include ports that are spaced apart from the wellbore wall to communicate the treatment fluid 108 into an annulus in the wellbore between the working string 104 and the wellbore wall. Although
The control trucks 112 can include mobile vehicles, immobile installations, and/or other suitable structures. The control trucks 112 control and/or monitor the injection treatment. For example, the control trucks 112 may include communication links that allows the control trucks 112 to communicate with tools, sensors, and/or other devices installed in the wellbore 103. The control trucks 112 may include communication links that allow the control trucks 112 to communicate with the pump trucks 114 and/or other systems at the surface 102. The control trucks 112 may include an injection control system that controls the flow of the treatment fluid 108 into the rock matrix 106. For example, the control trucks 112 may monitor and/or control the density, volume, flow rate, flow pressure, location, and/or other properties of the treatment fluid 108 injected into the rock matrix 106.
The injection system 110 may also include surface and down-hole sensors (not shown) to measure pressure, rate, temperature and/or other parameters of treatment. The injection system 110 may include pump controls and/or other types of controls for starting, stopping and/or otherwise controlling pumping as well as controls for selecting and/or otherwise controlling fluids pumped during the injection treatment. An injection control system (e.g. in the control trucks 112) may communicate with such equipment to monitor and control the injection treatment.
Applying the chemical treatment includes injecting the chemical treatment fluid 108 into the rock matrix 106 to treat the rock matrix 106. In some cases, it is desirable to treat the rock matrix uniformly around (e.g., 360 degrees) the wellbore and uniformly along longitudinal section of the wellbore. In some implementations of the well system 100, a chemical treatment is applied more uniformly by injecting the chemical treatment fluid 108 at a pressure that forms shear bands in the rock matrix and by using the shear bands to conduct the fluid into the rock matrix. For example, the shear bands may be formed by injecting the chemical treatment fluid above a fracture pressure and by using a low efficiency fluid that does not open a dominant fracture at the wellbore wall.
Example chemical treatments include acid stimulation treatments, formation stabilization treatments, consolidation treatments, scale inhibitor treatments, treatments that remove buildup of paraffin, asphaltene, or another substance from the rock material, heat transfer treatments, water flood treatments, and others. Acid stimulation treatments apply an acidic fluid to a rock formation to improve the production or injection flow capacity, for example, by dissolving material plugging the pores or by enlarging the pore spaces. Formation stabilization treatments apply treatment fluid to a subterranean zone to reduce movement of the matrix formation grains and fine particles during operation of the well including production or injection operations. Consolidation treatments apply treatment fluid to a subterranean zone to control production of sand and other undesirable substances from the zone. For example, a consolidation treatment can be applied to a weak sandstone formation to chemically bind the grains of sand while maintaining sufficient permeability to achieve viable production rates. Scale inhibitor treatments apply treatment fluid to control or prevent scale deposition in the production conduit or completion system. Heat transfer treatments apply heated fluids to a subterranean zone to affect material properties of the zone, for example, to achieve a desired flow rate. Waterflood treatments inject fluids to act as a secondary recovery treatment, for example, to displace residual hydrocarbons.
In one aspect of operation, the injection system 110 applies a chemical treatment to the rock matrix 106. The control truck 112 controls and monitors the pump truck 114 which pumps the treatment fluid 108 from the fluid supply system 118 through the work string 104, into the wellbore 103, and subsequently into the rock matrix 106. The treatment fluid 108 can be injected at a pressure that induces shear bands in the rock matrix 106. The treatment fluid 108 can be injected in a manner that prevents a dominant fracture from forming at the interior wall of the wellbore 103. For example, the treatment fluid 108 can have a sufficiently high leak-off rate in the rock matrix 106 to prevent formation of a dominant fracture. As such, the shear bands formed by the treatment fluid 108 conduct the injection fluid into the rock matrix 106. In some cases, a portion of rock matrix 106 that forms the interior wall of the wellbore acts as the primary fluid conductor that communicates fluid from the interior of the wellbore into the rock matrix 106. In some cases, shear bands formed by the treatment fluid 108 intersect the interior wall of the wellbore, and the shear bands intersecting the interior wall act as the primary fluid conductor that communicates fluid from the interior of the wellbore into the rock matrix 106. In some cases, both the shear bands and the rock matrix at the wellbore wall act as the primary conductor.
In some instances, the shear bands 203 are induced by plastic deformation of the rock matrix 202a under the pressure of the thin injection fluid. For example, the deformation can be caused by material instability in the rock matrix corresponding to increase in pore pressure surrounding the wellbore. In some instances, the shear bands 203 are formed due to shear loading applied to the rock matrix 202a by a thin fluid that has a significant leak-off rate and low viscosity in the rock matrix 202a, in combination with the subterranean formation that restrains the rock matrix 202a. As a result of the shear bands 203 that have been formed in the rock matrix 202a, fluid subsequently injected into the rock matrix 202a through the wellbore 201a in
In some implementations, fluid injection parameters can be controlled to achieve the conditions that cause shear bands 203 to form in the rock matrix 202a. For example, in some cases a sufficiently high injection rate can induce some or all of the shear bands 203. In some cases, treatment adjuncts, additives or formulations can be used to effectively cause an increase in bottom hole treating pressure or change the treatment penetration profile such that the fracture system includes the entire target interval. For example, treatment adjuncts may include sand, gravel, proppant, foam, particulate diverter materials, plugging diverter materials of various forms or shapes, relative permeability modifiers, and/or others. Such adjunct materials can be included with treatment fluids to block fluid entry into and leak-off from existing fracture networks (e.g., in other zones), thus allowing subsequent injection to create new fracture networks and radial penetration of treatment through out the treatment interval.
In some instances, the shear bands 203 are induced by plastic deformation of the rock matrix 202c under the pressure of the thin injection fluid. For example, the deformation can be caused by material instability in the rock matrix corresponding to increase in pore pressure surrounding the wellbore. In some instances, the shear bands 203 are formed due to shear loading applied to the rock matrix 202c by a thin fluid that has a significant leak-off rate and low viscosity in the rock matrix 202c, in combination with the subterranean formation that restrains the rock matrix 202c. In some instances, the induced shear bands may initially form a radial fracture pattern from the wellbore 201c. In some instances, the induced shear bands may initially form a different type of fracture pattern. As a result of the shear bands 203 that have been formed in the rock matrix 202c, fluid subsequently injected into the rock matrix 202c through the wellbore 201c in
As shown in
The injection fluid 308 can have the mechanical properties of a Newtonian fluid, for example, a fluid whose stress at any point is linearly proportional to its strain rate at that point, where the constant of proportionality is the viscosity of the fluid. The injection fluid 308 can be a thin fluid, for example, that contains substantially no solids and does not form filter cakes in the wellbore. The injection fluid 308 can be an incompressible fluid, a multiphase fluid, and/or a composition of multiple different types of fluids. The injection fluid 308 can substantially uniformly permeate the rock matrix 106 about the wellbore 103 and create shear discontinuities in the rock matrix 106.
In some implementations of the example system 300, each of the flow control devices 122a, 122b, 122c can be selectively opened, selectively closed, or otherwise reconfigured, for example, by well intervention, by pressure signals or electromagnetic signals propagated from the surface, and/or by another technique. In some implementations, the flow control devices 122a, 122b, 122c can be simultaneously opened or closed. In some instances, the injection fluid 308 is communicated through the flow control devices 122a, 122b and 122c into the rock matrix 106 at a pressure that forms shear bands 330 in the rock matrix. The injection fluid 308 can be communicated simultaneously through two or more of the flow control devices 122a, 122b, 122c, or the injection fluid 308 can be communicated through each of the flow control devices 122a, 122b, 122c at different times. As such, the shear bands 330 can be formed throughout the rock matrix 106 concurrently, over multiple time intervals, or in another manner.
The shear bands 330 can be formed substantially uniformly about the wellbore 103. For example, the shear bands 330 can be distributed through the rock matrix 106 such that the rock matrix 106 does not have substantial spatial variations in permeability that would create preferential flow through certain regions of the rock matrix 106. As such, in some instances, the shear bands 330 permit substantially uniform flow of a chemical treatment fluid from the wellbore 103 into the rock matrix 106 about the wellbore 103. In some instances, the shear bands 330 are uniform over a targeted section of the rock matrix 106. For example, the shear bands may be uniform over a longitudinal section, an azimuthal section, and/or a radial section about the wellbore.
The fluid supply 118 can supply a single fluid or it can supply multiple different fluids. In some implementations, the injection fluid 308 that forms the shear bands 330 is also the chemical treatment fluid. For example, the injection fluid 308 that forms the shear bands 330 can be the treatment fluid for an acid stimulation treatment, a scale inhibitor treatment, a formation stabilization treatment, a consolidation treatment, or another type of chemical treatment fluid. In some implementations, the chemical treatment fluid is a separate fluid that is injected after the injection fluid 308 that forms the shear bands 330. For example, after the injection fluid 308 has been injected to form the shear bands 330, the treatment fluid for an acid stimulation treatment, a scale inhibitor treatment, a formation stabilization treatment, a consolidation treatment, or another type of chemical treatment fluid can be injected.
As shown in
Each of the individual intervals 116a, 116b, 116c can be treated in sequence, or some or all of the intervals 116a, 116b, 116c can be treated simultaneously. In the example process shown by
In some implementations, a more uniform treatment of the rock matrix 106 can be achieved by applying the chemical treatment to individual intervals of the rock matrix 106. For example, to the extent that there are variations in permeability among the intervals 116a, 116b, 116c, the permeability within interval can be substantially uniform. As such, if the one of the intervals has a higher permeability than the other two, preferential treatment of the high permeability interval may be reduced or avoided by isolating the high permeability interval from the others.
The operations shown in
As shown in
As shown in
The treatment process can then continue to the next interval as shown in
At 502, a first interval in a subterranean formation is identified. The subterranean formation can include a soft rock formation having low stiffness, for example, a rock formation that includes rock materials having a Young's Modulus value less than two million. Examples of soft rock formations include shale, coal, and certain types of geologically young formations (e.g., Miocene and Pliocene period formations, and others). In some cases, the material in such rock formations can include brittle rock having low elasticity.
The interval is an interval along a wellbore in the subterranean formation. The interval includes the rock formation around a longitudinal section the wellbore. The longitudinal section can be any suitable length. The longitudinal section may include a section of a vertical, slant, curved, or horizontal wellbore, including a toe, heel, or intermediate section in the horizontal wellbore. The interval may be isolated by seals, packers, or other types of isolators installed in the wellbore.
The interval can be identified for receiving a chemical treatment. The chemical treatment to be applied to the interval can include any type of chemical treatment to be applied uniformly in the interval. Example chemical treatments include acid stimulation treatments, formation stabilization treatments, consolidation treatments, scale inhibitor treatments, treatments that remove buildup of paraffin, asphaltene, or another substance from the rock material, heat transfer treatments, water flood treatments, and others. The chemical treatment can be a radial treatment to be placed radially about the wellbore over a radial depth into the rock formation from the wellbore wall.
At 504, fluid is communicated into the first interval to induce shear bands in the interval. The fluid can be communicated to induce shear bands at any stage of a treatment. For example, shear bands can be induced during a first injection stage, or any subsequent injection stage. The fluid can be part of the chemical treatment and/or the fluid can be injected to prepare the interval to later receive the chemical treatment. As such, the fluid that induces the shear bands can be or can contain the chemical treatment fluid, or the fluid that induces the shear bands can be a separate fluid from the chemical treatment fluid. The fluid can have mechanical properties of a Newtonian fluid, for example, a fluid whose stress at any point is linearly proportional to its strain rate at that point, where the constant of proportionality is the viscosity of the fluid. The fluid can be a thin fluid, for example, that contains substantially no solids and does not form filter cakes in the wellbore. The fluid can be an incompressible fluid, a multiphase fluid, and/or a composition of multiple different types of fluids.
The fluid can be received in the wellbore from a fluid supply system at the surface of the well system, and the fluid can be communicated through the wellbore by a conduit system in the wellbore. For example, the fluid can flow through any type work string, tubing, or casing in the wellbore. The fluid is communicated into the interval from the wellbore at 504, for example, through perforations in the wellbore casing, through a port in a production string (e.g., an inflow control device, a valve, or another type of device), or through another type of port system in the wellbore.
The fluid may be communicated into the rock matrix at 504 at or above a fracture pressure without causing dominant fractures to propagate from the wellbore wall. As such, the fluid can be communicated into the rock matrix without forming conventional bi-wing fractures or similar discontinuities in the rock matrix. For example, by using thin fluids that have a low viscosity and/or a high leak-off rate in the rock matrix, the fluid can be injected above a fracture pressure without initiating or propagating a dominant open fracture at the wellbore wall. Because dominant open fractures are not formed at the wellbore wall, fluid can be conducted from the wellbore primarily by the rock matrix itself (i.e., a portion of the rock matrix that forms a wall of the wellbore) and/or primarily by shear bands in the rock matrix (i.e., shear bands that intersect the wall of the wellbore).
The shear bands are formed in the interval substantially uniformly about the wellbore. For example, the distribution of the induced shear bands can be substantially uniform over a full range of azimuthal directions about the wellbore, over the full longitudinal length of the interval, and/or over a finite depth into the formation from the wellbore wall. The full range of azimuthal directions can be a full 360 degrees about the wellbore, or a smaller range when appropriate. In some instances, the full longitudinal length of the interval is the distance between packers that isolate the interval from a neighboring interval. The finite depth into the formation from the wellbore can be a depth of several centimeters to several meters or more.
The uniformity of the shear bands in the interval results in a higher permeability of the rock matrix that is substantially uniform over the interval. For example, the increased permeability may be substantially uniform over a full range of azimuthal directions about the wellbore, over the full longitudinal length of the interval, and/or over a finite depth into the formation from the wellbore wall. In such cases, the fluid is communicated substantially uniformly into the rock matrix as the fluid is conducted through the shear bands in the interval. Thus, in some implementations, the shear bands improve the uniformity, range, and/or speed of fluid distribution in the interval.
In some implementations of the process 500, the first interval is plugged at 506 after the shear bands are formed in the interval. For example, the first interval may be plugged by communicating a proppant-laden fluid into the first interval. The proppant-laden fluid contains proppant material (i.e., solids) that plug open volumes in the interval. The interval may be plugged in a different manner, for example, by closing a port of a production string (e.g., by reconfiguring an inflow control device, a valve, or another device), by use of a relative permeability modifier, or by plugging perforations in a well casing. Plugging the interval prevents or substantially reduce the rate at which fluid can be communicated into the interval from the wellbore. As such, when subsequent intervals are treated, the plugging material can prevent or reduce the communication of fluids into the first interval (or any intervals that have been plugged).
After the first interval is plugged, a next interval of the subterranean formation is identified at 508. Fluid is then communicated into the next interval to induce shear bands in the next interval (504). The operations 504, 506, and 508 may be iterated for any number of intervals along the wellbore. In some implementations of the process 500, only a single interval is used. For example, the first interval may be the entire target region for the chemical treatment, or the first interval may be the only interval available. As such, in some implementations no additional intervals are identified and/or the first interval is not plugged.
At 510, additional fluid may be communicated into the first interval and/or into one or more other intervals in the subterranean formation. The additional fluid applied at 510 may be the same or a different fluid than was used to induce the shear bands at 504. The additional fluid communicated into the interval(s) at 510 can be part of a different chemical treatment than the fluid that was used to induce the shear bands at 504. The additional fluid communicated into the interval(s) at 510 can be part of the same chemical treatment that was applied at 504. Due to the presence of the shear bands, the additional fluid is communicated substantially uniformly into the rock matrix within each interval as the fluid is conducted through the shear bands in the interval(s). Thus, in some implementations, the shear bands improve the uniformity, range, and/or speed of distribution of the additional fluid in the interval. The additional fluid can be conducted from the wellbore primarily by the rock matrix itself and/or primarily by shear bands in the rock matrix intersecting the wall of the wellbore.
In some implementations of the process 500, the additional fluid is communicated into the first interval prior to inducing shear bands in any other interval. For example, after inducing the shear bands in the first interval at 504 and communicating additional fluid into the first interval at 510, the first interval may be plugged at 506, the next interval may be identified at 508, and one or more of the operations (504, 510, 506, 508) may be iterated for subsequent intervals.
In some implementations of the process 500, the additional fluid is communicated into the first interval after inducing the shear bands in the other intervals. For example, after inducing shear bands in multiple intervals, any intervals that have been plugged can be unplugged to allow communication of the additional fluid into the intervals. An interval may be unplugged, for example, by dissolving or otherwise removing the proppant or other diverter materials that were used to plug the interval. An interval may be unplugged by opening a port of a production string (e.g., by reconfiguring an inflow control device, a valve, or another device) or by dissolving or otherwise removing a plug from perforations in a well casing. As such, the additional fluid may be communicated into multiple different intervals simultaneously, sequentially, or in a different manner.
A number of embodiments have been described. Nevertheless, it will be understood that various modifications may be made without departing from the spirit and scope of the invention. Accordingly, other embodiments are within the scope of the following claims.
